UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_______________________________________

FORM 10-Q

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(Mark One)

☒   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: March 31, 2018

OR

☐   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to

Commission file number: 333-173751

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ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

_______________________________________

 

Registrant’s telephone number, including area code: 281-530-0991

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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☐    No  ☒ 

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.   However, the registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant would have been required to file such reports) as if it were subject to such filing requirements.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)    Yes  ☒    No  ☐ 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐ 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒ 



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Table of Contents







 

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PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands) 



The accompanying notes are an integral part of these condensed consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(in thousands)

 





The accompanying notes are an integral part of these condensed consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (Unaudited)

(in thousands)









The accompanying notes are an integral part of these condensed consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)





The accompanying notes are an integral part of these condensed consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



1. DESCRIPTION OF BUSINESS



Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent exploration and production company engaged primarily in the acquisition, exploration, development, and production of unconventional oil and natural gas properties in the eastern portion of the Anadarko Basin commonly referred to as the STACK.  The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area. 



On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by the Contribution Agreement, dated August 16, 2017, with Alta Mesa Resources, Inc. (“AMR”) (formerly Silver Run Acquisition Corporation II), High Mesa Holdings, LP (the “AM Contributor”), High Mesa Holdings GP, LLC,  the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor (“AM Contribution Agreement”). Simultaneous with the execution of the AM Contribution Agreement, AMR entered into (i) a Contribution Agreement, dated August 16, 2017, with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”), and, solely for certain provisions therein, the equity owners of the KFM Contributor (the “KFM Contribution Agreement”); and (ii) a Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”).



Pursuant to the Contribution Agreements, SRII Opco, LP, a newly formed subsidiary of AMR (“SRII Opco”), acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP ((i) and (ii) together, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “Business Combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.”



As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. AMR is a publicly traded corporation that is not under the control of any person. Prior to the closing of the Transactions, AMH GP, and consequently, us, was controlled by High Mesa Inc. (“High Mesa”) and indirectly by our founder and Chief Operating Officer, Michael E. Ellis.



In connection with the closing of the Business Combination, we distributed the remainder of our non-STACK assets to the AM Contributor and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities.  



Refer to Note 5—Business Combination for further information related to the Business Combination.

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES



We have provided a discussion of significant accounting policies in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Annual Report”).  As of March 31, 2018, our significant accounting policies are consistent with those discussed in Note 2 in the 2017 Annual Report, other than as noted below.



Basis of Presentation



The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete financial statements. The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances.



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The condensed consolidated financial statements included herein as of March 31, 2018, and for the period from February 9. 2018 through March 31, 2018 (Successor), January 1, 2018 through February 8, 2018 (Predecessor) and the three months ended March 31, 2017 (Predecessor), are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented.  The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2017, which were filed with the Securities and Exchange Commission (the “SEC”) in our 2017 Annual Report.  Certain reclassifications of prior period condensed consolidated financial statements have been made to conform to current reporting practices.  The reclassifications had no impact on net income (loss) or partners’ capital. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year. 



As a result of the Business Combination, AMR was treated as the accounting acquirer and we are the accounting acquiree.  Pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 805, Business Combinations, (“ASC 805”), the identifiable assets acquired and liabilities assumed were provisionally recorded at their estimated fair values on the Closing Date of the Business Combination (also referred to herein as the “acquisition date”).  Fair value adjustments related to the transaction have been pushed down to us resulting in assets and liabilities being recorded at fair value as of the acquisition date.  As a result of the impact of electing pushdown accounting, the financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented.  The Successor period presented herein is from February 9, 2018 to March 31, 2018 (“Successor Period”) and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”) and for the three months ended March 31, 2017 (“2017 Predecessor Period”).



The Company’s statement of operations subsequent to the Business Combination includes depreciation and amortization expense on the Company’s property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain other items of income and expense were also impacted. Therefore, the Company’s financial information prior to the Business Combination is not comparable to its financial information subsequent to the Business Combination.



As noted above, we distributed the remainder of our non-STACK assets to the AM Contributor in connection with the closing of the Business Combination.  The distribution of our remaining non-STACK assets and the sale of our Weeks Island field during the fourth quarter 2017 (collectively, the “non-STACK assets”) were part of the Company’s overall strategic shift to operate only in the eastern Anadarko Basin.  As a result, the Predecessor assets and liabilities and operating results directly related to non-STACK assets are presented as discontinued operations within the consolidated statement of operations.  See Note 7 — Discontinued Operations for further discussion.



Use of Estimates



The preparation of condensed 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 condensed 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 potential 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. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, accounting for business combinations, state taxes, share-based compensation 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.



Bond Premium on Senior Unsecured Notes



As result of the push down accounting related to the Business Combination, the Company estimated the fair value of our $500 million senior unsecured notes at $533.6 million as of the acquisition date.  The amount in excess of the principal amount was recorded as a bond premium, which is being amortized over the term of the notes using the straight-line method, which approximates the effective interest method. 



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Equity Based Compensation (Successor)



The Company recognizes compensation related to all stock-based awards, including awards of AMR stock and stock options, in the financial statements based on their estimated grant-date fair value. AMR grants various types of stock-based awards including stock options and restricted stock. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock awards are valued using the market price of AMR’s common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period.  See Note 16 – Equity Based Compensation for additional information regarding the Company’s equity based compensation (Successor).



Restricted Cash

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 (in thousands):





Recent Accounting Pronouncements



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 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.  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 applied push down accounting to reflect AMR’s basis and accounting policies in our financial statements from the date of the Business Combination. If AMR loses its emerging growth company status in 2018, we would 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 accounted 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.

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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.  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 applied push down accounting to reflect AMR’s basis and accounting policies in our financial statements from the date of the Business Combination. If AMR loses its emerging growth company status in 2018, we would adopt the standard on January 1, 2019.



In May 2017, the FASB issued ASU No. 2017-09, Compensation – Stock Compensation: Scope of Modification Accounting (“ASU 2017-09”), which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718.  ASU 2017-09 requires entities to account for the effects of a modification unless the fair value, vesting conditions, and classification of the modified award are all the same as the original award immediately before the original award is modified. ASU 2017-09 is effective prospectively for interim and annual reporting periods beginning after December 15, 2017.  The Company adopted ASU 2017-09 in the first quarter of 2018; however, the adoption of ASU No. 2017-09 did not have a material impact on the Company's consolidated financial statements.

