Alta Mesa Holdings, LP filed on Friday, May 17 10-K

Alta Mesa Holdings, LP revealed 10-K form on May 17.

PDP -Proved developed producing reserves.2018 Predecessor PeriodThe period from January 1, 2018 through February 8, 2018Predecessor PeriodsThe years ended December 31, 2017, 2016, 2015 and 2014Productive well -A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.Proved developed reserves -Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and can be expected to be recovered through extraction technology installed and operational at the time of the reserve estimate.Proved properties -Properties with proved reserves.Proved reserves -Quantities of oil and natural gas, which can be estimated with reasonable certainty to be economically producible from known reservoirs, and under existing economic conditions, operating methods and government regulations.Proved undeveloped reserves (“PUD”) -Reserves that are expected to be recovered from new wells, or from existing wellbores where a relatively major expenditure is required to make the well producible.PV-10 -When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (‘GAAP’) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenue. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Our PV-10 is the same as our standardized measure for the periods presented in this report.Realized price -The cash market price less all expected quality, transportation and demand adjustments.Recompletion -The process of treating an existing wellbore in an attempt to establish or increase existing production.Reserves -Estimated remaining quantities of oil and natural gas anticipated to be economically producible from known accumulations.Reservoir -A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.Resources -Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable.Royalty -An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage.SEC – United States Securities and Exchange Commission.Service well -A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, produced water disposal, water supply for injection, observation, or injection for in-situ combustion.Spacing -The distance between wells producing from the same reservoir. Spacing in horizontal development plays is often expressed in terms of feet, e.g., 1000 foot spacing, and is often established by regulatory agencies.STACK -An oilfield in the eastern portion of the Anadarko Basin; STACK is an acronym describing both its location-Sooner Trend Anadarko Basin Canadian and Kingfisher County-and the multiple, stacked productive formations present in the area.

When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (‘GAAP’) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenue. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Our PV-10 is the same as our standardized measure for the periods presented in this report.

Standardized Measure -Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the U.S. Securities and Exchange Commission, without giving effect to non-property related expenses such as certain general and administrative expenses, interest expense and depletion, discounted using an annual discount rate of 10%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes. Our standardized measure is the same as our PV-10 for the periods presented in this report.Stratigraphic test well -A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as ‘exploratory type’ if not drilled in a known area or ‘development type’ if drilled in a known area.Success rate -The percentage of wells drilled which produce hydrocarbons in commercial quantities.Successor Period – The period from February 9, 2018 through December 31, 2018Undeveloped acreage -Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.Unit -The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation. Also, the area covered by a unitization agreement.Unproved properties -Properties with no proved reserves.VWAP -Volume weighted average priceWaterflood -The injection of water into an oil reservoir to ‘sweep’ additional oil out of the reservoir rock and into the wellbores of producing wells. Typically, an enhanced recovery process.Working interest -The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs.Workover -Operations on a producing well to restore or increase production.

Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the U.S. Securities and Exchange Commission, without giving effect to non-property related expenses such as certain general and administrative expenses, interest expense and depletion, discounted using an annual discount rate of 10%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes. Our standardized measure is the same as our PV-10 for the periods presented in this report.

We sell our production to customers generally at prevailing spot prices in effect at the time of the sale. Collateral or other security is generally not required with regard to our trade receivables. Much of our oil and gas production is sold through a marketing agreement with ARM Energy Management, LLC (‘ARM’), who markets and sells our oil and gas production under short-term contracts, generally with month-to-month pricing based on published indices, adjusted for transportation, location and quality. ARM remits monthly collections of these sales to us, net of its fee. For the Successor Period, ARM marketed $309.7 million, or 75% of our total operating revenue for the period. We sell our NGL production under various contracts with processors in the vicinity of the production at spot market rates, after processing costs. Other than our marketing agreement with ARM, no other customers accounted for more than 10% of our consolidated sales for the Successor Period. We do not believe the loss of any specific customer, or of our marketing agent ARM, would have a material adverse effect on us because alternative purchasers are available.

