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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2019

As discussed further in Note 3, on September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Initial Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on our statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy process have been classified as “liabilities subject to compromise” on our balance sheet at December 31, 2019. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. The accompanying financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on stockholders’ deficit accounts of any changes that may be made to our capitalization; or (iv) the effect on operations of any changes that may be made to our business. While operating as debtor-in-possession under Chapter 11 of the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected on its consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications on our historical financial statements.

Also, as described further in Note 3, on January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases. The Additional Debtors also continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

Ability to Continue as a Going Concern

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.

As described further in Note 1, we expect to sell substantially all of our assets no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.

Basis of Accounting and Presentation

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We had no items of other comprehensive income during any period presented. Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation, but had no impact on net income (loss), stockholders’ equity or partners’ capital.

As a result of the Business Combination, we are the acquirer for accounting purposes and Alta Mesa and KFM are the acquirees. The identifiable assets acquired and liabilities assumed were recorded at their estimated fair values, which were pushed down to each entity. As a result, our financial statements and certain footnotes separate our presentation into two distinct periods, the periods before the consummation of the Business Combination (“Predecessor Periods”) and the period after that date (the “Successor Period”). Our financial statements reflect Alta Mesa as the “Predecessor” for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, reflecting the consolidation of Alta Mesa and KFM beginning on February 9, 2018. The period January 1, 2018 to February 8, 2018 is referred to as the 2018 Predecessor Period. The 2018 Predecessor Period and the periods prior to January 1, 2018 are collectively referred to as the “Predecessor Periods”.

As noted above, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa in connection with the closing of the Business Combination. We determined the non-STACK oil and gas assets and related liabilities are discontinued operations during the Predecessor Periods and have segregated their financial information from ours in the financial statements.

Principles of Consolidation

The financial statements include the accounts of the Company and its subsidiaries, and eliminate all intercompany transactions and balances. The Company’s interests in oil and gas upstream ventures and partnerships are proportionately consolidated. Noncontrolling interest (“NCI”) represents third-party ownership interests in SRII Opco and is presented as a component of equity. The portion of SRII Opco earnings that are not attributable to the Company are separately presented in our statements of operations.

Segment Reporting (Successor)

We operate in two reportable business segments: (i) Upstream and (ii) Midstream. Alta Mesa conducts our Upstream activities and owns proved and unproved oil and gas properties. KFM operates our Midstream segment and owns gas gathering, processing and produced water disposal assets and crude oil gathering and transportation assets. Both segments are conducted in the United States and all revenue was derived from customers located in the United States.

Use of Estimates

Preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported revenue and expenses during the reporting period. Estimates of reserves and their value are used to determine depletion and to conduct impairment analysis of oil and gas properties and can significantly affect future estimated cash flows utilized to assess goodwill and intangible assets for impairment. Estimating reserves has inherent uncertainty, including the projection of future rates of production and the timing of development expenditures.

Other significant estimates are utilized to determine amounts reported under GAAP related to collectibility of receivables, asset retirement obligations, federal and state taxes and contingencies. We base certain of our estimates on historical experience and various other assumptions that we believe to be reasonable. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. We regularly maintain cash balances that exceed federally insured amounts, but we have experienced no losses associated with these amounts.

Restricted Cash

Cash balances that are legally, contractually or otherwise restricted as to withdrawal or usage are considered restricted cash. As of December 31, 2019, and 2018, our restricted cash represents cash received for production where the final division of ownership is in dispute or there is unclaimed property for pooling orders in Oklahoma.

Accounts Receivable

Our receivables arise primarily from (i) the sale of our production, (ii) joint interest owners’ portion of operating costs for properties in which we are the operator, and (iii) for midstream services provided to third-party customers. The purchasers of our production and our midstream customers are concentrated in the oil and gas industry and therefore they are similarly affected by prevailing industry conditions. Accounts receivable are generally not collateralized. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties we operate and market the production.