 

3. SUPPLEMENTAL CASH FLOW INFORMATION



Supplemental cash flow disclosures and non-cash investing and financing activities are presented below (in thousands):





 

4. ACCOUNTS RECEIVABLE



Accounts receivable consisted of the following (in thousands):





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5. BUSINESS COMBINATION



As discussed in Note 1, on February 9, 2018, we consummated the Transactions contemplated by the AM Contribution Agreement.



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Pursuant to the AM Contribution Agreement, SRII Opco acquired  (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP.  At the closing of the Transactions, the AM Contributor received 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco.  The AM Contributor also acquired from AMR a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), corresponding to the number of Common Units received by the AM Contributor at closing.  The Common Units of SRII Opco and corresponding Class C Common Stock issued to the AM Contributor are redeemable for AMR’s Class A Common Stock or cash (at AMR’s election) beginning 180 days after closing.



Additionally, for a period of seven years following the closing, the AM Contributor will be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of AMR’s Class C Common Stock) as earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock of AMR equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):







The AM Contributor will not be entitled to receive a particular Earn-Out Payment on more than one occasion and, if, on a particular date, the 20-Day VWAP entitles the AM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of AMR, including a merger or sale of all or substantially all of AMR’s assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.



AMR also contributed $560 million in net cash contributions to us at the closing. AMR’s source for these funds was from the sale of its securities to investors in a public offering and in private placements.  We used a portion of the amount to repay all outstanding balances under the senior secured revolving credit facility.



Pursuant to the AM Contribution Agreement, AM Contributor delivered a final closing statement.  Subsequent to quarter end, it was determined that the AM Contributor would receive a positive adjustment amount and be issued 1,197,934 additional SRII Opco Common Units and an equivalent number of shares of AMR’s Class C Common Stock.



The Business Combination has been accounted for using the acquisition method. The acquisition method of accounting is based on FASB ASC 805, Business Combination, and uses the fair value concepts defined in FASB ASC 820, Fair Value Measurements (“ASC 820”). ASC 805 requires, among other things, that all assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by AMR, who was determined to be the accounting acquirer.  We have not completed the detailed valuation studies necessary to arrive at the final determination of the fair value of the assets acquired, the liabilities assumed and the related allocations of the purchase price in the Business Combination. As a result, the values of certain assets and liabilities are preliminary in nature and are subject to change as additional information becomes available and as additional analyses are performed.  Pursuant to ASC 805, finalization of the values are to be completed within one year of the Acquisition Date.



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Preliminary Estimated Purchase Price



AMR’s preliminary estimated purchase price consideration for Alta Mesa is as follows:





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Preliminary Estimated Purchase Price Allocation



The following table summarizes the allocation of AMR’s preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed in connection with the acquisition of Alta Mesa in the Business Combination. The allocation is as follows:

 



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6. PROPERTY AND EQUIPMENT



Property and equipment consists of the following (in thousands):





In conjunction with pushdown accounting, property and equipment was measured at fair value as of the acquisition date, which also impacted how value was assigned between the categories within property and equipment (see Note 5 – Business Combination for details).

 

7. DISCONTINUED OPERATIONS



As discussed in Note 1, we distributed the remainder of our non-STACK assets and related liabilities to the AM Contributor in connection with the closing of the Business Combination.  The distribution of our remaining non-STACK assets and related liabilities during the first quarter of 2018 and the sale of our Weeks Island field during the fourth quarter of 2017 completed the Company’s overall strategic shift to operate only in the eastern Anadarko Basin.  As a result, the Predecessor’s non-STACK assets and liabilities have been presented as discontinued operations in the consolidated balance sheets.  The operating results directly related to non-STACK assets and liabilities have been segregated and presented as discontinued operations within the condensed consolidated financial statements in the 2018 Predecessor Period and 2017 Predecessor Period. 



Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bear simple interest at 10%.  In connection with the Transactions described in Note 1, the Founder Notes were converted into equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK assets distribution.  The balance of the Founder Notes at the time of conversion was approximately $28.3 million including accrued interest.  Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period and $0.3 million for the 2017 Predecessor Period.

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The assets and liabilities directly related to the non-STACK assets have been reclassified to assets and liabilities associated with discontinued operations as follows (in thousands):







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The results of operations of the non-STACK assets and other items directly related to the sale of the non-STACK assets have been reclassified in discontinued operations as follows (in thousands):





The total operating and investing cash flows of the non-STACK assets are as follows (in thousands):



 

8. FAIR VALUE DISCLOSURES



We follow ASC 820, “Fair Value Measurements and Disclosures” (“ASC 820”). ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least reliable. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.



The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value 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.  In connection with the Business Combination, we recorded the fair value of our $500 million senior notes at $533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $520.6 million at March 31, 2018.  This estimation is based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination. See Note 11— Long-Term Debt, Net for information on long-term debt.



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We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil, natural gas and natural gas liquids derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (“NYMEX”) for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil, natural gas and natural gas liquids prices. We have classified the fair values of all our oil, natural gas and natural gas liquids derivative contracts as Level 2.



Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and natural gas properties with a carrying amount of $3.3 million were written down to their fair value of $2.1 million, resulting in an impairment charge of $1.2 million for the 2017 Predecessor Period.  Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.



New additions to asset retirement obligations result from estimations for new or acquired properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $0.4 million, zero and $0.3 million in additions to asset retirement obligations measured at fair value during the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively.



The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:

 



The amounts above are presented on a gross basis.  Presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 9 – Derivative Financial Instruments.

 

9. DERIVATIVE FINANCIAL INSTRUMENTS



We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging” (“ASC 815”). We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas and natural gas liquids. From time to time, we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our oil, natural gas and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of our lenders under the senior secured revolving credit facility described in Note 11, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, natural gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month. The contracts represent agreements between us and the counterparties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading or speculative purposes. 



From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates. 