The gross production tax, or severance tax, is a value-based tax levied at a basic rate of 7% upon the production of oil and gas in Oklahoma. As an economic incentive to develop its resources, Oklahoma has historically offered a ‘tax holiday’ with rates ranging from 1% for 48 months to 2% for 36 months for production from horizontal wells. Through June 2018, Oklahoma imposed a tax of 2% of gross production for the first 36 months of production and then at 7% thereafter on wells drilled after July 1, 2015. Effective July 2018, the 2% tax rate was increased to 5% for wells drilled after July 1, 2015 that were still within their first 36 months of production. For the period beyond 36 months, the tax rate remains at 7% for the remaining productive life of each well. All wells drilled after July 1, 2018 are taxed at 5% of gross production for the first 36 months of production and then at 7% thereafter. In addition, a longstanding excise tax of 0.095% continues to be levied.

In general, the volume of production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. For example, we estimate that our wells experience approximately a 40% first year decline in production. Thus, absent successful development of our assets or acquisition of properties that have existing proved developed reserves, our revenue could decline as reserves are produced. Our future oil and gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Our reduced drilling program for 2019 could negatively affect our ability to replace reserves and maintain our current production levels, which could have a material adverse effect on us.  Additionally, to the extent our operating cash flow falls below projections and external sources of capital become limited or unavailable, our ability to conduct the capital investment to maintain or expand our asset base would be impaired.

The timing of both our production and our incurrence of expenses in connection with our operations will affect the timing and amount of actual future net revenue and thus our oil and gas properties’ actual present value. In addition, the 10% discount factor we use in the standardized measure may not be the most appropriate discount factor to utilize in determining the fair value of our oil and gas properties. For example, although the standardized measure applies a 10% discount factor to both PDP and PUD reserves alike, in property sales transactions the fair value of PDP has historically been determined using a lower discount rate and the fair value of PUD reserves has typically been determined using a higher discount rate. Actual future prices and costs may differ materially from those used in the present value estimate.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and gas, we regularly enter into derivatives (‘hedges’) covering a significant portion of our expected production. The Alta Mesa RBL requires us to hedge at least 50% of anticipated equivalent production of our PDP reserves for the upcoming twenty-four month period at each measurement date, but also imposes maximum hedging levels for each production stream. Details of our derivative assets are included in Item 8. If we experience a sustained material interruption in our production, we might be forced to make payments under our hedging program without the benefit of the proceeds from our sale of the underlying production, which would have a material adverse effect on us. Further, risk exists that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge, although all of the counterparties to our current portfolio are lenders under the Alta Mesa RBL. Under that agreement, if a counterparty is a lender and does not perform, then the non-performance is treated as a reduction to the borrowings outstanding. Furthermore, given our current financial condition, our counterparties have ceased providing the credit necessary to enter into new hedges. Therefore, we may be more exposed to future price fluctuations. We may also be unable to comply with the minimum hedging requirements under the Alta Mesa RBL.

At December 31, 2018, we had a 66% average working interest in 786 gross producing wells. At December 31, 2018, we had six horizontal drilling rigs operating in the STACK, but by late February 2019, we had no rigs operating. We restarted our development program in March 2019 and expect to use 2-3 rigs for the remainder of 2019 as we focus on the optimal completion design, well pattern and lowering well costs.

Under the JDA, up to 100% of our well costs could be funded up to a specified total well cost. We are responsible for any drilling and completion costs exceeding approved amounts. In exchange for BCE carrying the drilling and completion costs, they receive 80% of our working interest in each funded well until attaining a 15% internal rate of return for the entire tranche, at which time their interest reduces to 20%. If a tranche attains a 25% internal rate of return, their interest reduces to 12.5%.

Ryder Scott Company, LP (‘Ryder Scott’), a third-party petroleum engineering consulting firm, audited approximately 96% of our 2018 proved reserves on a 6:1 Mcf per Bbl conversion basis. Their report is filed with this Annual Report as Exhibit 99.1. The reserve audit by Ryder Scott conformed to the meaning of ‘reserves audit’ as presented in the SEC’s Regulation S-K, Item 1202. The qualifications of the technical person at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.

