Alta Mesa Holdings, LP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - Alta Mesa Holdings, LP	amhexhibit322.htm
EX-32.1 - EXHIBIT 32.1 - Alta Mesa Holdings, LP	amhexhibit321.htm
EX-31.2 - EXHIBIT 31.2 - Alta Mesa Holdings, LP	amhexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Alta Mesa Holdings, LP	amhexhibit311.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_______________________________________

FORM 10-Q

_______________________________________

(Mark One)

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

For the quarterly period ended: June 30, 2018

¨ 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

_______________________________________

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

_______________________________________



Texas	20-3565150
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
15021 Katy Freeway, Suite 400, Houston, Texas	77094
(Address of principal executive offices)	(Zip Code)

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

_______________________________________

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 x

(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 x 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)



Large accelerated filer	¨	Accelerated filer	¨	Non-accelerated filer	x	(Do not check if smaller reporting company)
Smaller reporting company	¨	Emerging growth company	x

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 x

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	Page Number
Glossary	3
Cautionary Statement Regarding Forward-Looking Statements	4
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets	6
Condensed Consolidated Statements of Operations	8
Condensed Consolidated Statements of Changes in Partners’ Capital	9
Condensed Consolidated Statements of Cash Flows	10
Notes to Condensed Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3. Quantitative and Qualitative Disclosures about Market Risk	44
Item 4. Controls and Procedures	44
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	44
Item 1A. Risk Factors	44
Item 6. Exhibits	45
Signatures	46

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Glossary of Terms

Certain terms and abbreviations used in this Quarterly Report on Form 10-Q are defined as follows:



bbl -	Barrels
bbl/d -	Barrels per day
BOE -	Barrels of oil equivalent
Btu -	British thermal units
Completion -	The installation of permanent equipment for the production of oil and gas
EBITDA -	Earnings before interest, taxes, depreciation, depletion, amortization
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses
Mbbls -	One thousand barrels
Mbbls/d -	One thousand barrels per day
MBoe/d -	One thousand barrels of oil equivalent per day
Mcf -	One thousand cubic feet
Mcf/d -	One thousand cubic feet per day
MMBtu -	One million British thermal units
MMcf -	One million cubic feet
MMcf/d -	One million cubic feet per day
NYMEX -	New York Mercantile Exchange
NGLs -	Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline
Wellbore -	A hole that is drilled to aid in the exploration and recovery of natural resources including oil or natural gas
Working interest -	An interest in a mineral property that entitles the owner of that interest to all of the share of the mineral production from the property, usually subject to a royalty
VWAP -	Volume weighted average price

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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:


•	the benefits of the Business Combination;


•	the future financial performance of the combined company following the Business Combination;


•	our business strategy;


•	our reserve quantities and the present value of our reserves;


•	our estimated purchase price and purchase price allocations;


•	our exploration and drilling prospects, inventories, projects and programs;


•	our horizontal drilling, completion and production technology;


•	our ability to replace the reserves we produce through drilling and property acquisitions;


•	our financial strategy, liquidity and capital required for our development program;


•	future oil, and natural gas prices;


•	the supply and demand for natural gas, natural gas liquids, crude oil and midstream services;


•	the timing and amount of future production of oil and natural gas;


•	our hedging strategy and results;


•	the drilling and completion of wells, including statements about future horizontal drilling plans;


•	competition and government regulation;


•	our ability to obtain permits and governmental approvals;


•	changes in the Oklahoma forced pooling system;


•	pending legal and environmental matters;


•	our future drilling plans;


•	our marketing of oil, natural gas and natural gas liquids;


•	our leasehold or business acquisitions;


•	our costs of developing our properties;


•	our liquidity and access to capital;


•	our ability to hire, train or retain qualified personnel;


•	general economic conditions;


•	our future operating results, including initial production values and liquid yields in our type curve areas;


•	the costs, terms and availability of gathering, processing, fractionation and other midstream services; and


•	our plans, objectives, expectations and intentions contained in this report that are not historical.

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

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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 occurring after the date of this Quarterly Report on Form 10-Q.

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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)

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	Successor		Predecessor
	June 30, 2018		December 31, 2017
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	74,004	$	3,660
Restricted cash	1,022		1,269
Accounts receivable, net	104,668		76,161
Other receivables	1		1,388
Receivables due from affiliate	9,068		—
Receivables due from related party	10,333		790
Note receivable due from related party	1,609		—
Prepaid expenses and other current assets	3,834		2,932
Current assets — discontinued operations	—		5,195
Derivative financial instruments	—		216
Total current assets	204,539		91,611
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	2,550,519		894,630
Other property and equipment, net	50,091		32,140
Total property and equipment, net	2,600,610		926,770
OTHER ASSETS
Deferred financing costs, net	1,285		1,787
Notes receivable due from related party	11,262		12,369
Deposits and other long-term assets	48		9,067
Non-current assets — discontinued operations	—		43,785
Derivative financial instruments	—		8
Total other assets	12,595		67,016
TOTAL ASSETS	$	2,817,744	$	1,085,397

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

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	Successor		Predecessor
	June 30, 2018		December 31, 2017
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	143,107	$	170,489
Accounts payable — affiliate	481		5,476
Advances from non-operators	6,283		5,502
Advances from related party	37,135		23,390
Asset retirement obligations	538		69
Current liabilities — discontinued operations	—		15,419
Derivative financial instruments	37,743		19,303
Total current liabilities	225,287		239,648
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	6,439		10,400
Long-term debt, net	531,584		607,440
Noncurrent liabilities — discontinued operations	—		66,862
Derivative financial instruments	6,385		1,114
Other long-term liabilities	6		5,488
Total long-term liabilities	544,414		691,304
TOTAL LIABILITIES	769,701		930,952
Commitments and Contingencies (Note 13)
PARTNERS' CAPITAL	2,048,043		154,445
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	2,817,744	$	1,085,397