We have not designated any of our derivative contracts as fair value or cash flow hedges.  Accordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the condensed consolidated statements of operations at each reporting date.

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Derivative contracts are subject to master netting arrangements and are presented on a net basis in the condensed consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a liability account on the condensed consolidated balance sheets. Likewise, derivative liabilities could be presented in a derivative asset account. 



The following table summarizes the fair value and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:



Fair Values of Derivative Contracts:

















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The following table summarizes the effect of our derivative instruments in the condensed consolidated statements of operations (in thousands):







Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the senior secured revolving credit facility.



If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.



We had the following open derivative contracts for crude oil at March 31, 2018:



OIL DERIVATIVE CONTRACTS









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We had the following open derivative contracts for natural gas at March 31, 2018:



NATURAL GAS DERIVATIVE CONTRACTS







In those instances where contracts are identical as to time period, volume and strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above.  Prices stated in the table above for oil may settle against either the NYMEX index or may reflect a mix of positions settling on various combinations of these benchmarks.



We had the following open financial basis swaps at March 31, 2018:



NATURAL GAS BASIS SWAP DERIVATIVE CONTRACTS





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OIL BASIS SWAP DERIVATIVE CONTRACTS





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10. ASSET RETIREMENT OBLIGATIONS

A summary of the changes in asset retirement obligations is included in the table below (in thousands):







 

11. LONG-TERM DEBT, NET



Long-term debt, net consists of the following (in thousands):

 





Senior Secured Revolving Credit Facility (Successor). In connection with the consummation of the Business Combination, all indebtedness under the senior secured revolving credit facility was repaid in full. On February 9, 2018 and in connection with the closing of the AM Contribution Agreement (as described in Note 1), we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base. In April 2018, our borrowing base was increased to $400.0 million until the next scheduled redetermination in October 2018. The Eighth A&R credit facility does not permit us to borrow funds if at the time of such borrowing if we are not in compliance with the financial covenants set forth in the Eighth A&R credit facility. As of March 31, 2018, we have no borrowings under the Eighth A&R credit facility and have $13.6 million of outstanding letters of credit reimbursement obligations.

The principal amounts borrowed are payable on the maturity date of February 9, 2023. We have a choice of borrowing in Eurodollars or at the reference rate, with such borrowings bearing interest, payable quarterly for reference rate loans and one month, three month or six month periods for Eurodollar loans. Eurodollar loans bear interest at a rate per annum equal to the rate at the LIBOR, plus an applicable margin ranging from 2.00% and 3.00%.  Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus a margin ranging from 1.00% to 2.00%.  The next scheduled redetermination of our borrowing base is in October 2018. The borrowing base may be reduced in connection with the next redetermination of our borrowing base. The amounts outstanding under the Eighth A&R credit facility are secured by first priority liens on substantially all of the Company’s and its material operating subsidiaries’ oil and natural gas properties and associated assets and all of the equity of our material operating subsidiaries that are guarantors of the Eighth A&R credit facility. Additionally, SRII Opco and AMH GP have pledged their respective limited partner interests in us as security for our obligations. If an event of default occurs under the Eighth A&R credit facility, the administrative agent will have the right to proceed against the pledged capital stock and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.

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The Eighth A&R credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Eighth A&R credit facility permits us to make distributions to any parent entity (i) to pay for reimbursement of third party costs and expenses that are general and administrative expenses incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the tax receivable agreement. We can make restricted payments, so long as certain conditions are met, to any direct or indirect parent for the sole purpose of making a loan or capital contribution to Kingfisher in an amount up to $300 million until August 9, 2018.



The Eighth A&R credit facility also requires us to maintain the following two financial ratios:



We will be required to maintain financial ratios commencing on the fiscal quarter ending June 30, 2018.



Senior Secured Revolving Credit Facility (Predecessor).  As of December 31, 2017, the Company had $117.1 million outstanding.  At the date of the Business Combination, the outstanding balance under our credit facility was paid off.



Senior Unsecured Notes. We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) due December 15, 2024 which were issued at par by us and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016.  The senior notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017. 



The senior notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.



The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the senior notes.



The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture governing the senior notes to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business. 



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Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of the purchase.  The closing of the Business Combination with AMR did not constitute as a change of control under the indenture governing the senior notes because certain existing owners of the Company and SRII Opco entered into an amended and restated voting agreement with respect to the voting interests in AMH GP.  See Note 5 — Business Combination (Successor) to the consolidated financial statements for further detail.



The indenture contains customary events of default, including: 



The credit facility and the senior notes contain customary events of default.  If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest.  Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.



As of March 31, 2018, we were in compliance with the indentures governing the senior notes.



Bond Premium (Successor). As discussed in Note 5,  the fair value of our senior notes as of the acquisition date was $533.6 million.  The bond premium of $33.6 million is being amortized over the respective term of the senior notes.  The bond premium amortization recorded in the Successor Period was $0.8 million.  The unamortized bond premium related to the senior notes are netted with long-term debt on the condensed consolidated balance sheet as of March 31, 2018. 



Deferred financing costs. As of December 31, 2017, the unamortized deferred financing costs were $11.4 million. As a result of the Business Combination, the 2018 Predecessor Period deferred financing costs have been adjusted to a fair value of zero as part of pushdown accounting.  During the Successor Period, we incurred new deferred financing costs related to the Eighth A&R credit facility of $1.0 million. Amortization expense of zero,  $0.2 million and $1.0 million is included in interest expense on the consolidated statements of operations for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.   



12. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES



The following provides the details of accounts payable and accrued liabilities (in thousands):





 

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13. COMMITMENTS AND CONTINGENCIES



Contingencies



Environmental claims. Various landowners have sued us in lawsuits concerning several fields in which we have or historically had operations.  The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our condensed consolidated financial statements at March 31, 2018.



Title/lease disputes. Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.



Litigation (Predecessor). On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our former subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish.  Plaintiffs claimed they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located.  Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon.  The property was originally owned by Exxon and was sold to TMRC.  TMRC subsequently sold the property to Extex.  On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter.  On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon.  On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement.  In connection with the Business Combination, the liability was included in the distribution of our non-STACK assets to the AM contributor.