As of May 17, 2019, SRII Opco LP and AMH GP held 100% of such interests.

Production taxes for the Successor Period and 2018 Predecessor Period are higher as compared to 2017 primarily due to the increase in oil and natural gas liquids revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018, for wells in their first 3 years of production.  Production taxes are assessed based on revenues on a pre-hedge basis.

The Alta Mesa RBL bears interest at LIBOR plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 1.50% to 2.50%. There is also a commitment fee that ranges between 0.375% and 0.50% on the undrawn borrowing base amounts. The RBL may be prepaid without a premium. Interest on outstanding facility debt was LIBOR+2.00% at December 31, 2018.

Alta Mesa has $500.0 million in aggregate principal amount of 7.875% senior unsecured notes (the ‘2024 Notes’) that were issued at par by Alta Mesa and its wholly owned subsidiary Alta Mesa Finance Services Corp. during the fourth quarter of 2016.  The 2024 Notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017.

On September 29, 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 on February 28, 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.

(1)Interest on the outstanding balance under the Alta Mesa RBL is payable quarterly; and for the 2024 Notes is payable semiannually. The weighted average rates on our outstanding borrowings as of December 31, 2018 of 6.75% was utilized to calculate the projected interest for our Alta Mesa RBL.  Projected obligation amounts are based on the payment schedules for interest, and are not presented on an accrual basis.

Interest on the outstanding balance under the Alta Mesa RBL is payable quarterly; and for the 2024 Notes is payable semiannually. The weighted average rates on our outstanding borrowings as of December 31, 2018 of 6.75% was utilized to calculate the projected interest for our Alta Mesa RBL.  Projected obligation amounts are based on the payment schedules for interest, and are not presented on an accrual basis.

The fair value of our oil and gas derivatives and basis swaps at December 31, 2018 was a net asset of $17.5 million. A 10% increase or decrease in oil and gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and gas commodity contracts of approximately $14.9 million (decrease in value) or $14.2 million (increase in value), respectively, as of December 31, 2018.

Much of our oil and gas production is sold through a marketing agreement with ARM, who markets and sells our oil and gas production under short-term contracts, generally with month-to-month pricing based on published indices, adjusted for transportation, location and quality. ARM remits monthly collections of these sales to us, net of its fee. For the Successor Period, ARM marketed $309.7 million, or 75% of our total operating revenue for the period. We are significantly exposed to ARM’s credit quality but have experienced no and anticipate no losses with it.

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivatives. A 1% increase in interest rates would increase interest expense on the Alta Mesa RBL by approximately $1.6 million, based on the balance outstanding at December 31, 2018.

Pursuant to the Contribution Agreements, SRII Opco, LP, a newly formed subsidiary of AMR (‘SRII Opco’) acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP ((i) and (ii) collectively, the ‘AM Contribution’) and (b) 100% of the economic interests in KFM (the ‘KFM Contribution’). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the ‘Business Combination’ and the transactions contemplated by the Contribution Agreements are referred to herein as the ‘Transactions’. We are deemed to be a variable interest entity (‘VIE’) and SRII Opco is our primary beneficiary since it controls our general partner, AMH GP, and has the power to direct our activities impacting our performance, as well as holding all of our equity at risk. Accordingly, our results of operations have been consolidated into SRII Opco. Similarly, AMR is the primary beneficiary of SRII Opco and controls SRII Opco, GP, LLC (‘SRII Opco GP’), the general partner of SRII Opco. As a result, AMR controls and consolidates SRII Opco, and by extension, us.

(2)The purchase price consideration was for 100% of the limited partner interests in us and 100% of the economic interests and 90% of the voting interests in AMH GP.

The purchase price consideration was for 100% of the limited partner interests in us and 100% of the economic interests and 90% of the voting interests in AMH GP.

(4)Represents the approximate fair value as of the acquisition date of (i) Alta Mesa’s $500.0 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million, based on Level 1 inputs, and (ii) outstanding borrowings under the Alta Mesa Predecessor Credit Facility of approximately $134.1 million as of the acquisition date.

