Related Party Transactions	12 Months Ended
Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 20 — RELATED PARTY TRANSACTIONS On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM. The Gas Gathering and Processing Agreement was subsequently amended in February 2017, effective December 2016 and again in June 2018, effective April 2018. The more recent amendment to the Gas Gathering and Processing Agreement impacts our ability to make elections with respect to the NGL portion of our production volumes but has no other effect on our consolidated financial statements. In November 2018, we sold our produced water assets, consisting of over 200 miles of produced water gathering pipelines and related facilities, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher, a related party and an entity under common control by our parent, AMR, for $98.0 million, including approximately $90.0 million in cash transferred during 2018. The remaining balance owed of approximately $8.0 million is included in related party receivables. In conjunction with the sale, we entered into a new fifteen-year produced water disposal agreement with KFM. Under that agreement, we recognized expense of $4.7 million during November and December of 2018. On September 21, 2016, we entered into an agreement with Kingfisher that beginning January 1, 2017 through January 31, 2022, we shall reimburse Kingfisher for 50% of any shortfall fee paid by Kingfisher to Superior Pipeline Company, LLC, a third party gas processor. During the period February 9, 2018 through December 31, 2018, cash payments required under our commitments totaled approximately $0.1 million. David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David -Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $166,000, $28,000, $186,000 and $146,000 for the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, respectively. Following termination of the contract, Brigid Murrell continued to provide services to the Company as an individual contractor and was paid $8,523 for services rendered in that capacity through December 31, 2018. These amounts are recorded in general and administrative expenses. David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of approximately $1,157,774, $28,874, $250,000, and $425,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively. These amounts are included in general and administrative expense. David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of approximately $297,134, $67,322, $150,000, and $180,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively. These amounts are included in general and administrative expense. Bayou City Agreement In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of Alta Mesa’s drilling operations and to allow Alta Mesa to accelerate development of our STACK acreage. The JDA establishes a development plan of 60 wells in three tranches, and provides opportunities for the parties to potentially agree to an additional 20 wells. Pursuant to the terms and provisions of the JDA, BCE committed to fund 100% of Alta Mesa’s working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for carrying the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return on each individual tranche. Following the completion of each joint well, Alta Mesa and BCE will each bear its respective proportionate working interest share of all subsequent costs and expenses related to such joint well. Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of December 31, 2018, 61 joint wells have been drilled or spudded. As of December 31, 2018 and 2017, $9.8 million and $23.4 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our consolidated balance sheets. At December 31, 2018, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. High Mesa In September 2017, we entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured in February 2019. At December 31, 2018 and 2017, amounts due under the promissory note totaled $1.7 million and $1.5 million, respectively. HMS defaulted under the terms of that promissory note when it was not paid when due on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owing under the note immediately due and payable. We also have an $8.5 million promissory note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. As of December 31, 2018 and 2017, the note receivable amounted to $11.7 million and $10.8 million, respectively. HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to us. We oppose HMI’s claims and believe HMI’s obligation under the notes to be our valid assets and that the full amount is payable to us. We intend to pursue all available remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. As a result of the potential conflict of interest of certain directors of AMR who are also controlling holders and directors of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2018, we established an allowance for doubtful accounts for the promissory notes totaling $13.4 million, the expense for which is included in general and administrative expense in 2018. Interest income on the promissory notes amounted to approximately $0.9 million, $0.1 million, $0.9 million, and $0.8 million for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively, all recorded as paid-in-kind and added to the balance due thereunder. In connection with the Business Combination, we distributed our non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Under the High Mesa Agreement, during the 180-day period following the Closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000, (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services. Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the High Mesa Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services from Alta Mesa to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the High Mesa Agreement, and pursuant to the High Mesa Agreement as “Receivables due from related party” in the balance sheets. As of December 31, 2018 (Successor) and December 31, 2017 (Predecessor), we had receivables of approximately $10 million and $0.8 million for costs and expenses incurred on HMI’s behalf. Subsequent to year-end, we billed HMI $0.9 million for incremental MSA costs incurred and have received approximately $1.0 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result, we have recognized an allowance for uncollectible accounts of $9.0 million to fully provide for the unremitted balance and may have future allowances for amounts incurred in 2019 prior to the termination of the MSA. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities.