On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP, our wholly owned subsidiary, Alta Mesa Services, LP, our wholly owned subsidiary, and us (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty.  The suit alleges that the AMH Parties made improper post production deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells.  The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case.  In June 2017, the court administratively closed the case following mediation.  As of December 31, 2017, we accrued approximately $4.7 million in accounts payable and accrued liabilities in our condensed consolidated balance sheets and in general and administrative expense (“G&A”) in our condensed consolidated statements of operations in connection with this litigation.  On March 12, 2018, the Class settlement was approved by the Court.  During January 2018, approximately $4.7 million was paid to fund the settlement.



On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including us. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to us in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants, including us. While we may incur costs or losses in connection with this litigation, we have not accrued a loss contingency because we are currently unable to determine the scope or merit of Mustang’s claim or to reasonably estimate an amount or range of such costs or losses. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves



Other contingencies. We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business.  The outcomes cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.



Performance appreciation rights.  In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014.  The Plan was intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company.  Under the Plan, participants were granted performance appreciation rights (“PARs”) with a stipulated initial designated value. The Business Combination with AMR as described in Note 5 resulted in the accelerated vesting and payment of all outstanding PARs.  The value of the PARs that vested upon the closing of the Business Combination was approximately $10.6 million and recorded in G&A in the 2018 Successor Period.  Following the closing of the Business Combination, the Plan was terminated.

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Nonqualified Deferred Compensation. In 2013, we established a nonqualified deferred compensation plan, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”).  The Retirement Plan was intended to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees. In connection with the Business Combination, we terminated the Retirement Plan resulting in approximately $9.4 million being recorded in G&A in the Successor Period. 

 

Commitment.    The Company has entered into certain firm transportation contracts that extend through 2028.  At March 31, 2018, the future minimum commitments related to these contracts are approximately $1.7 million a year.



14. SIGNIFICANT RISKS AND UNCERTAINTIES



Our business makes us vulnerable to changes in wellhead prices of oil and natural gas.  Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future.  Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors.  The duration and magnitude of changes in oil and natural gas prices cannot be predicted.  Declines in oil and/or natural gas prices or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves.  Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.  We mitigate some of this vulnerability by entering into oil, natural gas, and natural gas liquids price derivative contracts. See Note 9 – Derivative Financial Instruments for further details on derivatives.

 

15. PARTNERS’ CAPITAL



Management and Control:   Our Seventh Amended and Restated Agreement of Limited Partnership (the “Seventh Amended Partnership Agreement”) currently provides for interests to be divided into economic units held by the partners referred to as “LP Units” and non-economic general partner interests owned by AMH GP (as defined below) referred to as “GP Units”.  AMH GP owns all the GP Units and in connection with the Business Combination, SRII Opco owns all the LP Units. 



As a limited partnership, our operations and activities are managed by the board of directors (the “Board of Directors”) of our general partner, AMH GP.  The limited liability company agreement of AMH GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic interests in AMH GP and (ii) Class B Units, which hold 100% of the voting interests in AMH GP.



SRII Opco is the sole owner of Class A Units and owns 90% of the Class B Units.  Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, the founder, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company, and HPS Investment Partners, LLC, a Delaware limited liability company own an aggregate 10% of the Class B Units.  AMH GP’s Board of Directors are selected by the Class B Members.  Notwithstanding the foregoing, voting control of AMH GP is vested in SRII Opco pursuant to a voting agreement.



The Seventh Amended Partnership Agreement specifies the manner in which we will make cash distribution to our partners.  When AMH GP so directs, we shall make distributions of Net Cash Flow (as defined in the Seventh Amended Partnership Agreement) to the limited partner.

 

16. EQUITY BASED COMPENSATION



Equity based compensation (Successor)



Following the closing of the Business Combination, AMR adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”).  A total of 50,000,000 shares of AMR’s Class A Common Stock is reserved for issuance under the LTIP.  The LTIP provides for the grant of stock options, including incentive stock options (“ISOs”) and nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other stock-based awards in AMR’s Class A Common Stock.  Prior to the Business Combination, we did not have any equity based compensation programs. Pursuant to the LTIP, certain grants of stock-based awards were deemed granted on February 9, 2018.  During the Successor Period, AMR recognized non-cash stock-based compensation expense of $2.8 million resulting from stock options, restricted stock, and RSUs awards which is included in general and administrative expense in the accompanying consolidated statements of income.  Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.



We recognize compensation expense on a straight-line basis for service based grants over the vesting period.  The fair value of restricted stock awards is determined based on the estimated fair market value of our Class A Common Stock on the date of grant.



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Stock options.  



Options that have been granted under the LTIP expire seven years from the grant date and have service-based vesting schedules of three years. The exercise for an option under the LTIP may not be below the fair value of AMR’s Class A Common Stock on the grant date.  On the Closing Date, AMR granted 4,082,571 stock options to the Company’s employees.



Information about outstanding stock options is summarized in the table below:







Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period.  The Company estimates the fair value using the Black-Scholes option-pricing model.  Expected volatilities 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.  The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.

The following summarizes the assumptions used to determine the fair value of those options:





As of March 31, 2018, there was $17.8 million of unrecognized compensation cost related to non-vested stock options.  The Company expects to recognize that cost on a pro rata basis over a weighted average period of 2.8 years.

Restricted stock.



On February 9, 2018, 1,133,134 restricted stock were deemed granted to employees, one third of which vest on each anniversary of the grant date over three years, subject to the employee’s continued service.



The following table provides information about restricted stock awards granted during the Successor Period:







Compensation cost for the service-based vesting restricted shares is based upon the grant-date market value of the award.  Such costs are recognized ratably over the applicable three year vesting period.  Unrecognized compensation cost related to unvested restricted shares at March 31, 2018 was $9.6 million which the Company expects to recognize over a weighted average period of 2.8 years.