Represents the approximate fair value as of the acquisition date of (i) Alta Mesa’s $500.0 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million, based on Level 1 inputs, and (ii) outstanding borrowings under the Alta Mesa Predecessor Credit Facility of approximately $134.1 million as of the acquisition date.

Prior to the Business Combination, we had notes payable to our founder (‘Founder Notes’) that bore simple interest at 10%.  The Founder Notes were part of the non-STACK distribution.  The balance of the Founder Notes at the time of conversion was approximately $28.3 million, including accrued interest.  Interest on the Founder Notes was $0.1 million, $1.2 million and $1.2 million for the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, respectively.

(1) Represents the same wells under the Predecessor Period valued at a higher interest rate of 10.2% compared to interest rates ranging between 4.4% and 8.8%.

The facility matures in February 2023 and is subject to semiannual redeterminations. We may borrow in Eurodollars or at a reference rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, plus a margin ranging from 2.00% to 3.00%. Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s prime rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus a margin ranging from 1.00% to 2.00%.

Our 2024 Notes have a face value of $500.0 million and bear interest at 7.875% per annum. The 2024 Notes were issued at par during the 4th quarter of 2016 in a private placement but were exchanged for substantially identical registered senior notes in November 2017.

The 2024 Notes mature in December 2024 with interest payable semi-annually on June 15 and December 15. Before December 2019, we may redeem up to 35% of the 2024 Notes using proceeds from equity offerings at a redemption price of 107.875% of principal under specified conditions. Before December 2019, we otherwise may redeem the 2024 Notes at their principal amount plus an applicable make-whole premium.

Upon certain changes of control, the terms of the notes may require us to redeem them at 101% of the principal amount. The Business Combination did not constitute a change in control for the 2024 Notes.

We have an agreement with ARM pursuant to which they market our oil, gas and NGLs. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. ARM collects payments from purchasers, deducts their fee and remits the balance to us. In addition, ARM markets our firm transportation on the ONEOK Gas Transportation, L.L.C. system and the Panhandle Eastern Pipeline Company, LP system for a management fee. The AM Contributor owns 10% of ARM. During the Successor Period, we paid ARM $1.4 million for our share of the marketing fees. Receivables from ARM for sales on our behalf were $38.4 million and $22.4 million as of December 31, 2018 and 2017, respectively.  During the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, sales managed by ARM on our behalf were $309.7 million, $28.8 million, $199.2 million and $114.8 million, respectively.

AMR sponsors a 401(k) savings plan, whereby our employees can elect to make contributions pursuant to a salary reduction agreement. We make matching contributions equal to 100% of the first 5% of an employee’s contributions. Employee contributions are immediately vested whereas company matching contributions vest 50% after two years and become fully vested at the end of three years. Matching contributions to the plan were approximately $1.0 million, $0.3 million, $1.2 million, and $1.1 million for the Successor Period, the 2018 Predecessor Period, 2017 and 2016, respectively.

Since we are a limited partnership, our operations and activities are managed by the board of directors of Alta Mesa GP.  The limited liability company agreement of Alta Mesa GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic rights in Alta Mesa GP and (ii) Class B Units which hold 100% of the voting interests in Alta Mesa GP.

SRII Opco is the sole owner of Alta Mesa GP’s Class A Units and owns 90% of the Class B Units.  Our former President and Chief Executive Officer and our former Chief Operating Officer-Upstream, along with certain affiliates of Bayou City, and HPS Investment Partners, LLC (‘HPS’), own an aggregate 10% of the Class B Units. AMH GP’s board of directors are selected by the Class B members. Notwithstanding the foregoing, voting control of AMH GP is vested in SRII Opco pursuant to a voting agreement.

Employees were also granted performance-based restricted stock units (‘PSUs’) under the LTIP. PSUs granted in 2018 generally vest over three years at 20% during the first year, 30% during the second year and 50% during the third year. The number of PSUs vesting each year will be based on the achievement of annual company-specified performance goals and objectives applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that vest can range from 0% to 200% of the target grant applicable to each vesting period. We only recognize expense for PSUs when the specified performance thresholds for future periods have been established. For PSUs granted during the Successor Period only the performance goals and objectives for 2018 had been established as of December 31, 2018. Those 2018 performance goals were not attained, and the 2018 award tranche was forfeited, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted. No amounts will be recognized for the 2019 and 2020 performance periods until the specific targets have been established and probability of attainment can be measured.

