Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

The consolidated financial statements include the accounts of the Company and its subsidiaries, and eliminate all intercompany transactions and balances. The Company’s interests in oil and gas upstream ventures and partnerships are proportionately consolidated, in accordance with GAAP.

Use of Estimates

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

Other estimates are utilized to determine amounts reported under GAAP related to collectibility of receivables, asset retirement obligations, derivatives, accounting for business combinations, share-based compensation and contingencies. We base certain of our estimates on historical experience and various other assumptions that we believe to be reasonable. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.

Cash and Cash Equivalents

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

Restricted Cash

Cash balances that are legally, contractually or otherwise restricted as to withdrawal or usage are considered restricted cash. As of December 31, 2018 and 2017, our restricted cash represents cash received for production where the final division of ownership is in dispute or there is unclaimed property for pooling orders in Oklahoma.

Accounts Receivable

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

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

Property and Equipment

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

Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts to obtain a mineral interest or right in a property, including related broker and other fees. These costs are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties, or when leases expire, at which time the costs are expensed as exploration costs. Unproved properties are not subject to depletion.

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

Accounting policies for other assets include:

Other Property and Equipment — Other property and equipment, such as land, vehicles, office furniture and office equipment, are recorded at cost. Maintenance, repairs and minor renewals are expensed as incurred.

Other important accounting policies affecting property and equipment include:

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

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

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

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

Exploration Expense

Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, delay rentals, gains or losses on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well yields commercial reserves. If the exploratory well is determined to be unsuccessful, the cost is expensed as exploration expense in the period of that determination. If the exploratory well yields commercial reserves, it is transferred to proved oil and gas properties. Exploratory well costs may continue to be capitalized for several reporting periods if there is ongoing assessment of commerciality.

Deferred Financing Costs

Deferred financing costs reflect fees paid to lenders and third parties that are directly related to our establishment of our long term debt. The costs associated with the Alta Mesa RBL are reported as non-current assets and are amortized over the term of the facility as additional interest expense. During the Predecessor Periods, costs associated with the issuance of the 2024 Notes were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense.

Acquisitions

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

Asset Retirement Obligations

We recognize liabilities for the anticipated future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets by increasing the carrying amount of the related long-lived asset at the time it is legally incurred. The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The asset retirement cost is recognized as depletion or depreciation over the life of the asset. Accretion expense represents the increase to the discounted liability toward its expected settlement value and is included in “Depreciation, depletion and amortization” in the statements of operations. Asset retirement obligations are subject to revision primarily for changes related to the estimated timing and cost of abandonment.

Bond Premium on Senior Unsecured Notes

In connection with the Business Combination, we estimated the fair value of our $500.0 million senior unsecured notes at $533.6 million. The excess above the face value was recognized as a bond premium, which is being amortized as a reduction in interest expense over the remaining term of the notes.

Derivatives

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

Revenue Recognition

Predecessor -

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

Successor -

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU and the associated subsequent amendments (collectively, “ASC 606”), superseded virtually all of the revenue recognition guidance under GAAP. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply ASC 606 using either the full retrospective approach or a modified retrospective approach. Effective December 31, 2018, we ceased to be an emerging growth company and adopted ASC 606 for the Successor Period, using a modified retrospective approach. There was no impact on the timing of recognition of revenue or of our classification of amounts between revenue and operating expenses upon adoption of ASC 606.

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

Performance obligations are satisfied once control of the product has been transferred to the customer. We consider a variety of facts and circumstances in assessing the point control is transferred, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, our right to payment, and transfer of legal title.

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

Our natural gas production is primarily sold to purchasers at prevailing market prices. We evaluate the contract terms of our gas processing arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis based on the assessment of control and, when applicable, principal versus agent guidance under ASC 606. During the Successor Period, we determined that we controlled the products during processing (i.e., control transfers at the tailgate of the processing plant) or until the processor’s sale to the end customers in downstream markets (i.e., the processor is our agent and we are the principal selling party). Accordingly, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the customer and the gathering and processing services are rendered, similar to the accounting treatment required under previous revenue accounting guidance. All facts and circumstances are considered and judgment is often required in making this determination.

Customers are invoiced once our performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30-60 days. There are no significant judgments that affect the amount or timing of revenue from contracts with customers. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities, apart from production receivables.

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

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

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

Equity-Based Compensation

Our parent company, AMR, grants various types of stock-based awards, including stock options, restricted stock and performance-based restricted stock units to certain of our employees.

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

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

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

Income Taxes

We have elected under the Internal Revenue Code of 1986, as amended, to be treated as an individual partnership for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are not taxed at the partnership level. Accordingly, no tax provision for federal income taxes is included in these financial statements.

Fair Value Hierarchy

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

There are three levels of the fair value hierarchy:


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


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


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

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

We consider the book values of our cash, accounts and notes receivable and current liabilities to approximate fair value due to their short-term nature. We also consider the carrying value of our long-term debt under the Alta Mesa RBL to not be materially different from fair value due to short-term variable market rates of interest applicable to our outstanding borrowings.

Going Concern

Recenlty Issued and Applicable Accounting Standards

Adopted

During the 1st quarter of 2018, we adopted Accounting Standards Update (“ASU”) No. 2017-04, Intangibles - Goodwill and Other, Simplifying the Test for Goodwill Impairment. This new guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Accordingly, any identified impairment of goodwill will be recognized as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.

We adopted ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) on December 31, 2018, which clarified how certain transactions are classified in the statement of cash flows. The adoption of this guidance had no material effect.

We adopted ASU 2014-09, Revenue from Contacts with Customers, and related amendments, codified as Accounting Standards Codification (“ASC”) 606, on December 31, 2018, retroactive to the beginning of our Successor Period. There was no impact on the timing of recognition of revenue or of our classification of amounts between revenue and operating expenses upon adoption of ASC 606, however, enhanced disclosure of our revenue recognition policies was required.

Not Yet Adopted

Leasing Standards

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. We have used a modified retrospective transition approach for existing leases with terms in excess of 12 months entered into prior to January 1, 2019, the date of our adoption.

In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. ASU 2018-01 and subsequent applicable ASUs also provide several other optional practical expedients in transition. We elected the “package of practical expedients”, which permits us to forgo reassessment of our prior conclusions about lease identification, lease classification and initial direct costs for leases entered into prior to the effective date, January 1, 2019. We also elected the land easement relief which permits us to forgo reassessment of existing or expired land easements not previously accounted for under ASC 840. Additionally, we elected the practical expedient to not provide comparative reporting periods and therefore financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. By accounting policy, we will not separate non-lease components from lease components. We did not elect the use-of-hindsight practical expedient.

We are continuing to assess and finalize all of the effects of adoption, but currently believe the most significant effects relate to (1) recognition of new right-of-use assets and lease liabilities on our balance sheet for our office and equipment operating leases totaling approximately $20.0 million each, effective as of January 1, 2019; and (2) providing significant new disclosures about our leasing activities in our future filings.

We are also finalizing the implementation of third-party lease accounting software and completing the design and implementation of our processes and internal controls regarding this new standard.

Other Standards

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We don’t expect the adoption of this standard to impact our financial position or results of operations.