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)

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	Successor			Predecessor			Successor			Predecessor
	Three			Three			February 9, 2018			January 1, 2018				Six
	Months Ended			Months Ended			Through			Through				Months Ended
	June 30, 2018			June 30, 2017			June 30, 2018			February 8, 2018				June 30, 2017
OPERATING REVENUES AND OTHER
Oil	$	75,291		$	42,348		$	115,569		$	30,972			$	89,288
Natural gas	7,980			10,642			13,190			4,276				20,233
Natural gas liquids	10,241			6,581			14,955			4,000				13,653
Other revenues	2,229			1,979			2,784			888				3,213
Total operating revenues	95,741			61,550			146,498			40,136				126,387
Gain (loss) on sale of assets and other	(63		)	—			5,916			—				—
Gain (loss) on derivative contracts	(29,219		)	18,250			(51,865		)	7,298				48,492
Total operating revenues and other	66,459			79,800			100,549			47,434				174,879
OPERATING EXPENSES
Lease operating expense	12,679			11,480			20,996			4,485				22,490
Marketing and transportation expense	11,206			6,510			16,788			3,725				12,172
Production taxes	2,606			1,184			4,021			953				2,450
Workover expense	333			1,102			1,578			423				1,690
Exploration expense	8,083			3,192			13,038			3,633				8,239
Depreciation, depletion, and amortization expense	26,509			20,110			37,445			11,784				39,088
Impairment expense	—			—			—			—				1,188
Accretion expense	161			30			263			39				126
General and administrative expense	17,811			8,293			49,270			24,352				18,029
Total operating expenses	79,388			51,901			143,399			49,394				105,472
INCOME (LOSS) FROM OPERATIONS	(12,929		)	27,899			(42,850		)	(1,960		)		69,407
OTHER INCOME (EXPENSE)
Interest expense	(10,361		)	(12,578		)	(15,557		)	(5,511		)		(24,620		)
Interest income and other	820			299			1,366			172				548
Total other income (expense), net	(9,541		)	(12,279		)	(14,191		)	(5,339		)	—	(24,072		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE STATE INCOME TAXES	(22,470		)	15,620			(57,041		)	(7,299		)		45,335
Provision for state income taxes	7			—			7			—				285
INCOME (LOSS) FROM CONTINUING OPERATIONS	(22,477		)	15,620			(57,048		)	(7,299		)		45,050
LOSS FROM DISCONTINUED OPERATIONS, NET OF STATE INCOME TAX	—			(30,934		)	—			(7,593		)		(35,449		)
NET INCOME (LOSS)	$	(22,477	)	$	(15,314	)	$	(57,048	)	$	(14,892	)		$	9,601

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)

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	Predecessor
BALANCE, DECEMBER 31, 2017	$	154,445
DISTRIBUTION OF NON-STACK ASSETS (NET LIABILITY)	33,102
NET LOSS	(14,892		)
BALANCE, FEBRUARY 8, 2018	$	172,655



	Successor
BALANCE, FEBRUARY 9, 2018	$	1,535,891
CAPITAL CONTRIBUTION	560,344
ISSUANCE OF ADDITIONAL ALTA MESA PURCHASE CONSIDERATION	9,467
EQUITY-BASED COMPENSATION	6,389
DISTRIBUTION	(7,000		)
NET LOSS	(57,048		)
BALANCE, JUNE 30, 2018	$	2,048,043

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)

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	Successor			Predecessor
	February 9, 2018			January 1, 2018			Six
	Through			Through			Months Ended
	June 30, 2018			February 8, 2018			June 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(57,048	)	$	(14,892	)	$	9,601
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion, and amortization expense	37,445			12,414			51,298
Impairment expense	—			5,560			29,124
Accretion expense	263			140			1,052
Amortization of deferred financing costs	80			171			1,456
Amortization of debt premium	(2,051		)	—			—
Equity-based compensation expense	6,389			—			—
Dry hole expense	—			(45		)	888
Expired leases	10,658			1,250			5,922
(Gain) loss on derivative contracts	51,865			(7,298		)	(48,492		)
Settlements of derivative contracts	(18,969		)	(1,661		)	254
Premium paid on derivative contracts	—			—			(520		)
Interest converted into debt	—			103			599
Interest on notes receivable due from related party	(417		)	(85		)	(406		)
Loss on sale of assets and other	63			1,923			—
Gain on acquisition of oil and gas properties	—			—			(1,626		)
Changes in assets and liabilities:
Accounts receivable	(2,923		)	(20,895		)	(11,478		)
Other receivables	1,221			(9,887		)	4,281
Receivables due from affiliate	(9,068		)	—			—
Receivables due from related party	(9,426		)	(117		)	(680		)
Prepaid expenses and other current and non-current assets	7,810			9,970			(11,644		)
Advances from related party	(10,371		)	24,116			(42,528		)
Settlement of asset retirement obligations	(806		)	(63		)	(977		)
Accounts payable — related party	(4,994		)	—			—
Accounts payable, accrued liabilities, and other liabilities	(45,210		)	25,815			7,655
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES	(45,489		)	26,519			(6,221		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment	(319,042		)	(38,096		)	(151,832		)
Acquisitions, net of cash acquired	—			—			(6,251		)
Proceeds from sale of assets and other, net	11,299			—			—
NET CASH USED IN INVESTING ACTIVITIES	(307,743		)	(38,096		)	(158,083		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuances of long-term debt	—			60,000			165,065
Repayments of long-term debt	(134,065		)	(43,000		)	(10,000		)
Additions to deferred financing costs	(1,366		)	—			(170		)
Capital distributions	(7,000		)	(68		)	—
Capital contributions	560,344			—			7,875
NET CASH PROVIDED BY FINANCING ACTIVITIES	417,913			16,932			162,770
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	64,681			5,355			(1,534		)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period	10,345			4,990			7,618
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, end of period	$	75,026		$	10,345		$	6,084