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.

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.

On February 9, 2018, AMR consummated the acquisition of (i) all of the limited partnership interest in the Company, (ii) 100% of the economic interests and 90% of the voting interests in AMH GP and (iii) all of the membership interests in Kingfisher Midstream, LLC (‘Kingfisher’), which we collectively refer to as the ‘Business Combination’. As is the case with many partnerships, we do not directly employ officers, directors or employees. Our operations and activities are managed by the Board of Directors and officers of AMH GP. References to our directors and officers are references to the directors and officers of AMH GP. References to our employees are references to the employees of AMS, an entity wholly owned by us.

(10) Base Salary for 2018 includes (i) $50,192, which represents of Mr. McCabe’s pre-Business Combination base salary and (ii) $399,231 which is the base salary paid in 2018 from the closing of the Business Combination. The allocation of the base salary to us is 100% of the $50,192 and 50% of the $399,231. The All Other Compensation for 2018 includes (i) $14,350 for Miscellaneous and Company Contributions to Defined Contribution Plans and (ii) $3,000,000 in PARs. The allocation of the All Other Compensation to us is 50% of the $14,350 and 100% of the $3,000,000. All other amounts of compensation for 2018 were allocated at 50% to us.

(11)    Base Salary for 2018 includes (i) $55,962, which represents Mr. Chappelle’s pre-Business Combination base salary and (ii) $724,154 which is the base salary paid in 2018 from the closing of the Business Combination. The allocation of the base salary to us is 100% of the $55,962 and 50% of the $724,154. All other amounts of compensation for 2018 were allocated at 50% to us.

Target bonus opportunity consists of base salary multiplied by bonus target, which is expressed as a percentage of base salary. The quantitative corporate performance score can range between 0% and 200%, with 100% being the target. Individual performance factors can range between 0 and 1.5.

Messrs. Hackett, Chappelle and McCabe and Ms. Warnica participated in both upstream and midstream bonus plans with weighting proportionate to the respective upstream and midstream EBITDA(X) targets, resulting in a 30% weighted payout.

Ms. Warnica’s proportionate weighting was adjusted to 50% for each of upstream and midstream to more accurately align with her 2018 job responsibilities. Messrs. Ellis and Cole participated in only the upstream bonus plan.

Based on AMR’s performance results for the year ended December 31, 2018, Ms. Warnica received 58% of her target bonus. Each of Messrs. Hackett, Chappelle, McCabe, Ellis and Cole received no bonus for 2018.

After consultation with its independent consultant and considering competitive market data, the demand for talent, and cost considerations, the Committee awarded LTIs to each NEO as of February 9, 2018 in connection with the Business Combination with respect to Messrs. Hackett, Chappelle, Ellis, McCabe and Cole. The Committee determined to grant 30% of the target LTI value in restricted stock awards, 30% in options and 40% in performance-based restricted stock units. The Committee awarded LTIs to Ms. Warnica in connection with her joining the Company in April 2018 in recognition of grants that were forfeited from a prior employer, as well as during the annual grant cycle.

In connection with the Business Combination, AMR entered into a letter agreement with Mr. Hackett under which, if AMR terminates Mr. Hackett’s employment without cause or he resigns for good reason, within the meaning of and under the letter agreement, he will be entitled to full accelerated vesting of all AMR equity awards granted to him during the three years following closing of the Business Combination that are subject to time-based vesting and accelerated vesting of any such AMR equity awards that are subject to performance-based vesting at the target level of performance. The Board of AMR also approved an annual base salary for Mr. Hackett of $520,000, effective on the Closing Date, and a target annual bonus amount under an annual performance bonus program for 2018 of 95% of his annual base salary.