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Restricted stock units



On February 9, 2018, 0.7 million performance-based restricted stock units (“PSUs”) were deemed granted to key employees under the LTIP.  For the PSUs,  20% vest on December 31, 2018, 30% vest on December 31, 2019 and 50% vest on December 31, 2020; provided that the actual number of PSUs that are deemed granted and may be earned is between 0% and 200% of the initial target, with the final number to be dependent upon achievement of certain performance goals and objectives. The performance criteria with respect to the PSUs that vest December 31, 2018 is based on our cumulative EBITDAX, as defined in the PSU grant agreement. The performance criteria for PSUs that vest in 2019 and 2020 have not yet been established and, accordingly, those PSUs were not deemed granted as of March 31, 2018 for expense recognition purposes. During the restriction period, the RSUs may not be transferred or encumbered, and the recipient does not receive dividend equivalents or have voting rights until the unit vests.



The following summary provides information about RSUs granted during the Successor Period:







As of March 31, 2018, there was $5.2 million of unrecognized compensation cost related to the unvested RSUs which we expect to recognize on a pro rata basis over a weighted average period of 0.8 years.

 

17. SUBSIDIARY GUARANTORS



All of our wholly owned subsidiaries are guarantors under the terms of our senior notes and our credit facility. Our condensed consolidated financial statements reflect the financial position of these subsidiary guarantors. As the parent company, we have no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several.  Those subsidiaries which are not wholly owned by us and are not guarantors of our senior notes or our credit facility, are immaterial subsidiaries.  There are no restrictions on dividends, distributions, loans or other transfers of funds from the subsidiary guarantors to us.

 

18. SUBSEQUENT EVENT



Extended lease agreement.    On April 1, 2018, we amended our lease agreement for the Company headquarters located in Houston, Texas.  The amended lease agreement provides for additional expansion space and extends the original lease term through April 2028.  As a result of the amendment, we have additional lease commitment obligations of approximately $17.6 million through 2028.







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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations



The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes included elsewhere in this report. In addition, such analysis should be read in conjunction with the consolidated financial statements and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Annual Report”).  The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below in “Cautionary Statement Regarding Forward-Looking Statements,” and in our 2017 Annual Report, particularly in the section titled “Risk Factors,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.   



Overview



We have been engaged in the onshore oil and natural gas acquisition, exploitation, exploration and production in the United States since 1987.  Currently we are focusing on the development and acquisition of unconventional oil and natural gas reserves in the STACK.  We transitioned our focus from our prior diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities.  The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates.  The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area.  We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners. 



Business Combination with Alta Mesa Resources, Inc.



On August 16, 2017, we entered into a Contribution Agreement (the “AM Contribution Agreement”) with Alta Mesa Resources, Inc. (“AMR”) (formerly Silver Run Acquisition Corporation II, a Delaware corporation, High Mesa Holdings, LP, a Delaware limited partnership (the “AM Contributor”), High Mesa Holdings GP, LLC, a Texas limited liability company and the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, a Texas limited liability company and our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor. Simultaneous with the execution of the AM Contribution Agreement, AMR entered into (i) a Contribution Agreement (the “KFM Contribution Agreement”) with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”), and, solely for certain provisions therein, the equity owners of the KFM Contributor; and (ii) a Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”).



On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by the Contribution Agreements and SRII Opco, LP, a Delaware limited partnership (“SRII Opco”) acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP ((i) and (ii) together, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “Business Combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.”



SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco, is a wholly owned subsidiary of AMR.  The limited partners of SRII Opco are the AM Contributor, the KFM Contributor and the Riverstone Contributor (collectively, the “Contributors”), AMR and certain funds managed by Highbridge.  As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. AMR is a publicly traded corporation that is not under the control of any person. Prior to the closing of the Transactions, AMH GP, and consequently, us, were controlled by High Mesa and indirectly by our founder and Chief Operating Officer, Michael E. Ellis.



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Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company (“Bayou City”), and HPS Investment Partners, LLC, a Delaware limited liability company (“Highbridge”), continue to own an aggregate 10% voting interest in AMH GP following the closing. These existing owners were a party to a voting agreement with the AM Contributor and AMH GP, pursuant to which they agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the closing of the Transactions, the parties amended and restated the voting agreement to include SRII Opco as a party and the existing owners agreed to vote their interests in AMH GP as directed by SRII Opco and appoint SRII Opco as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. The amended and restated voting agreement will continue in force until SRII Opco elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in AMH GP.



Consideration



Pursuant to the AM Contribution Agreement, at the closing of the Transactions (the “Closing”), the AM Contributor received 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco. The AM Contributor also acquired from AMR a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), corresponding to the number of Common Units received by the AM Contributor at the Closing. 



In addition to the above, for a period of seven years following the Closing, the AM Contributor will be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of AMR’s Class C Common Stock) as earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock of AMR equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):





The AM Contributor will not be entitled to receive a particular Earn-Out Payment on more than one occasion and, if, on a particular date, the 20-Day VWAP entitles the AM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of AMR, including a merger or sale of all or substantially all of AMR’s assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.



AMR also contributed $560 million in net cash contributions to us at the Closing. AMR’s source for these funds was from the sale of its securities to investors in a public offering and in private placements.  We used a portion of the amount to repay all outstanding balances under the senior secured revolving credit facility.  



Pursuant to the AM Contribution Agreement, the AM Contributor delivered a final closing statement.  Subsequent to quarter end, it was determined that the AM Contributor would receive a positive adjustment amount and be issued 1,197,934 additional Common Units and an equivalent number of shares of AMR’s Class C Common Stock.   



Exchange or Redemption of Common Units



Beginning 180 days after the Closing, the AM Contributor will have the right to exchange its Common Units for shares of AMR Class A Common Stock or cash (at AMR’s election). Upon any redemption of Common Units by the AM Contributor, a corresponding number of shares of Class C Common Stock owned by the AM Contributor will be cancelled.



Amended Limited Partnership and Limited Liability Company Agreement 



In connection with the closing of the Business Combination on February 9, 2018, AMH GP and SRII Opco entered into a Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa (the “Seventh Amended Partnership Agreement”). The Seventh Amended Partnership Agreement reflects, among other things, that SRII Opco is now our sole limited partner.