NOTE 20 — RELATED PARTY TRANSACTIONS

On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM. The Gas Gathering and Processing Agreement was subsequently amended in February 2017, effective December 2016 and again in June 2018, effective April 2018. The more recent amendment to the Gas Gathering and Processing Agreement impacts our ability to make elections with respect to the NGL portion of our production volumes but has no other effect on our consolidated financial statements.

In November 2018, we sold our produced water assets, consisting of over 200 miles of produced water gathering pipelines and related facilities, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher, a related party and an entity under common control by our parent, AMR, for $98.0 million, including approximately $90.0 million in cash transferred during 2018. The remaining balance owed of approximately $8.0 million is included in related party receivables. In conjunction with the sale, we entered into a new fifteen-year produced water disposal agreement with KFM. Under that agreement, we recognized expense of $4.7 million during November and December of 2018.

On September 21, 2016, we entered into an agreement with Kingfisher that beginning January 1, 2017 through January 31, 2022, we shall reimburse Kingfisher for 50% of any shortfall fee paid by Kingfisher to Superior Pipeline Company, LLC, a third party gas processor. During the period February 9, 2018 through December 31, 2018, cash payments required under our commitments totaled approximately $0.1 million.

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David -Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $166,000, $28,000, $186,000 and $146,000 for the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, respectively. Following termination of the contract, Brigid Murrell continued to provide services to the Company as an individual contractor and was paid $8,523 for services rendered in that capacity through December 31, 2018. These amounts are recorded in general and administrative expenses.

David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of approximately $1,157,774, $28,874, $250,000, and $425,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively. These amounts are included in general and administrative expense.

David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of approximately $297,134, $67,322, $150,000, and $180,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively. These amounts are included in general and administrative expense.

Bayou City Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of Alta Mesa’s drilling operations and to allow Alta Mesa to accelerate development of our STACK acreage. The JDA establishes a development plan of 60 wells in three tranches, and provides opportunities for the parties to potentially agree to an additional 20 wells. Pursuant to the terms and provisions of the JDA, BCE committed to fund 100% of Alta Mesa’s working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for carrying the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return on each individual tranche. Following the completion of each joint well, Alta Mesa and BCE will each bear its respective proportionate working interest share of all subsequent costs and expenses related to such joint well. Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of December 31, 2018, 61 joint wells have been drilled or spudded. As of December 31, 2018 and 2017, $9.8 million and $23.4 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our consolidated balance sheets. At December 31, 2018, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA.

High Mesa

In September 2017, we entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured in February 2019. At December 31, 2018 and 2017, amounts due under the promissory note totaled $1.7 million and $1.5 million, respectively. HMS defaulted under the terms of that promissory note when it was not paid when due on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owing under the note immediately due and payable. We also have an $8.5 million promissory note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. As of December 31, 2018 and 2017, the note receivable amounted to $11.7 million and $10.8 million, respectively. HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to us. We oppose HMI’s claims and believe HMI’s obligation under the notes to be our valid assets and that the full amount is payable to us. We intend to pursue all available remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. As a result of the potential conflict of interest of certain directors of AMR who are also controlling holders and directors of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2018, we established an allowance for doubtful accounts for the promissory notes totaling $13.4 million, the expense for which is included in general and administrative expense in 2018.

Interest income on the promissory notes amounted to approximately $0.9 million, $0.1 million, $0.9 million, and $0.8 million for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively, all recorded as paid-in-kind and added to the balance due thereunder.

In connection with the Business Combination, we distributed our non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Under the High Mesa Agreement, during the 180-day period following the Closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000, (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the High Mesa Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services from Alta Mesa to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the High Mesa Agreement, and pursuant to the High Mesa Agreement as “Receivables due from related party” in the balance sheets. As of December 31, 2018 (Successor) and December 31, 2017 (Predecessor), we had receivables of approximately $10 million and $0.8 million for costs and expenses incurred on HMI’s behalf. Subsequent to year-end, we billed HMI $0.9 million for incremental MSA costs incurred and have received approximately $1.0 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result, we have recognized an allowance for uncollectible accounts of $9.0 million to fully provide for the unremitted balance and may have future allowances for amounts incurred in 2019 prior to the termination of the MSA. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities.