| Summary Of Significant Accounting Policies | NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We use accounting policies which reflect industry practices and conform to accounting principles generally accepted in the United States of America (“GAAP”). Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ capital. During the fourth quarter of 2017, we sold our oil and natural gas properties located in the Weeks Island field in Louisiana. The sale of the Weeks Island field was a disposal completed in 2017 as part of the Company’s overall strategic shift to operate only in the STACK, which we completed upon the closing of the business combination as discussed in Note 19. As a result, we presented the assets and liabilities and operating results directly related to the sale of the Weeks Island field as discontinued operations within the consolidated statement of operations. We will reflect the remainder of the disposal of the non-STACK assets as discontinued operations in 2018. See Note 6 — Discontinued Operations for further discussion.
Principles of Consolidation . The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.
Use of Estimates . The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquired properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. 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 maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance Corporation provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.
R estricted Cash. The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2017 and 2016, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute or there is unclaimed property for pooling orders in Oklahoma.
In November 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows: Restricted Cash, which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. We adopted ASU 2016-18 in the fourth quarter of 2017.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows:
As of December 31,
2017
2016
2015
(in thousands)
Cash and Cash Equivalents
$ 3,721
$ 7,185
$ 8,869
Restricted cash
1,269
433
105
Total cash, cash equivalents and restricted cash
$ 4,990
$ 7,618
$ 8,974
Accounts Receivable . Our receivables arise primarily from the sale of oil, natural gas and natural gas liquids and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. 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 of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts.
Accounts receivable consisted of the following:
As of December 31,
2017
2016
(in thousands)
Oil, natural gas and natural gas liquids sales
$ 31,878
$ 22,276
Joint interest billings
14,272
7,460
Pooling interest (1)
35,839
5,885
Allowance for doubtful accounts
(848)
(889)
Total accounts receivable, net
$ 81,141
$ 34,732
(1)
Pooling interest relates to Oklahoma’s forced pooling process which requires the company to offer mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represent costs of unbilled interests on wells which the company incurred before the pooling process was completed. Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties.
See Note 14 for further information regarding marketing arrangements with our primary marketing representative, ARM Energy Management, LLC (“AEM”) and significant concentrations. Accounts receivable from AEM arising from sales marketed on our behalf were $22.4 million and $14.9 million as of December 31, 2017 and 2016, respectively.
Allowance for Doubtful Accounts . We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated.
Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statements of operations. Deferred financing costs related to the Company’s senior secured revolving credit facility are included in deferred financing costs, net and the deferred financing costs related to the senior unsecured notes are included in long-term debt, net, on the Company’s consolidated balance sheets.
Property and Equipment . Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.
Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.
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, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, or “suspended” on the balance sheet pending determination of whether the well has discovered proved commercial reserves. See Note 5 for further details. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly.
Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.
Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in Account Standards Codification (ASC) 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.
Our evaluation of the Company’s proved properties resulted in impairment expense of $ 11.3 million, $ 16.1 million and $ 45.6 million for the years ended December 31, 2017 , 2016 and 2015, respectively, primarily due to increased operating costs for impairments incurred during 2017 and lower forecasted commodity prices for impairments incurred during 2016 and 2015.
Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statements of operations. For the years ended December 31, 2017 , 2016 and 2015, impairment expense of unproved properties was $ 19.0 million, $ 0.2 million, and $ 4.8 million, respectively.
Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.
If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2017 , 201 6 and 201 5, respectively, the Company did not record any impairment expense related to other long-lived assets.
Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.
DD&A expense for the years ended December 31, 2017 , 2016 and 2015 related to oil and natural gas properties was $ 92.1 million, $62.1 million, and $75.0 million, respectively.
Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2017 , 2016 and 2015 was $ 2.4 million, $2.9 million, and $3.0 million respectively.