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In addition, on February 9, 2018, the owners of AMH GP entered into a Sixth Amended and Restated Limited Liability Company Agreement of AMH GP, which was amended to, reflect that SRII Opco, now the holder of all of the Class A Units (as defined therein) is entitled to 100% of the economic rights with respect to AMH GP, and that SRII Opco is now the holder of 90% of the Class B Units (as defined therein) which are entitled to 100% of the voting rights with respect to AMH GP.



As described above, on February 9, 2018, all of the owners of AMH GP entered into an amended and restated voting agreement regarding the voting of their interests in AMH GP.



Appointment and Departure of Directors



In connection with the Business Combination, Michael A. McCabe, Homer “Gene” Cole, Mickey Ellis, Don Dimitrievich, William W. McMullen and Mark Stoner resigned from the board of AMH GP. In connection with the Business Combination, James T. Hackett was appointed to the board of AMH GP.  Harlan H. Chappelle and Michael E. Ellis remain directors on the board of AMH GP.  Our executive management team remains the same, except that Mr. Hackett is now Chairman of the Board.



Amended and Restated Senior Secured Revolving Credit Facility 



In connection with the closing of the Business Combination, we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base.  In April 2018, our borrowing base was increased to $400.0 million.  The Eighth A&R credit facility does not permit us to borrow funds if at the time of such borrowing we are not in compliance with our financial covenants. As of February 9, 2018, all outstanding balances under our credit facility were paid in full. 



For further details of the Business Combination please see Note 5 — Business Combinations in the consolidated financial statements.



Distribution of Non-Stack Assets 



In connection with the closing of the Business Combination, we completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities.  On February 8, 2018, we distributed the remainder of our non-STACK assets to AM Contributor as a dividend. We also converted the Founder Notes into equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK assets.  The balance of the Founder Notes at the time of conversion was approximately $28.3 million including accrued interest.  Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period and $0.3 million for the 2017 Predecessor Period.



Presentation of Financial and Operating Data



As a result of the Business Combination, AMR was treated as the accounting acquirer and we are the accounting acquiree and the accounting predecessor of AMR.  Pursuant to Accounting Standard Codification (“ASC”) 805, Business Combinations (“ASC 805”), the identifiable assets acquired and liabilities assumed were provisionally recorded at their estimated fair values on the acquisition date.  Fair value adjustments related to the transaction have been pushed down to us resulting in assets and liabilities being recorded at fair value as of the acquisition date.  As a result of the impact of electing pushdown accounting, the financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented.  The Successor period is from February 9, 2018 to March 31, 2018 (“Successor Period”) and the Predecessor periods are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”) and for the three months ended March 31, 2017 (“2017 Predecessor Period”).



The Company’s statement of operations subsequent to the Business Combination includes depreciation and amortization expense on the Company’s property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain other items of income and expense were also impacted. Therefore, the Company’s financial information prior to the Business Combination is not comparable to its financial information subsequent to the Business Combination.



As noted above, we distributed the remainder of our non-STACK assets to the AM Contributor in connection with the closing of the Business Combination.  The distribution of our remaining non-STACK assets during the first quarter of 2018 and the sale of our Weeks Island field during the fourth quarter of 2017 (collectively, the “non-STACK assets”) were part of the Company’s overall strategic shift to operate only in the eastern Anadarko Basin.  As a result, the Predecessor’s assets and liabilities and operating results directly related to non-STACK assets are presented as discontinued operations within the consolidated financial statements.  See Note 7 — Discontinued Operations for further discussion.



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Outlook, Market Conditions and Commodity Prices



Our revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, natural gas and natural gas liquids, which are beyond our control.  The success of our business is significantly affected by the price of oil due to our current focus on development of oil reserves and exploration for oil.



Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and it is uncertain whether the increase in market prices experienced in recent months will be sustained.  As a result, we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues.  In the event that oil, natural gas and natural gas liquids prices significantly decrease, such decrease could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of our borrowing base under our senior secured revolving credit facility.  The following table sets forth the average New York Mercantile Exchange (“NYMEX”) prices for oil and natural gas for the three months ended March 31, 2018 and 2017:





Our 2018 anticipated non-acquisition capital expenditures ranges between $500 million and $580 million.    We are currently utilizing eight drilling rigs as of May 2018, which will result in drilling between 170 and 180 gross wells in the STACK.  Following the closing of the Business Combination, we have allocated all of our 2018 capital expenditures to develop the STACK. 



Our derivative contracts are reported at fair value on our consolidated balance sheets and are sensitive to changes in the price of oil, natural gas and natural gas liquids. Changes in these derivative assets and liabilities are reported in our consolidated statements of operations as gain (loss) on derivative contracts which include both the non-cash increase and decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. We recognized a net loss on our derivative contracts of $22.6 million in the Successor Period, which includes $4.6 million in cash settlements received for derivative contracts. The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil and natural gas revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and we expect these gains and losses to continue to reflect changes in oil and natural gas prices.



The primary factors affecting our production levels are capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped reserves, enhanced completions and well recompletions, and other enhanced recovery methods. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.



Operations Update



Our STACK properties consist largely of contiguous leased acreage primarily in Kingfisher County, Oklahoma, which is the eastern portion of the Anadarko Basin referred to as the STACK, an acronym describing both its location and the multiple, stacked pay zones present in the area.  This continuously growing position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet.  The legacy operations within our acreage are primarily shallow-decline, long-lived oil fields developed on 80-acre vertical well spacing associated with waterfloods in the Oswego, Big Lime and Manning Limestones.  We continue to maintain production in these historical field pay zones. 

 

In the first quarter of 2018, we brought 28 operated horizontal wells on production of which approximately 13 were funded through our joint development agreement with BCE-STACK Development LLC (“BCE”).  We had 22 operated horizontal wells in progress as of the end of the first quarter of 2018, of which two were funded through our joint development agreement with BCE.  As of May 2018, 18 of the 22 operated horizontal wells in progress as of March 31, 2018 were on production. 



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As of March 31, 2018, we had seven drilling rigs operating in the STACK.  We currently have eight drilling rigs operating in the STACK.  We plan to continue targeting the Mississippian-age Osage, Meramec, and Manning formations and the Pennsylvanian-age Oswego formation with horizontal drilling.  We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Osage formations. 