We routinely assess the recoverability of our receivables to determine their collectibility. We establish a valuation allowance to reduce receivables to their estimated collectible amounts, based upon several factors including, our historical experience, the length of time a receivable has been outstanding, communication with customers and the current and projected financial condition of specific customers.

Property and Equipment and Exploration Expense

Property and Equipment

Our oil and gas property is accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts to obtain a mineral interest or right in a property, including related broker and other fees. These costs are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties

and become subject to depletion, or when we abandon plans to develop leases are impaired, at which time the costs are expensed as exploration costs. Unproved properties are not subject to depletion.

Proved Oil and Gas Properties — We capitalize costs incurred to drill, complete and equip proved reserves. Proved property costs include all costs incurred to drill and equip successful exploratory wells, development wells (regardless of success), development-type stratigraphic test wells and service wells, plus costs transferred from unproved properties.

Accounting policies for Midstream and other assets include:

Other Property and Equipment — Other property and equipment, such as land, buildings, plant equipment, assets associated with produced water disposal, vehicles, office furniture and office equipment, are recorded at cost. Maintenance, repairs and minor renewals are expensed as incurred. Plant and equipment also includes costs for our cryogenic gas processing facility along with gas gathering pipelines and compression, including rights of way, and a crude oil gathering system and crude oil storage facility.

Other important accounting policies affecting property and equipment include:

Depreciation and Depletion — Depletion of proved oil and gas properties is computed using the unit-of-production method based upon produced volumes and estimated proved reserves. Because all of our oil and gas properties are located in a single basin, we apply depletion on a single cost center. We deplete leasehold acquisition costs and the cost to acquire proved properties (generally proved undeveloped costs) based upon total estimated proved reserves. We deplete costs to drill, complete and equip wells plus the related lease costs (generally proved developed costs) over estimated proved developed reserves.

Through December 31, 2019, we depreciated our Midstream property and equipment using the straight-line method over the estimated useful lives of the assets, which included 35 years for our produced water disposal assets, processing plant and pipelines and 25 years for our compressors. Leasehold improvements were depreciated over the shorter of their useful lives or the term of the lease. Vehicles and office furniture and office equipment were depreciated over their estimated useful lives, ranging from three years to seven years. As a result of the expected sale of substantially all of our assets no later than mid-April 2020, we will depreciate any assets that are not to be acquired by the Buyer over our expected wind-down period, expected to be less than one year.

Impairment — Because proved reserves have not been ascribed to unproved property, in determining whether it is impaired, we consider numerous factors including recent leasing activity, recent drilling results in the area, our geologists’ evaluation and the remaining lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated proved and unproved reserves and, combined with a market approach, estimate fair value. Our cash flow estimates for unproved reserves are reduced by additional risk-weighting factors. We then reduce the carrying amount, if higher, to estimated fair value.

We review proved oil and gas properties at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows to the carrying value. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value, which we estimate by discounting the projected future cash flows using an appropriate risk-adjusted rate.

We evaluate whether the value of all other long-lived assets, including our midstream assets, is impaired when circumstances indicate the carrying value of those assets may not be recoverable. Such circumstances could result from events such as changes in the condition of an asset, changes to planned throughput or a change in our intent to utilize the asset. The determination of recovery is based on undiscounted cash flow projections or the likely cash flow from sale of the assets compared to the carrying value of the assets. If the carrying amount exceeds undiscounted future net cash flows, we adjust the carrying amount of the assets to their estimated fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent comparable sales, estimated replacement cost, an internally-developed, market participant-based discounted cash flow analysis, an analysis from outside professional advisors or, if the long-lived asset is to be sold, utilizing the likely cash flow from sale as the best estimate of fair value.

Exploration Expense

Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired or expiring leases with no expected development, delay rentals, gains or losses on settlement of asset retirement obligations, salaries for geologically-focused employees and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well yields commercial reserves. If the exploratory well is determined to be unsuccessful, the cost is expensed as exploration expense in the period of that determination. If the exploratory well yields commercial reserves, it is transferred to proved oil and gas properties. Exploratory well costs may continue to be capitalized for several reporting periods if the assessment of commerciality is ongoing.