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)

NOTE 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 focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County ("STACK").

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, were both 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 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.

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

NOTE 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 June 30, 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. 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”), our 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 our assets and liabilities being recorded at fair value as of the acquisition date. As a result of the Transactions described above, 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 for the three months ended June 30, 2018 and from February 9, 2018 to June 30, 2018 (“Successor Period”), (collectively, “Successor Periods”); and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”), the three

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months ended June 30, 2017 and the six months ended June 30, 2017 (“2017 Predecessor Period”), (collectively, the (“Predecessor Periods”).

As noted above, we distributed our non-STACK assets to the AM Contributor in connection with the closing of the Business Combination. The distribution of our non-STACK assets 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, we have classified the assets and liabilities and operating results of the non-STACK assets as discontinued operations during the Predecessor Periods within the condensed consolidated financial statements. See Note 7 — Discontinued Operations (Predecessor) for further discussion.

Principles of Consolidation and Reporting. 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.

The condensed consolidated financial statements included herein as of June 30, 2018, and for the three months ended June 30, 2018 (Successor) and the period from February 9, 2018 through June 30, 2018 (Successor), the period from January 1, 2018 through February 8, 2018 (Predecessor) and the three and six months ended June 30, 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.

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.

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. Other estimates are utilized to determine amounts related to oil and natural gas revenues, the value of oil and natural gas properties, the value of other property and equipment, 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 a result of the pushdown 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 as a reduction to interest expense.

Equity-Based Compensation (Successor). The Company recognizes compensation related to all stock-based awards in the financial statements based on their estimated grant-date fair value. AMR grants various types of stock-based awards including stock options, restricted stock and performance-based restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and 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

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applicable vesting period. See Note 16 – Equity-Based Compensation (Successor) for additional information regarding the Company’s equity based compensation.

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):

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	Successor		Predecessor
	June 30, 2018		December 31, 2017
Cash and cash equivalents	$	74,004	$	3,660
Restricted cash	1,022		1,269
Cash of discontinued operations	—		61
Total cash, cash equivalents and restricted cash	$	75,026	$	4,990

Recent Accounting Pronouncements Issued But Not Yet Adopted. 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. Subsequent to the issuance of ASU 2014-09, the FASB amended the standard to provide clarification 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. The core principle of the new amended standard is that a company will recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration to which the company is entitled in exchange for those services. In order to comply with the new standard, companies will need to (i) identify performance obligations in each contract, (ii) estimate the amount of variable consideration to include in the transaction price and (iii) allocate the transaction price to each separate performance obligation.

ASU 2014-09, as amended, is 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.

ASU 2014-09 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 previously elected to use the extended transition period to defer implementation of the new standard until the first quarter of 2019 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. AMR, our parent company, is also an emerging growth company, but will cease to be an emerging growth company on December 31, 2018, which will require them to adopt ASU 2014-09 on December 31, 2018, with modified retroactive implementation as of January 1, 2018. Accordingly, we will also adopt ASU 2014-09, at the same time as our parent company.

We are in the process of assessing our contracts and evaluating the impact on our 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 revenues and expenses under the new gross-versus-net presentation guidance and on our current accounting policies, including the need to make changes to relevant business practices and internal controls, if needed.

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 (except for 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. 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 are evaluating the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and implementation 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 a change in the amount of lease 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.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. As an emerging growth company, we had elected to use the extended transition period to defer adoption of this standard until 2019. However, our parent company will lose its emerging growth status, effective December 31, 2018. Accordingly, we will be required to adopt this new standard on December 31, 2018, when adopted by our parent company. The adoption of this guidance will not impact our financial position or results of operations but could result in presentational changes in our consolidated statements of cash flows.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model used today. With respect to our trade receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, which will be effective for us in fiscal years beginning after December 15, 2019, also requires additional disclosures regarding the credit quality of our trade receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

Reclassifications. Certain prior year amounts have been reclassified to conform to the current year presentation.

NOTE 3 — SUPPLEMENTAL CASH FLOW INFORMATION

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

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	Successor			Predecessor
	February 9, 2018			January 1, 2018		Six
	Through			Through		Months Ended
	June 30, 2018			February 8, 2018		June 30, 2017
Supplemental cash flow information:
Cash paid for interest	$	21,216		$	1,145	23,452
Cash paid for state income taxes	6			—		—
Non-cash investing and financing activities:
Change in asset retirement obligations	877			—		235
Asset retirement obligations assumed, purchased properties	—					89
Change in accruals or liabilities for capital expenditures	(27,646		)	4,712		37,494
Distribution of non-STACK assets (net liability)	—			33,102		—

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NOTE 4 — ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following (in thousands):

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	Successor			Predecessor
	June 30, 2018			December 31, 2017
Oil, natural gas and natural gas liquids sales	$	30,126		$	26,916
Joint interest billings	34,762			13,821
Pooling interest (1)	39,843			35,839
Allowance for doubtful accounts	(63		)	(415		)
Total accounts receivable, net	$	104,668		$	76,161

_________________

(1)

Pooling interest relates to Oklahoma’s forced pooling process which requires the Company to offer mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents costs of unbilled interests on wells which the Company incurred before the pooling process was completed. Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties.