Investments . The Company’s investment consisted of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method and we have recorded $9.0 million of Investment in LLC on the consolidated balance sheets as of December 31, 2017, and 2016. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations. As discussed in Note 19, o n February 8, 2018, in connection with the closing of the business combination, we transferred our 10.17% ownership interest in Orion to AM Contributor.
At December 31, 2017, Alta Mesa was a part owner of AEM with an ownership interest of less than 10% . AEM markets our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. For additional information on AEM, see Note 14.
Asset Retirement Obligations . We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset. The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. Accretion expense is recognized as the discounted liability is accreted to its expected settlement value. Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.
Derivative Financial Instruments . We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 7 for information on fair value).
Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in gain (loss) on derivative contracts in the consolidated statement of operations. Gains or losses from the settlement of matured derivatives contracts are also included in gain (loss) on derivatives contracts in the consolidated statement of operations. Cash flows from settlements of derivative contracts are classified as operating cash flows.
Income Taxes . The Company has elected under the Internal Revenue Code of 1986, as amended, provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.
Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable 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 the partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $340.1 million at December 31, 2017.
The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for (benefit from) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.
We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.
We have considered our exposure under the standard at both the federal and state tax levels. We have not recorded any liabilities for uncertain tax positions as of December 31, 2017 and 2016 . We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2017 , 2016 or 2015 .
The Company’s tax returns for the years ended December 31, 2014 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.
Revenue Recognition . We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances.
Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The fair value estimate of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs. We have estimated the fair value of our $500 million senior notes at $551 million on December 31, 2017 . Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments see Note 7 – Fair Value Disclosures and Note 11 - Long-Term Debt, Net and Notes Payable to Founder.
Acquisitions . Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition.
Recent Accounting Pronouncements Issued
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that do not elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard during the first quarter of 2019 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues at the end of any fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates measured as of June 30, or issue more than $1.0 billion of non-convertible debt over a three-year period. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We intend to apply push down accounting and reflect AMR’s basis and accounting policies in our financial statements from the date of the business combination. Therefore, we could be required to adopt the standard in the fourth quarter of 2018.
We are in the process of assessing our contracts and evaluating the impact on the consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09 as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our future revenues and expenses under the new gross-versus-net presentation guidance. We continue to evaluate the impact of these and other provisions of ASU 2014-09 on our accounting policies, changes to relevant business practices, internal controls, and consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases. 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 accounting for as leases under Topic 840, Leases . The standard will be effective for interim and annual periods beginning after December 15, 2018 for public companies and annual periods beginning after December 15, 2019 for all other entities, with earlier adoption permitted. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets.
At this time, we cannot reasonably estimate the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and impletion of ASU 2016-02 is expected to have an impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months. The adoption is also expected to result in increase in depreciation, depletion and amortization expense, interest expense recorded on our consolidated statement of operations, and additional disclosures. As part of our assessment to date, we have formed an implementation work team and will complete our evaluation in 2018. As we continue to evaluate and implement the standard, we will provide additional information about the expected financial impact at a future date. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard in 2020. We c ould cease to be an emerging growth company if we meet the re quirements as described above. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We intend to apply push down accounting and reflect AMR’s basis and accounting policies in our financial statements from the date of the business combination. Therefore, we could be required to adopt the standard on January 1, 2019.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) , which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017 for public companies and for fiscal years beginning after December 15, 2018 for all other entities. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required t o adopt the standard in 2019. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We intend to apply push down accounting and reflect AMR’s basis and accounting policies in our financial statements from the date of the business combination. Therefore, we could be required to adopt the standard in the fourth quarter of 2018. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our consolidated statements of cash flows.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”) , which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for interim and annual periods after December 15, 2017 for public companies and annual periods beginning after December 15, 2018 for all other entities. The amendments should be applied prospectively on or after the effective date and disclosures are not required at transition. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The Company early adopted ASU 2017-01 in the fourth quarter of 2017. We do not expect the adoption of ASU 2017-01 to have a material impact on our consolidated financial statements; however these amendments could result in the recording of fewer business combinations in the future periods.
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