The employment agreement for Ms. Warnica entitles her to receive an annual base salary of $450,000 and to participate in an annual performance bonus program with a target bonus award determined by the Board of AMR. For 2018, Ms. Warnica’s target annual bonus amount under this program was 95% of her annual base salary. Ms. Warnica is also entitled to receive an annual physical and reimbursement of up to $5,000 per year for tax planning services. If Ms. Warnica’s employment is terminated without cause or she resigns for good reason, within the meaning of and under the employment agreement, she will be entitled to receive (i) a prorated annual bonus for the year of termination, determined at the discretion of the Committee and based on satisfaction of performance criteria prorated for the partial performance period, (ii) full accelerated vesting of all AMR equity awards that are subject to time-based vesting, accelerated vesting of any AMR equity awards that are subject to performance-based vesting at the target level of performance and full accelerated vesting of any nonqualified deferred compensation account balance or benefit, (iii) a lump-sum payment equal to the sum of $24,000 for outplacement services, (iv) 18 months of her annual base salary and 1.5 times the greater of her target annual bonus and the annual bonus paid to her for the prior year and (v) payment for up to 18 months of premiums for continued coverage in AMR’s group health plans and, thereafter, continued participation in AMR’s group health plans at her cost for up to an additional 6 months. Ms. Warnica would also be entitled to receive the amounts under clauses (i), (iii), (iv) and (v) of the preceding sentence if her employment terminates due to death or disability, under and within the meaning of her employment agreement. If Ms. Warnica’s qualifying termination of employment occurs during the fifteen months following a change in control (within the meaning of her employment agreement) or, only in the case of termination without cause or resignation for good reason, during the three months prior to a change in control and is demonstrated to be in connection with the change in control, then in addition to the foregoing payments and benefits, she will be entitled to an additional lump-sum payment equal to the sum of six months of her annual base salary and 0.5 times the greater of her target annual bonus and the annual bonus paid to her for the prior year. Ms. Warnica’s right to receive termination payments and benefits, other than a prorated annual bonus for the year of termination, are conditioned upon executing a general release of claims in our favor. Ms. Warnica has also agreed to refrain from competing with the Company or soliciting its customers or employees during and for a period of 12 months following her employment with AMS.

(2)after which no person or group beneficially owns voting securities representing 50% or more of the combined voting power of the Successor Entity; provided, however, that no person or group shall be treated for purposes of this clause (2) as beneficially owning 50% or more of the combined voting power of the Successor Entity solely as a result of the voting power held in AMR prior to the consummation of the transaction.

after which no person or group beneficially owns voting securities representing 50% or more of the combined voting power of the Successor Entity; provided, however, that no person or group shall be treated for purposes of this clause (2) as beneficially owning 50% or more of the combined voting power of the Successor Entity solely as a result of the voting power held in AMR prior to the consummation of the transaction.

‘Good Reason’ means the occurrence of any of the following without the NEO’s prior written consent, if not cured and corrected by AMR or the Company within 60 days after written notice thereof is provided by the NEO to AMS, provided such notice is delivered within 90 days after the occurrence of the applicable condition or event and that NEO resigns from employment with AMS within 90 days following expiration of such 60-day cure period: (a) the demotion or reduction in title or rank of NEO with AMR or the Company, or the assignment to NEO of duties that are materially inconsistent with NEO’s positions, duties and responsibilities with AMR or the Company, or any removal of the NEO from, or any failure to nominate for re- election the NEO to, any of such positions (other than a change due to the NEO’s Disability or as an accommodation under the American with Disabilities Act), except for any such demotion, reduction, assignment, removal or failure that occurs in connection with NEO’s termination of employment for Cause, Disability or death; (b) the reduction of the NEO’s annual base salary and/or target bonus opportunity, as compared to his aggregate base salary and target bonus opportunity as effective immediately prior to such reduction, if such reduction of base salary and/or target bonus opportunity, on an aggregated basis, is five percent (5%) or greater of the aggregate base salary and target bonus opportunity as effective immediately prior to such reduction; (c) a relocation of the NEO’s principal work location to a location in excess of 50 miles from its then current location; or (d) failure to nominate the NEO to be re-elected to the Board of AMR. For the avoidance of doubt, the closing of the Business Combination will not by itself be deemed to provide a basis for the NEO to resign for Good Reason.