NOTE 5 — BUSINESS COMBINATION

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

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.

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”):

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20-Day VWAP		Earn-Out Consideration
$14.00		10,714,285 Common Units
$16.00		9,375,000 Common Units
$18.00		13,888,889 Common Units
$20.00		12,500,000 Common Units

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 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 balance under the senior secured revolving credit facility described in Note 11 — Long Term Debt, Net.

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Pursuant to the AM Contribution Agreement, AM Contributor delivered a final closing statement during the second quarter of 2018. Based on the final closing statement, the AM Contributor received an additional 1,197,934 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 our 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 of our long-term assets and liabilities are preliminary in nature and are subject to change as additional information becomes available and as additional analysis is performed. Pursuant to ASC 805, finalization of the values is to be completed within one year of the Acquisition Date.

Preliminary Estimated Purchase Price

AMR’s preliminary estimated purchase price consideration for Alta Mesa was as follows (in thousands):

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	February 9, 2018 (As initially reported)		Measurement Period Adjustment ⁽¹⁾		February 9, 2018 (As adjusted)
Preliminary Purchase Consideration: ⁽²⁾
SRII Opco Common Units issued ⁽³⁾	$	1,251,782	$	9,467	$	1,261,249
Estimated fair value of contingent earn-out purchase consideration ⁽⁴⁾	284,109		—		284,109
Total purchase price consideration	$	1,535,891	$	9,467	$	1,545,358

_________________


(1)	The measurement period adjustment relates to the issuance of 1,197,934 of additional SRII Opco Common Units, valued at approximately $7.90 per unit, to the AM Contributor based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 (Successor).


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


(3)	At closing, the Riverstone Contributor received consideration of 20,000,000 SRII Opco Common Units and the AM Contributor received consideration of 138,402,398 SRII Opco Common Units. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity.

(4)

For a period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of AMR Class C Common Stock) if the 20-day VWAP of the Class A Common Stock of AMR equals or exceeds the specified prices pursuant to the AM Contribution Agreement. Pursuant to ASC 805 and ASC 480, Distinguishing Liabilities from Equity (“ASC 480”), we have determined that the fair value of the earn-out consideration was approximately $284.1 million, which was classified as equity. The fair value of the contingent equity earn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to AMR (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining contractual term of the contingent liability earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.

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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 (in thousands):

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	February 9, 2018 (As initially reported)		Measurement Period Adjustment ⁽¹⁾		February 9, 2018 (As adjusted)
Estimated Fair Value of Assets Acquired ⁽²⁾
Cash, cash equivalents and short term restricted cash	$	10,345	$	—	$	10,345
Accounts receivable	101,745		—		101,745
Other receivables	1,222		—		1,222
Receivables due from related party	907		—		907
Prepaid expenses and other current assets	1,405		—		1,405
Derivative financial instruments	352		—		352
Property and equipment: ⁽³⁾
Oil and natural gas properties, successful efforts	2,314,858		9,467		2,324,325
Other property and equipment, net	43,318		—		43,318
Notes receivable due from related party	12,454		—		12,454
Deposits and other long-term assets	10,286		—		10,286
Total fair value of assets acquired	2,496,892		9,467		2,506,359
Estimated Fair Value of Liabilities Assumed ⁽²⁾
Accounts payable and accrued liabilities	210,867		—		210,867
Accounts payable — affiliate	5,476		—		5,476
Advances from non-operators	6,803		—		6,803
Advances from related party	47,506		—		47,506
Asset retirement obligations ⁽³⁾	5,998		—		5,998
Derivative financial instruments	11,585		—		11,585
Long-term debt ⁽⁴⁾	667,700		—		667,700
Other long-term liabilities	5,066		—		5,066
Total fair value of liabilities assumed	961,001		—		961,001
Total consideration and fair value	$	1,535,891	$	9,467	$	1,545,358

_________________


(1)	The measurement period adjustment is recognized in the reporting period in which the adjustment was determined and calculated as if the accounting had been completed at the acquisition date.


(2)	The assets acquired and liabilities assumed relate to Alta Mesa’s STACK assets.

(3)

The estimated fair values of oil and natural gas properties and asset retirement obligations were determined using valuation techniques that convert future cash flows to a single discounted amount and involve the use of certain inputs that are not observable in the market (Level 3 inputs). Significant inputs include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discount rates and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation. Actual results may vary from these estimates.

(4)

Represents the approximate fair value as of the acquisition date of Alta Mesa’s $500 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million, based on Level 1 inputs, and outstanding borrowings under the Eighth A&R credit facility (described in Note 11 — Long Term Debt, Net) of approximately $134.1 million as of the acquisition date.