Equity Method Investment

We account for investments that we do not control, but in which we can exercise significant influence, using the equity method of accounting. Such investments are originally recorded at our acquisition cost. The investment is adjusted by our proportionate share of the investee’s net income, increased by contributions made and decreased by distributions received.

We assess the carrying value of our equity method investments for impairment when indicators exist indicating an impairment may be other-than-temporary. If an impairment is deemed to be other-than-temporary, we adjust the carrying value to fair value, if lower.

Deferred Financing Costs

Deferred financing costs reflect fees paid to lenders and third parties that are directly related to our establishment of our long term debt. Prior to the bankruptcy filing by the Initial Debtors, the costs associated with the Alta Mesa RBL were amortized over the term of the Alta Mesa RBL as additional interest expense, with the remaining unamortized costs written off to “reorganization items, net” in our statement of operations upon the bankruptcy filing. The costs associated with the KFM Credit Facility are reported as non-current assets and are amortized over the term of the KFM Credit Facility as additional interest expense but were written off in January after it filed for bankruptcy. During the Predecessor Periods, costs associated with the issuance of our 7.875% senior unsecured notes maturing in December 2024 (the “2024 Notes”) were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense. These Predecessor defined financing costs were eliminated with the Business Combination’s adjustment to 2024 Notes to fair value.

Acquisitions

Business combinations are accounted for using the acquisition method. The results of operations of any acquired businesses are included in our results of operations from the closing date. The total cost of each acquisition is allocated to tangible and intangible assets acquired and liabilities assumed based on their estimated fair values at the time of the acquisition.

Intangible Assets

In connection with the acquisition of KFM, we recognized the estimated fair value of acquired customer contracts and related customer relationships as intangible assets, which were valued using the income approach. These intangible assets, all of which related to the Midstream segment, had finite lives and were subject to amortization utilizing an accelerated attrition method to approximate the benefit received over their economic lives.

Goodwill

We recognized goodwill as the excess of the purchase price over the estimated fair value of the identified assets and liabilities acquired in the Business Combination. Goodwill was not amortized but was subject to periodic impairment assessment at least annually, or whenever events and circumstances indicated an impairment may exist.

Asset Retirement Obligations

We recognize liabilities for the anticipated future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets by increasing the carrying amount of the related long-lived asset at the time it is legally incurred. The

fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The asset retirement cost is recognized as depletion or depreciation over the life of the asset. Accretion expense represents the increase to the discounted liability toward its expected settlement value and is included in “Depreciation, depletion and amortization” in the statements of operations. Asset retirement obligations are subject to revision primarily for changes related to the estimated timing and cost of abandonment.

There are no material legal or contractual obligations relating to dismantlement, decommissioning or removal of our Midstream assets, other than for certain of our produced water assets, for which asset retirement obligations have been established as of December 31, 2019.

Bond Premium on 2024 Notes

In connection with the Business Combination, we estimated the fair value of our $500.0 million 2024 Notes at $533.6 million. The excess fair value above the face value was recognized as a bond premium, which was being amortized as a reduction in interest expense over the remaining term of the notes prior to the time of the bankruptcy filing by the Initial Debtors. The remaining unamortized premium was written off to “reorganization items, net” in our consolidated statement of operations upon the Initial Debtors’ bankruptcy filing.

Derivatives

We present our derivatives as assets or liabilities at estimated fair value. Changes in fair value of our derivatives, along with realized gains or losses from settlements, are recognized as “Gain (loss) on derivatives” in the statements of operations. Settlements of derivatives are classified as operating cash flows. Where master netting agreements are in place, we net the value of our derivative assets and liabilities with the same counterparty.

Income Taxes

Successor

Deferred income taxes are provided for the temporary differences between the basis of assets and liabilities for financial reporting and income tax purposes. We classify deferred tax assets and liabilities as noncurrent.