On November 13, 2018, Michael A. McCabe, Vice President, Chief Financial Officer and Assistant Secretary, announced his plans to retire. Mr. McCabe retired from the Company effective March 29, 2019. In connection with his departure, AMS entered into a Separation Agreement with Mr. McCabe pursuant to which he is entitled to (i) vesting acceleration for his outstanding awards under AMR’s 2018 Long-Term Incentive Plan (other than his 2018 performance units, which were canceled), (ii) 150% of his base salary in effect on the separation date, (iii) 150% of the greater of (x) his target bonus or (y) the amount of bonus paid for the year immediately preceding the year containing the separation date, and (iv) a lump sum payment of approximately $117,209, in each case in exchange for certain waivers and releases for the Company’s benefit. Mr. McCabe will also receive certain other benefits, such as continued coverage pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as set forth in the separation agreement. These payments were paid to Mr. McCabe upon receipt of a general effective release of claims in the Company’s favor. These amounts will be reflected in the All Other Compensation column of the Summary Compensation Table next year.

(2)SRII Opco LP owns 100% of the economic interests in Alta Mesa and AMH GP. BCE-AMH Holdings, LLC, BCE-MESA Holdings, LLC, Mezzanine Partners II Delaware Subsidiary, LLC, Offshore Mezzanine Partners Master Fund II, L.P., Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., The Northwestern Mutual Life Insurance Company, The Northwestern Mutual Life Insurance Company For its Group Annuity Separate Account, Northwestern Mutual Capital Strategic Equity Fund III, LP, KCK-AMIH, Ltd., United Insurance Company of America, Jade Real Assets Fund, L.P., Michael E. Ellis and Harlan H. Chappelle (collectively, the ‘Existing Owners’) own a 10% non-voting interest in AMH GP. The Existing Owners and AMH GP are parties to a voting agreement with SRII Opco LP pursuant to which the Existing Owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP.

SRII Opco LP owns 100% of the economic interests in Alta Mesa and AMH GP. BCE-AMH Holdings, LLC, BCE-MESA Holdings, LLC, Mezzanine Partners II Delaware Subsidiary, LLC, Offshore Mezzanine Partners Master Fund II, L.P., Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., The Northwestern Mutual Life Insurance Company, The Northwestern Mutual Life Insurance Company For its Group Annuity Separate Account, Northwestern Mutual Capital Strategic Equity Fund III, LP, KCK-AMIH, Ltd., United Insurance Company of America, Jade Real Assets Fund, L.P., Michael E. Ellis and Harlan H. Chappelle (collectively, the ‘Existing Owners’) own a 10% non-voting interest in AMH GP. The Existing Owners and AMH GP are parties to a voting agreement with SRII Opco LP pursuant to which the Existing Owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP.

(4)Alta Mesa Resources, Inc. owns a 46.9% limited partnership interest in SRII Opco, LP and 100% of SRII Opco GP, LLC.

Alta Mesa Resources, Inc. owns a 46.9% limited partnership interest in SRII Opco, LP and 100% of SRII Opco GP, LLC.

(6)HPS Investment Partners, LLC (‘HPS’) manages each of Mezzanine Partners II Delaware Subsidiary, LLC, KFM Offshore, LLC, KFM Institutional, LLC, AP Mezzanine Partners II, L.P. and Jade Real Assets Fund, L.P., which collectively directly own approximately 8.5% of the limited partner interests in SRII Opco LP. The business address of each of these entities is c/o HPS Investment Partners, LLC, 40 West 57th street 33rd Floor, New York, NY 10019. HPS also manages, directly or indirectly, each of Mezzanine Partners II Delaware Subsidiary, LLC, KFM Offshore, LLC, a wholly-owned subsidiary of Offshore Mezzanine Partners Master Fund II, L.P., KFM Institutional, LLC, a wholly-owned subsidiary of Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., and Jade Real Assets Fund, L.P. (collectively, the ‘HPS Kingfisher Members’). The HPS Kingfisher Members own an interest in KFM Holdco, LLC, which owns an approximate 4.2% direct interest in SRII Opco, LLC. The amounts set forth in this footnote do not include the amounts that may be beneficially owned by the HPS Alta Mesa Members or the HPS Kingfisher Members indirectly through HMI and KFM Holdco, respectively.