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NOTE 6 — PROPERTY AND EQUIPMENT

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



	Successor			Predecessor
	June 30, 2018			December 31, 2017
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	891,787		$	84,590
Accumulated impairment of unproved properties	—			—
Unproved properties, net	891,787			84,590
Proved oil and natural gas properties	1,695,596			1,061,105
Accumulated depreciation, depletion, amortization and impairment	(36,864		)	(251,065		)
Proved oil and natural gas properties, net	1,658,732			810,040
TOTAL OIL AND NATURAL GAS PROPERTIES, net	2,550,519			894,630
OTHER PROPERTY AND EQUIPMENT
Land	5,059			2,912
Salt water disposal system	44,028			30,990
Office furniture and equipment, vehicles	1,585			20,008
Accumulated depreciation	(581		)	(21,770		)
OTHER PROPERTY AND EQUIPMENT, net	50,091			32,140
TOTAL PROPERTY AND EQUIPMENT, net	$	2,600,610		$	926,770

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).

NOTE 7 — DISCONTINUED OPERATIONS (Predecessor)

We distributed our non-STACK assets and related liabilities to the AM Contributor immediately prior to the Closing Date of the Business Combination. The distribution of our non-STACK assets and related liabilities and the sale of our Weeks Island field during the fourth quarter of 2017 were part of our 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 the 2017 Predecessor Periods.

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 – Description of Business, the Founder Notes were converted into an equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK asset 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 and $0.6 million for the three months ended June 30, 2017 (Predecessor) and 2017 Predecessor Period, respectively.

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The assets and liabilities directly related to the non-STACK assets presented as discontinued operations in the consolidated balance sheets were as follows (in thousands):

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	Predecessor
	December 31, 2017
Assets associated with discontinued operations:
Current assets
Cash	$	61
Accounts receivable	4,980
Other receivables	154
Total current assets	5,195
Noncurrent assets
Investments in LLC - Cost	9,000
Proved oil and natural gas properties, net	15,408
Unproved properties, net	15,504
Land	2,706
Other long-term assets	1,167
Total noncurrent assets	43,785
Total assets associated with discontinued operations	$	48,980

Liabilities associated with discontinued operations:
Current liabilities
Accounts payable and accrued liabilities	$	7,882
Asset retirement obligations	7,537
Total current liabilities	15,419
Noncurrent liabilities
Asset retirement obligations, net of current	37,049
Founder's note	28,166
Other long-term liabilities	1,647
Total noncurrent liabilities	66,862
Total liabilities associated with discontinued operations	$	82,281

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The operating results directly related to the non-STACK assets and liabilities presented as discontinued operations within the consolidated financial statements were as follows (in thousands):

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	Predecessor
	Three Months Ended June 30, 2017			January 1, 2018 Through February 8, 2018			Six Months Ended June 30, 2017
Operating revenues and other:
Oil	$	12,723		$	1,617		$	25,128
Natural gas	2,494			1,023			5,588
Natural gas liquids	495			236			1,042
Other revenues	86			16			202
Total operating revenues	15,798			2,892			31,960
Loss on sale of assets	—			(1,923		)	—
Gain on acquisition of oil and gas properties	1,626			—			1,626
Total operating revenues and other	17,424			969			33,586
Operating expenses:
Lease operating expense	7,096			1,770			15,056
Marketing and transportation expense	347			83			728
Production taxes	1,855			167			3,657
Workover expense	913			127			1,708
Exploration expense	3,073			—			6,168
Depreciation, depletion and amortization	6,384			630			12,210
Impairment expense	27,904			5,560			27,936
Accretion expense	450			101			926
General and administrative expense	35			21			47
Total operating expenses	48,057			8,459			68,436
Interest expense	(301		)	(103		)	(599		)
Loss from discontinued operations, net of state income taxes	$	(30,934	)	$	(7,593	)	$	(35,449	)

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

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	Predecessor
		January 1, 2018 Through February 8, 2018			Six Months Ended June 30, 2017
Total operating cash flows of discontinued operations		$	(6,838	)	$	8,761
Total investing cash flows of discontinued operations		(570		)	(10,512		)

NOTE 8 — FAIR VALUE MEASUREMENTS

We follow ASC 820, which 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.

In connection with our acquisition, we recorded the fair value of our $500 million unsecured senior notes at $533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $530.1 million at June 30, 2018 (Successor). 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 inputs used to determine 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. During the six months ended June 30, 2017, certain of our 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. 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 $0.9 million, zero and $0.6 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 June 30, 2018 and December 31, 2017, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:



	Level 1	Level 2		Level 3	Total
	(in thousands)
At June 30, 2018: (Successor)
Financial Assets:
Derivative contracts for oil and natural gas	—	$	4,692	—	$	4,692
Financial Liabilities:
Derivative contracts for oil and natural gas	—	$	48,820	—	$	48,820
At December 31, 2017: (Predecessor)
Financial Assets:
Derivative contracts for oil and natural gas	—	$	4,416	—	$	4,416
Financial Liabilities:
Derivative contracts for oil and natural gas	—	$	24,609	—	$	24,609

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

NOTE 9 — DERIVATIVE FINANCIAL INSTRUMENTS

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 derivative contracts are executed by affiliates of our lenders under the senior secured revolving credit facility described in Note 11— Long Term Debt, Net, 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 derivative 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 equivalent to volumes in gallons (gal) per month. The derivative 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

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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. As of June 30, 2018, we are not a party to any interest rate swap agreements.

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.