We assess the ability to realize our deferred tax assets on a quarterly basis. Deferred tax assets may be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. A valuation allowance is established to reduce deferred tax assets to the amount expected to be realized when we determine that it is more likely than not that some or all of the deferred tax assets are not realizable.

We are also subject to the Texas margin tax, which is considered an income-based tax. We recognize tax (current and deferred) based on taxable income, as determined using the rules for the margin tax as a component of our income tax provision.

We assess uncertain tax positions using a two-step process. If we determine it is more likely than not that the income tax position will be sustained upon examination by the taxing authorities, we recognize the largest amount that is greater than 50% likely to be realized upon ultimate settlement. We have considered our exposure under the standard at both the federal and state tax levels. We did not record any liabilities for uncertain tax positions as of December 31, 2019 or December 31, 2018.

We record interest and penalties for the taxation, as a component of income tax expense. We did not incur any material tax interest or penalties for any period presented.

Alta Mesa’s tax returns for the years ended December 31, 2016 and forward remain open for examination, but none are currently under examination by the relevant authorities.

Predecessor

Alta Mesa historically elected to be treated as an individual partnership for tax purposes. Accordingly, its items of income, expense, gains and losses flowed through to the partners and were taxed at the partner level. Accordingly, no tax provision for federal income taxes was recognized by the Predecessor.

Predecessor net income (loss) for financial statement purposes differed significantly from taxable income (loss) reported to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under Alta Mesa’s amended and restated partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes could not be readily determined due to some tax basis differences being determined at the partner level and Alta Mesa’s lack of information about each unitholder’s tax attributes in Alta Mesa.

Revenue Recognition

Predecessor -

Oil, natural gas, and NGL revenue were recognized when production was sold to a purchaser at a fixed or determinable price, when delivery had occurred and title had transferred, and collectibility of the revenue was reasonably assured. During the Predecessor Periods, we followed the sales method of accounting for revenue. Under this method of accounting, revenue was recognized based on volumes sold. There were no material gas imbalances during the periods presented.

Successor (Upstream) -

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU and the associated subsequent amendments (collectively, “ASC 606”), superseded virtually all of the revenue recognition guidance under GAAP. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services.

Our revenue from contracts with customers includes the sale of crude oil, natural gas, and NGLs. These sales are recognized as revenue when production is sold to a customer in fulfillment of performance obligations under the terms of the underlying contracts. Performance obligations primarily comprise delivery of our production at a delivery point, as negotiated within each contract. Each unit of oil, natural gas, and NGL is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.

Performance obligations are satisfied once control of the product has been transferred to the customer. We consider a variety of facts and circumstances in assessing the point control is transferred, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, our right to payment, and transfer of legal title. Moreover, as part of the process of applying the five-step model, we also evaluated AMH’s and KFM’s arrangement in following the principal-versus-agent guidance under ASC 606. As a principal seller to the customer, revenues are recognized on a gross basis, and as an agent, revenue are recognized on a net basis.

Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price or at purchaser posted prices for the producing area. For oil contracts, AMH is considered to be the principal seller to its customers, and we record sales and related expenses on a gross basis upon satisfaction of our performance obligations.

Our natural gas production is primarily sold to purchasers at prevailing market prices. We evaluate the contract terms of our gas processing arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis based on the assessment of control and, when applicable, principal versus agent guidance under ASC 606. During the Successor Period, we determined that we controlled the products during processing (i.e., control transfers at the tailgate of the processing plant) or until the processor’s sale to the end customers in downstream markets (i.e., the processor is our agent and we are the principal selling party). Accordingly, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the customer and the gathering and processing services are rendered, similar to the accounting treatment required under previous revenue accounting guidance. However, instances in which all or a significant percentage of the proceeds from the sale must be returned to the producer, we are deemed to be the agent. As a result, the purchase and sale are presented as a net transaction with our margin included in gathering and processing revenue. When evaluating the principal-versus-agent guidance under ASC 606 and its impact on AMH and KFM, all facts and circumstances are considered and judgment is often required in making this determination.