Production from our STACK assets was an average of approximately 24,500 BOE/d net to our interest, 70% oil and natural gas liquids, for the Successor Period, 23,400 BOE/d net to our interest, 71% oil and natural gas liquids, for the 2018 Predecessor Period, and 19,300 BOE/d net to our interest, 70% oil and natural gas liquids, for the 2017 Predecessor Period. 

 

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Results of Operations: For the Periods from February 9, 2018 Through March 31, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor) Compared to Three Months Ended March 31, 2017 (Predecessor)



The tables included below set forth financial information for the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period which are distinct reporting periods as a result of the Business Combination.  The amounts below exclude operating results related to discontinued operations.



Revenues



Our oil, natural gas and natural gas liquids revenues vary as a result of changes in commodity prices and production volumes. The following table provides the components of net revenue, price and volume for the respective periods indicated. 



Oil revenues were 80%, 79% and 74% of our total E&P net revenues for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Oil revenues for the Successor Period and the 2018 Predecessor Period increased compared to the 2017 Predecessor Period due to higher average prices and an increase in production in the 2018 fiscal quarter. The higher average prices are tied to the overall increase of the oil commodity prices as discussed above.  Oil production was 52%, 54% and 54% of total production volume for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.

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Natural gas revenues were 10%, 11% and 15% of our total E&P net revenues for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Natural gas revenues for the Successor Period and the 2018 Predecessor Period decreased compared to the 2017 Predecessor Period due to lower average prices partially offset by an increase in production in the 2018 fiscal quarter. The lower average prices are tied to the overall decrease of the natural gas commodity prices as discussed above. Natural gas production was 30%, 29% and 30% of total production volume for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.



Natural gas liquid revenues were 9%, 10% and 11% of our total E&P net revenues for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Natural gas liquid revenues for the Successor Period and the 2018 Predecessor Period increased compared to the 2017 Predecessor Period due to higher average prices and an increase in production in the 2018 fiscal quarter. The higher average prices are tied to the overall increase of the oil commodity prices as discussed above.  Natural gas liquids production was 18%, 17% and 16% of total production volume for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.

Gain on sale of assets and other primarily includes the sale of seismic data for $5.9 million.

Gain (loss) on derivative contracts presented in the table below represents cash settlements related to the commodity as well as fair value changes on our oil, natural gas and natural gas liquids derivative contracts.  The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves.







Operating Expenses



The following table summarizes selected operating expense for the periods indicated:





Lease operating expense primarily consists of compression, chemicals, fuel, power and water and associated labor. Lease operating expense per BOE is $6.66 for the Successor Period, $4.91 for the 2018 Predecessor Period and $6.34 for the 2017 Predecessor Period. The increase in cost per BOE in the Successor Period was primarily due to an increase in seasonal cost and saltwater disposal fees. Freezing weather in the winter months can result in higher operating expense to prevent freezing of production equipment or shut-ins in Oklahoma. 



Marketing and transportation expense for the Successor Period, the 2018 Predecessor Period, and 2017 Predecessor represents throughput for our properties in the STACK at the Kingfisher processing facility. The increase is due to higher marketing and transportation fee charged to provide effective gathering, efficient processing and assurance that our production will continue to flow as the activity in the basin expands at the Kingfisher processing facility. 

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Production taxes for the Successor Period and 2018 Predecessor Period are higher as compared to the 2017 Predecessor Period and are related to an increase in oil, natural gas and natural gas liquids revenue. 





Exploration Expense consists primarily of geological and geophysical personnel and data, lease rental expenses, expired leases, dry hole costs and settlements of asset retirement costs in excess of estimates.  The following table shows the components of exploration expenses for the periods presented.







Depreciation, depletion and amortization expense was lower on a per BOE basis for the Successor Period as compared to the 2018 Predecessor Period and 2017 Predecessor period primarily due to an increase in the reserve base resulting from drilling success in the STACK offset by increases in the depletion base resulting from the application of pushdown accounting of the Business Combination.







General and administrative expense was $31.4 million, $24.4 million and $9.7 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.  Total general and administrative (“G&A”) expenses include non-cash charges for equity compensation of $2.8 million in the Successor Period.  See Note 16 — Equity Based Compensation for further detail on equity compensation.  G&A expenses for the Successor Period and the 2018 Predecessor Period included $20.3 million and $16.3 million, respectively, of transaction expenses primarily attributable to the consummation of the Business Combination.







Interest expense.  The following table presents information about interest expense. 







 



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Liquidity and Capital Resources



Our principal requirements for capital are to fund our day-to-day operations, exploration and development activities, and to satisfy our contractual obligations, primarily for the payment of debt interest and any amounts owed during the period related to our hedging positions.  Our main sources of liquidity and capital resources come from cash flows generated from operations, the issuance of senior unsecured notes, borrowings under our senior secured revolving credit facility and capital contributions from our parent AMR.



Our 2018 anticipated non-acquisition capital expenditures ranges between $500 million and $580 million.  We increased our capital budget for 2018 from 2017 levels in response to the improvement in the current commodity price environment. Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production, revenues and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations.  However, because a large percentage of our acreage is held by production, we have the ability to materially increase or decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage.  In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.



We strive to maintain financial flexibility and may access the debt markets as necessary to facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.  



We expect to fund our capital budget in 2018 predominantly with cash flows from operations, borrowings under our senior secured revolving credit facility and drilling and completion capital funded through our joint development agreement with BCE.  As we execute our business strategy, we will continually monitor the capital resources available to meet future financial obligations and planned capital expenditures.  We believe our cash flows provided by operating activities, cash on hand and availability under our senior secured revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned and future development drilling activities.  However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties.  We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all. 



Senior Unsecured Notes



We have $500 million in aggregate principal amount of 7.875% senior unsecured notes, or the “senior notes”, due December 15, 2024 which were issued at par by us and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016.  Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.



The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our senior secured revolving credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the senior notes.

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The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business.



Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase. The closing of the Business Combination with AMR did not constitute a change of control under the indenture governing the senior notes because certain existing owners of the Company and SRII Opco entered into an amended and restated voting agreement with respect to the voting interests in AMH GP.



The indenture contains customary events of default, including:  



As of March 31, 2018, we were in compliance with the indentures governing the senior notes.