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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	June 30, 2018 (Successor)
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	1,934	$	(1,934	)	$	—
Derivative financial instruments, long-term assets	2,758		(2,758		)	—
Total	$	4,692	$	(4,692	)	$	—

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Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	39,677	$	(1,934	)	$	37,743
Derivative financial instruments, long-term liabilities	9,143		(2,758		)	6,385
Total	$	48,820	$	(4,692	)	$	44,128

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	December 31, 2017 (Predecessor)
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	1,406	$	(1,190	)	$	216
Derivative financial instruments, long-term assets	3,010		(3,002		)	8
Total	$	4,416	$	(4,192	)	$	224

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Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	20,493	$	(1,190	)	$	19,303
Derivative financial instruments, long-term liabilities	4,116		(3,002		)	1,114
Total	$	24,609	$	(4,192	)	$	20,417

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

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	Successor			Predecessor			Successor			Predecessor
Derivatives not	Three			Three			February 9, 2018			January 1, 2018		Six
designated as hedging	Months Ended			Months Ended			Through			Through		Months Ended
instruments under ASC 815	June 30, 2018			June 30, 2017			June 30, 2018			February 8, 2018		June 30, 2017
Gain (loss) on derivative contracts
Oil commodity contracts	$	(28,712	)	$	16,451		$	(51,291	)	$	5,431	$	42,537
Natural gas commodity contracts	(507		)	1,830			(574		)	1,867		5,728
Natural gas liquids commodity contracts	—			(31		)	—			—		227
Total gain (loss) on derivative contracts	$	(29,219	)	$	18,250		$	(51,865	)	$	7,298	$	48,492

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, under certain circumstances, 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 described in Note 11 — Long Term Debt, Net.

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

We had the following open derivative contracts for crude oil at June 30, 2018:

OIL DERIVATIVE CONTRACTS

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	Volume in bbls	Weighted Average		Range
Settlement Period and Type of Contract	Volume in bbls	Weighted Average		High		Low
2018
Price Swap Contracts	1,104,000	$	53.55	$	61.26	$	50.27
Collar Contracts
Short Call Options	1,104,000	61.28		64.60		60.50
Long Put Options	1,104,000	51.67		60.00		50.00
Short Put Options	1,104,000	42.08		52.50		40.00
2019
Price Swap Contracts	182,500	63.03		63.03		63.03
Collar Contracts
Short Call Options	2,701,000	66.31		75.20		56.50
Long Put Options	2,883,500	53.80		62.00		50.00
Short Put Options	2,883,500	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	183,000	60.20		60.20		60.20
Long Put Options	549,000	50.67		51.00		50.00
Short Put Options	549,000	40.00		40.00		40.00

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We had the following open derivative contracts for natural gas at June 30, 2018:

NATURAL GAS DERIVATIVE CONTRACTS

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	Volume in MMBtu	Weighted Average		Range
Settlement Period and Type of Contract	Volume in MMBtu	Weighted Average		High		Low
2018
Price Swap Contracts	4,142,500	$	2.89	$	3.09	$	2.75
Collar Contracts
Short Call Options	2,292,500	3.32		3.75		3.14
Long Put Options	1,987,500	2.86		2.90		2.75
Short Put Options	610,000	2.40		2.40		2.40
2019
Price Swap Contracts	5,405,000	2.72		3.09		2.64
Collar Contracts
Short Call Options	2,475,000	3.38		3.75		3.25
Long Put Options	2,025,000	2.90		2.90		2.90
Short Put Options	900,000	2.40		2.40		2.40

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 June 30, 2018:

NATURAL GAS BASIS SWAP DERIVATIVE CONTRACTS



Volume in MMBtu⁽¹⁾	Reference Price 1 ⁽¹⁾	Reference Price 2 ⁽¹⁾	Period			Weighted Average Spread ($ per MMBtu)
152,500	WAHA	NYMEX Henry Hub	Nov '18	—	Dec '18	$	(1.05	)
225,000	WAHA	NYMEX Henry Hub	Jan '19	—	Mar '19	(1.05		)
4,600,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jul '18	—	Dec '18	(0.66		)
6,530,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '19	—	Oct '19	(0.74		)

_________________


(1)	Represents short swaps that fix the basis differentials between WAHA, Tex/OKL Panhandle Eastern Pipeline (“PEPL”) and NYMEX Henry Hub.

OIL BASIS SWAP DERIVATIVE CONTRACTS

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Volume in bbl ⁽¹⁾

Reference Price 1 ⁽¹⁾

Reference Price 2 ⁽¹⁾

Period

Weighted

Average Spread

($ per bbl)

1,104,000

CMA Oil

WTI

Jul '18

—

Dec '18

(0.54

)

_________________


(1)	Represents basis swaps for the basis differentials between NYMEX CMA (Calendar Monthly Average) Roll that reconcile the trade month versus the delivery month for physical contract pricing and WTI.

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NOTE 10 — ASSET RETIREMENT OBLIGATIONS

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

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	2018
Balance, as of January 1 (Predecessor)	$	10,469
Liabilities settled	(63		)
Revisions to estimates	63
Accretion expense	39
Balance, as of February 8 (Predecessor)	$	10,508

Balance, as of February 9 (Successor)	$	—
Liabilities assumed from Business Combination	5,998
Liabilities incurred	877
Liabilities settled	(806		)
Liabilities transferred in sale of properties	(20		)
Revisions to estimates	665
Accretion expense	263
Balance, as of June 30 (Successor)	6,977
Less: Current portion	538
Long-term portion	$	6,439

NOTE 11 — LONG-TERM DEBT, NET

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

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	Successor		Predecessor
	June 30, 2018		December 31, 2017

Senior secured revolving credit facility	$	—	$	117,065
7.875% senior unsecured notes due 2024	500,000		500,000
Unamortized premium on senior unsecured notes	31,584		—
Unamortized deferred financing costs	—		(9,625		)
Total long-term debt, net	$	531,584	$	607,440

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 June 30, 2018, we have no borrowings under the Eighth A&R credit facility and have $21.9 million of outstanding letters of credit.