Customers are invoiced once our performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30-60 days. There are no significant judgments that

affect the amount or timing of revenue from contracts with customers. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities, apart from production receivables.

Our receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates, as well as for unbilled costs for wells subject to Oklahoma’s forced pooling process in which mineral owners have the option to participate in the drilling of pooled wells. Depending on the mineral owner’s decision, these costs will be billed to them or added to our oil and gas properties or lease operating expense. Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts.

We have concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors and have reflected this disaggregation of revenue for all periods presented.

We do not have material unsatisfied performance obligations for contracts as all contracts have either an original expected length of one year or less or the entire future consideration is variable and allocated entirely to a wholly unsatisfied performance obligation.

Midstream -

We have the following significant revenue sources each of which we consider to be a distinct service and each of which possesses a single performance obligation:


•	Natural gas gathering, processing and sale of residue gas and NGLs for Alta Mesa and third parties;


•	Crude oil gathering for Alta Mesa; and


•	Produced water gathering and disposal for Alta Mesa and third parties.

We provide our services pursuant to a variety of contracts that set forth our fees, including in certain contracts, the percentage of the proceeds from the sale of our customers’ products in addition to the specified fee. Our services are typically billed on a monthly basis in the month following services or delivery of the product with payment typically due within 30 days. We do not offer extended payment terms and we have no contracts with financing components. Our gathering contracts have initial terms that span multiple years up to the life of the dedicated properties. Our most significant produced water contract has an initial term of 15 years.

We recognize revenue principally under contracts that contain one or more of the following arrangements:

Fee-based arrangements

Revenue for fee-based arrangements are recognized over the contract term with revenue recognized for each month of service based on the volumes delivered by the customer. Both natural gas gathering and processing plus crude oil gathering services are recognized in gathering and processing revenues. Produced water services are recognized as produced water disposal fees.

For service rates that are unchanged over the contract term or escalate only due to inflation, we recognize revenue at the rate in effect during the month of service. We have instances where we also charge supplemental fees for an early period of time during the contract term and this revenue is recognized over the expected period of customer benefit, which is generally the remaining term of the contract. The difference between the amount billed and collected for such early term fees billed during the initial contract term and the amount recorded as revenue is deferred and recognized as contract liabilities. At December 31, 2019 and 2018, we had recognized a deferral of $3.4 million and $1.7 million, respectively, of these early term fees which is included in other long-term liabilities.

Percent-of-proceeds arrangements

Under our percent-of-proceeds arrangements, we generally receive natural gas from producers at or near the wellhead, move it through our gathering system, process it to separate the gas and liquid products and sell the resulting gas and NGLs to third parties. We then remit to the producers an agreed-upon percentage of the actual proceeds received from sales. The margins we earn are directly related to the volumes that flow through our system and the price at which we are able to sell the products.

We evaluate our percent-of-proceeds arrangements with customers against the principal/agent provisions of the underlying contract. For those arrangements where we possess control of the commodity after processing and act as principal in the sale, we record sales revenue equal to the gross price received and we recognize the cost paid to the purchaser as cost of sales of

gathered purchased production. For those percent-of-proceeds arrangements where we do not control the products after processing, because substantially all of the sales proceeds are paid to the producer, we act as an agent for the producer and only recognize the net margin that we earn within sales of gathered production.

In limited instances, we may also receive products as consideration under percent-of-proceeds agreements. We recognize revenue for the products received at their fair value in the month of service.