HPS Investment Partners, LLC (‘HPS’) manages each of Mezzanine Partners II Delaware Subsidiary, LLC, KFM Offshore, LLC, KFM Institutional, LLC, AP Mezzanine Partners II, L.P. and Jade Real Assets Fund, L.P., which collectively directly own approximately 8.5% of the limited partner interests in SRII Opco LP. The business address of each of these entities is c/o HPS Investment Partners, LLC, 40 West 57th street 33rd Floor, New York, NY 10019. HPS also manages, directly or indirectly, each of Mezzanine Partners II Delaware Subsidiary, LLC, KFM Offshore, LLC, a wholly-owned subsidiary of Offshore Mezzanine Partners Master Fund II, L.P., KFM Institutional, LLC, a wholly-owned subsidiary of Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., and Jade Real Assets Fund, L.P. (collectively, the ‘HPS Kingfisher Members’). The HPS Kingfisher Members own an interest in KFM Holdco, LLC, which owns an approximate 4.2% direct interest in SRII Opco, LLC. The amounts set forth in this footnote do not include the amounts that may be beneficially owned by the HPS Alta Mesa Members or the HPS Kingfisher Members indirectly through HMI and KFM Holdco, respectively.

AMR has a policy with respect to the review and approval of related party transactions. A ‘Related Party Transaction’ is any transaction, arrangement or relationship where we are a participant, the Related Party (defined below) had, has or will have a direct or indirect material interest, and the aggregate amount involved is expected to exceed $120,000 in any calendar year. ‘Related Party’ includes (a) any person who is or was (at any time during the last fiscal year) an executive officer, director or nominee for election as a director; (b) any person or group who is a beneficial owner of more than 5% of our voting securities; (c) any immediate family member of a person described in provisions (a) or (b) of this sentence; or (d) any entity in which any of the foregoing persons is employed, is a partner or has a greater than 5% beneficial ownership interest.

Mr. Chappelle, Mr. Ellis and certain affiliates of Bayou City and Highbridge own an aggregate 10% voting interest in AMH GP. These individuals and entities were a party to a voting agreement with the AM Contributor and AMH GP, pursuant to which they have agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the closing of the Business Combination, the parties amended and restated the voting agreement to include SRII Opco LP as a party and the existing owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. The voting agreement will continue in force until SRII Opco LP elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in AMH GP.

We were founded in 1987 by Mr. Ellis and we, or our subsidiaries, over time had entered into promissory notes to repay Mr. Ellis for contributions of working capital and other amounts. The Founder Notes, prior to the Business Combination, bore interest at 10.0% paid-in-kind and were unsecured and subordinated to all of our debt at that time. Interest and principal were originally to be payable upon maturity on December 31, 2021.

On September 29, 2017, Alta Mesa 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 on February 28, 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. Alta Mesa subsequently declared all amounts owing under the note immediately due and payable. Alta Mesa also has 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 Alta Mesa. We oppose HMI’s claims and believe HMI’s obligation under the notes to be valid assets of Alta Mesa and that the full amount is payable to Alta Mesa. 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 of our directors who are also controlling holders and directors of HMI, our disinterested directors are directing our course of action in 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.

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.

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.  Prior to the business combination, HMI owned a minority interest in KFM. Alta Mesa also indirectly owned a minimal interest in KFM through its 10% ownership of AEM.  In connection with the business combination, KFM is now a wholly owned subsidiary of SRII Opco LP.  We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM.

On September 21, 2016, we entered into an agreement with KFM that beginning January 1, 2017 through January 31, 2022, we shall reimburse KFM for 50% of any shortfall fee paid by KFM to a third-party operator for any year in which the daily delivered gas volume is less than the daily gas volume committed.   During the period February 9, 2018 through December 31, 2018, cash payments required under our commitments totaled approximately $0.1 million.

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