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 or, for Eurodollar loans, in one, three or six-month tranches. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, plus a 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 or (iii) the rate for one-

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month Eurodollar loans plus 1.00%, 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 the 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 collateral and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.

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 general and administrative expenses ("G&A") 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.

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


•	a current ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of our consolidated current assets to our consolidated current liabilities of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

•

a leverage ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) annualized by multiplying EBITDAX for the period of (a) the fiscal quarter ending June 30, 2018 times 4, (b) the two fiscal quarter periods ending September 30, 2018 times 2 (c) the three fiscal quarter periods ending December 31, 2018 times 4/3rds and (d) for each fiscal quarter on or after March 31, 2019, EBITDAX for the four-fiscal quarter period then ended, of not greater than 4.0 to 1.0.

As of June 30, 2018, we were in compliance with the financial ratios described above.

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”) 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. 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 for an amount of cash not greater than the net cash proceeds from certain equity offerings at a 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

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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.

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:


•	default in any payment of interest on the senior notes when due, continued for 30 days;


•	default in the payment of principal or premium, if any, on the senior notes when due;


•	failure by the Issuers or any subsidiary guarantor to comply with its obligations under the indenture;


•	default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Issuers or restricted subsidiaries;


•	certain events of bankruptcy, insolvency or reorganization of the Issuers or restricted subsidiaries; and


•	failure by the Issuers or certain subsidiaries that would constitute a payment of final judgment aggregating in excess of $20 million.

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 June 30, 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 recognized in interest expense was $1.2 million and $2.1 million for the three months ended June 30, 2018 (Successor) and the Successor Period, respectively. The unamortized bond premium related to the senior notes is included as a component of long-term debt in the consolidated balance sheet as of June 30, 2018.

Deferred financing costs. As of December 31, 2017 (Predecessor), we had $11.4 million of unamortized deferred financing costs related to both our senior notes and the Eight A&R credit facility. As a result of the Business Combination, our unamortized deferred financing costs have been adjusted to a fair value of zero at February 9, 2018. During the Successor Period, we incurred additional deferred financing costs related to the Eighth A&R credit facility of $1.4 million. These costs are reflected as deferred financing costs, net in other noncurrent assets in the consolidated balance sheets as of June 30, 2018. The amortization of the deferred financing costs is included in interest expense in the consolidated statements of operations. For the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), the amortization of deferred financing costs was $0.1 million and $0.5 million, respectively. For the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, the amortization of deferred financing costs was $0.1 million, $0.2 million and $1.5 million, respectively.

NOTE 12 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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

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	Successor		Predecessor
	June 30, 2018		December 31, 2017
Accruals for capital expenditures	$	61,982	$	48,771
Revenues and royalties payable	36,451		29,514
Accruals for operating expenses/taxes	8,880		14,632
Accrued interest	1,760		2,587
Derivative settlement payable	4,510		2,106
Other	4,524		4,301
Total accrued liabilities	118,107		101,911
Accounts payable	25,000		68,578
Accounts payable and accrued liabilities	$	143,107	$	170,489

NOTE 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 June 30, 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. During January 2018, approximately $4.7 million was paid to fund the settlement. On March 12, 2018, the class settlement was approved by the Court.

Litigation (Successor). 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,

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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 closing of the Business Combination was approximately $10.6 million and such amount was recorded in G&A in the Successor Period. Following the closing of the Business Combination, the Plan was terminated.

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.

Commitments

We lease office space and certain field equipment such as compressors, under long-term operating lease agreements. On April 1, 2018, we amended the lease agreement for our corporate headquarters located in Houston, Texas. The amended lease agreement provides for additional office space and extends the original lease term through April 2028. Due to the amendment, we have additional lease commitment obligations of approximately $17.6 million through April 2028. Any initial rent-free months are amortized over the life of the lease.

The Company has entered into certain firm transportation contracts that extend through 2028. At June 30, 2018, the future minimum commitments related to these contracts were approximately $1.7 million a year.

NOTE 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.

NOTE 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 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.

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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.

NOTE 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 made on February 9, 2018. During the Successor Period, AMR recognized non-cash stock-based compensation expense of $6.4 million resulting from stock options, restricted stock, and RSUs awards which is included in general and administrative expense in the accompanying consolidated statements of operations. 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.

Stock options. Options that have been granted under the LTIP expire seven years from the grant date and generally vest in one-third increments each year on the anniversary date following the date of grant, based on continued employment. The exercise price for an option granted under the LTIP may not be below the fair value of AMR’s Class A Common Stock on the grant date.

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

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	Successor
	Stock Options		Weighted Average Grant - Date Fair Value		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of February 9, 2018	—		$	—	—	—
Granted	4,538,004		4.51		—	—
Exercised	—		—		—	—
Forfeited or expired	(29,997	)	4.62		—	—
Outstanding as of June 30, 2018	4,508,007		$	4.51	6.7	$	20,331
Exercisable as of June 30, 2018	—		$	—	—	$	—

Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable three-year 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

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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:

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	Successor
	February 9, 2018 Through June 30, 2018
Expected term (in years)	4.5
Expected stock volatility	64.6	%
Dividend yield	—
Risk-free interest rate	2.4	%

As of June 30, 2018, there was $17.7 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 2.7 years.