Sale of gathered production

We sell gas, NGLs and condensate purchased from our customers to third parties pursuant to short term arrangements at market-based prices adjusted for location and quality differentials. These sales are recognized at the point (i) when we satisfy our performance obligation by transferring control of the product to the purchaser at the specified delivery point, (ii) when amounts are determinable and (iii) when we determine that collectibility is probable. The determination of the point control is transferred relies upon a variety of facts and circumstances including: the purchaser’s ability to use the products, the transfer of significant risks and rewards, our right to payment and transfer of legal title. The cost to purchase the underlying products is recognized when we obtain control of the product, but is generally concurrent with their sale.

Also, we may sell products to other midstream companies pursuant to off-take agreements. Under these contracts, we evaluate whether we control the products during processing and whether the processor controls the products in their sale to the ultimate purchaser. For those contracts where we do not control the products during processing, we recognize revenue on their sale to the midstream company based on the price received net of processing fees earned by the midstream company. For those contracts where we control the products during processing and where we direct their sale, we recognize revenue on the gross price received within sales of gathered production and we recognize the fees paid to the midstream company as transportation, processing and marketing expense.

Equity-Based Compensation

In 2018, we granted various types of stock-based awards, including stock options, restricted stock and performance-based restricted stock units to certain of our employees.

The fair value of stock option awards is determined using the Black-Scholes option pricing model, which includes various assumptions. Expected volatilities utilized in the option pricing model are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. Dividend yield is based on our expectations of dividend payments during the expected term of the options granted and risk-free interest rates are based on U.S. Treasury rates in effect at the grant date.

Service-based restricted stock awards are valued using the market price of our Class A Common Stock on the grant date. Performance-based restricted stock awards are valued using the market price of Class A Common Stock at the later of grant date and when all performance-based criteria are determined.

We recognize the estimated fair value of stock option and restricted stock awards as compensation expense on a straight-line basis over the applicable vesting period, which generally is 3.0 years, except in the case of awards made to our directors, which vest immediately upon issuance. Awards of performance-based restricted stock units that contain tranches with multi-year performance targets are recognized over the vesting period for which performance criteria for each tranche have been determined. All awards to employees typically require continued employment to vest. Forfeitures of unvested awards are recognized when they occur and result in the reversal of previously recognized expense.

Fair Value Hierarchy

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date within our principal market.

There are three levels of the fair value hierarchy:


•	Level 1 — Fair value is based on quoted prices in active markets for identical assets or liabilities.


•	Level 2 — Fair value is determined using significant observable inputs, generally either quoted prices in active markets for similar assets or liabilities, or quoted prices in markets that are not active.


•	Level 3 — Fair value is determined using one or more significant inputs that are unobservable in active markets at the measurement date. Such inputs are often used in pricing models, discounted cash flow calculations, or similar techniques.

We utilize fair value measurements to account for certain items, determine certain account balances and provide disclosures. Fair value measurements are also utilized in assessing the impairment of long-lived assets.

We consider the book values of our cash, accounts and notes receivable and current liabilities to approximate fair value due to their short-term nature. Our outstanding borrowings under the Alta Mesa RBL have been classified as liabilities subject to compromise at December 31, 2019 and the outstanding borrowings under the KFM Credit Facility will be classified similarly following the January 2020 bankruptcy filing by the Additional Debtors as full recovery by our lenders following the expected sale of substantially all of our assets is unlikely.

Earnings Per Share

Basic earnings per share is calculated by dividing earnings available to Class A common stockholders by the weighted average number of shares outstanding during each period. In periods where we report negative earnings, basic and diluted earnings per share are identical.

The Company uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding SRII Opco Common Units and corresponding shares of its outstanding Class C Common Stock, as well as outstanding warrants and the treasury stock method to determine the potential dilutive effect of restricted stock, restricted stock units and stock options.

Recent Issued Accounting Standards Applicable to Us

Recently Issued Accounting Standards Applicable to Us

Adopted

As described further in Note 5, we adopted Accounting Standards Update 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, effective 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 and would have been effective for us beginning January 2023. We made no determination as to the impact of this new standard on our financial position or results of operations upon adoption.

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, on a prospective basis, beginning January 2020.

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 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. Adoption of this standard will not impact our financial position or results of operations.