Senior Secured Revolving Credit Facility



In connection with the consummation of the Business Combination, all indebtedness under the senior secured revolving credit facility was repaid in full.  On February 9, 2018 and in connection with the closing of the AM Contribution Agreement, we entered into the Eighth Amended and Restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate of $1.0 billion with an initial $350.0 million borrowing base. In April 2018, our borrowing base was increased to $400.0 million until the next scheduled redetermination date in October 2018.  The Eighth A&R credit facility does not permit us to borrow funds if at the time of such borrowing we are not in compliance with the financial covenants set forth in the Eighth A&R credit facility.



As of May 21, 2018, we have no outstanding borrowings under the Eighth A&R credit facility and have $21.9 million of outstanding letters of credit reimbursement obligations.



The principal amounts borrowed are payable on the maturity date of February 9, 2023. We have a choice of borrowing in Eurodollars or at the reference rate, with such borrowings bearing interest, payable quarterly for reference rate loans and one month, three months or six months period for Eurodollar loans. Eurodollar loans bear interest at a rate per annum equal to the rate at the LIBOR, plus an applicable margin ranging from 2.00% to 3.00%. Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month’s Eurodollar loans plus 1%, plus an applicable margin ranging from 1.00% to 2.00%. The borrowing base may be reduced in connection with the next redetermination of its borrowing base. The amounts outstanding under the Eighth A&R credit facility are secured by first priority liens on substantially all of the Company’s and its material operating subsidiaries’ oil and natural gas properties and associated assets and all of the equity of our material operating subsidiaries that are guarantors of the Eighth A&R credit facility. Additionally, SRII Opco and AMH GP have pledged their respective limited partner interests in us as security for our obligations. If an event of default occurs under the Eighth A&R credit facility, the administrative agent will have the right to proceed against the pledged capital stock and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.



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The Eighth A&R credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Eighth A&R credit facility permits us to make distributions to any parent entity (i) to pay for reimbursement of third party costs and expenses that are general and administrative expenses incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the tax receivable agreement. In addition, we can make restricted payments, so long as certain conditions are met, to any direct or indirect parent for the sole purpose of making a loan or capital contribution to Kingfisher in an amount up to $300 million until August 9, 2018.



The Eighth A&R credit facility also requires us to maintain the following two financial ratios:



At the execution of the Eighth A&R credit facility and in connection with the closing of the Business Combination, we are not subject to financial covenants ratios as of March 31, 2018.  We will be required to maintain financial ratios commencing on the fiscal quarter ending June 30, 2018.



The credit facility and the senior notes contain customary events of default.  If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest.  Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.



Cash flow provided by (used in) operating activities



Cash provided by (used in) operating activities was $(49.3) million, $26.5 million and $(3.9) million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.  Cash-based items of net income (loss) including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, provided approximately $0.5 million, $(2.4) million, and $23.7 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.  Working capital and other assets and liabilities resulted in a decrease of $49.8 million, and an increase of $28.9 million, for the Successor Period and the 2018 Predecessor Period respectively.  The 2017 Predecessor Period working capital and other assets and liabilities had a decrease of approximately $27.6 million.



Cash flow used in investing activities



Investing activities used cash for capital expenditures for property and equipment of approximately $129.3 million, $38.1 million and $60.6 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.



Cash flow provided by financing activities



Cash provided by financing activities was $425.3 million, $16.9 million and $62.9 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. The Successor Period included capital contributions totaling $560.3 million, offset by repayments on the Alta Mesa senior secured revolving facility totaling $134.1 million and incurred deferred financing costs of $1.0 million. The 2018 Predecessor Period included proceeds from long-term debt totaling $60.0 million, offset by repayments of long-term debt totaling $43.0 million. The 2017 Predecessor period included proceeds from long-term debt totaling $55.1 million and capital contributions totaling $7.9 million.



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Cautionary Statement Regarding Forward-Looking Statements



The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project”, the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our 2017 Annual Report and Part II, Item 1A of this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.



Forward-looking statements may include statements about:





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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids. These risks include, but are not limited to, commodity price volatility, low prices for oil, natural gas and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties and the other risks described under “Item 1A. Risk Factors” in our 2017 Annual Report and in this report.



Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers.  Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.



Should one or more of the risks or uncertainties described in the 2017 Annual Report or this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.



Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.



ITEM 3. Quantitative and Qualitative Disclosures about Market Risk



For information regarding our exposure to certain market risks, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities—Commodity Derivative Instruments” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2017 Annual Report. There have been no material changes to the disclosure regarding market risks other than as noted below. See Part I, Item 1, Notes 8 and 9 to our condensed consolidated financial statements for a description of our outstanding derivative contracts at the most recent reporting date.



The fair value of our commodity derivative contracts at March 31, 2018 was a net liability of $29.3 million. A 10% increase or decrease in oil, natural gas and natural gas liquids prices with all other factors held constant would result in a decrease or increase, respectively, in the estimated fair value (generally correlated to our estimated future net cash flows from such instruments) of our commodity derivative contracts of approximately $29.9 million (decrease in value) or $26.7 million (increase in value), respectively, as of March 31, 2018.



We are subject to interest rate risk on our variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts.  As of March 31, 2018, we have no outstanding balance under our Eighth A&R credit facility. 



ITEM 4. Controls and Procedures



Evaluation of Disclosure Controls and Procedures



In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2018 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.



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Changes in Internal Control Over Financial Reporting



The internal controls over financial reporting that existed prior to the Business Combination were reviewed by management in anticipation of the Business Combination. The company will continue to monitor the effectiveness and adequacy of internal controls over financial reporting after the business combination and implement additional controls as appropriate.



PART II — OTHER INFORMATION



ITEM 1. Legal Proceedings



See Part I, Item 1, Note 13 — Commitments and Contingencies to our condensed consolidated financial statements, which is incorporated in this item by reference.



ITEM 1A. Risk Factors



We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in the 2017 Annual Report. There have been no material changes with respect to the risk factors disclosed in the 2017 Annual Report during the quarter ended March 31, 2018.

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ITEM 6. Exhibits

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

 



 



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