Restricted stock. Restricted stock granted to employees generally vests in one-third increments each year on the anniversary date following the date of grant, based on continued employment. Prior to vesting, no dividends are paid and the shares may not be traded.

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

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	Successor
	Restricted Stock Awards		Weighted Average Grant - Date Fair Value per share
Outstanding as of February 9, 2018	—		$	—
Granted	1,335,550		8.56
Vested	—		—
Forfeited or expired	(13,332	)	8.94
Outstanding as of June 30, 2018	1,322,218		$	8.56

Compensation cost for restricted shares is based upon the grant-date market value of the award, recognized ratably over the applicable three-year vesting period, subject to the employee's continued service. Unrecognized compensation cost related to unvested restricted shares at June 30, 2018 was $9.9 million which the Company expects to recognize over a weighted average remaining period of 2.7 years.

Restricted stock units. The Company also grants performance-based restricted stock units (“PSUs”) to key employees under the LTIP. PSUs granted during the period will vest over three years at 20% during the first year, 30% during the second year and 50% during the third year. The number of PSUs vesting each year will be based on the achievement of annual company-specified performance goals and objectives applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that vest can range from 0% and 200% of the target grant applicable to each vesting period. For accounting purposes, the Company will only recognize PSUs granted when the specified performance thresholds for future periods have been established. For PSUs granted during the period February 9, 2018 to June 30, 2018, only the performance goals and objectives for 2018 have been established to date. Those 2018 performance goals are related to the Company achieving a specified level of EBITDAX for the period ended December 31, 2018.

The following summary provides information about the target number of PSUs granted during the Successor Period:

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	Successor
	PSUs			Weighted Average Grant - Date Fair Value per unit
Outstanding as of February 9, 2018	—			$	—
Granted	764,951			8.76
Vested	—			—
Forfeited or expired	(3,555	)		8.94
Outstanding as of June 30, 2018	761,396		—	$	8.76

As of June 30, 2018, there was $3.0 million of unrecognized compensation cost related to the unvested PSUs which we expect to recognize on a pro rata basis over a weighted average remaining period of 0.5 years.

NOTE 17 — RELATED PARTY TRANSACTIONS

On January 13, 2016, our wholly-owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “joint development agreement”), with BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The drilling program initially called for the development of forty identified well locations, which developed in two tranches of twenty wells each. The parties subsequently agreed to add a third and fourth tranche of investment that will allow for the drilling of an additional forty wells.

Under the joint development agreement, as amended on December 31, 2016, BCE committed to fund 100% of our working interest share up to a maximum of an average of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding the aggregate limit of $64 million in any tranche. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, Alta Mesa and BCE will each bear its respective proportionate working interest share of all subsequent costs and expenses related to such joint well. Mr. William McMullen, one of our former directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill the additional wells under the joint development agreement. As of June 30, 2018, 52 joint wells have been drilled or spudded leaving 28 wells to be drilled under the joint development agreement. As of June 30, 2018 (Successor), and December 31, 2017 (Predecessor), $37.1 million and $23.4 million, respectively, in advances from related party were reflected in our consolidated balance sheets, which represents net advances remaining from BCE for their working interest share of the drilling and development cost as part of the joint development agreement. BCE may request refunds of certain advances, as they did subsequent to June 30, 2018, if funded wells previously on the drilling schedule were subsequently removed. At the request of BCE, approximately $32.4 million of advances for such wells was refunded on July 26, 2018. On August 3, 2018, replacement AFEs were issued to BCE for another 10 wells to be drilled this year with a cash call made to BCE for approximately $26.0 million.

On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with Kingfisher. The Gas Gathering and Processing Agreement was subsequently amended on February 3, 2017, effective as of December 1, 2016, and thereafter amended on June 29, 2018, effective as of April 1, 2018. The recent amendment to the Gas Gathering and Processing Agreement impacts our net NGL production volumes but will not impact our consolidated financial statements.

Effective June 1, 2018, we entered into a Marketing Services Agreement with ARM Energy Management, LLC ("AEM") pursuant to which AEM markets our oil, natural gas and natural gas liquids and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location and quality taken into account. AEM remits monthly collections on these sales to us, and receives a marketing fee. In addition, AEM markets our firm transportation on the ONEOK Gas Transportation, L.L.C. system for an asset management fee. The AM Contributor owns less than 10% of AEM. For the period ended June 30, 2018, we paid AEM $0.2 million for our share of the marketing fees.

NOTE 18 — SUBSIDIARY GUARANTORS

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All of our wholly-owned subsidiaries are guarantors under the terms of the senior notes and the Eighth A&R credit facility. Our condensed consolidated financial statements reflect the financial position of these subsidiary guarantors. As the parent company to these subsidiaries, 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.

NOTE 19 — SUBSEQUENT EVENTS

On August 13, 2018, the Alta Mesa Credit Facility was amended. Certain changes were made to the facility’s negative covenants related to restricted payments. The facility size, borrowing base, borrowing rates and financial covenants were unchanged.

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

As of June 30, 2018, we have assembled a highly contiguous position of approximately 130,000 net acres in the up-dip, naturally-fractured oil portion of the STACK, primarily in eastern Kingfisher County and Major County, Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. We continue to acquire acreage within and adjacent to our acreage footprint with the goal of operating the drilling, completion and production operations in such locations. At present, we are operating eight horizontal drilling rigs in the STACK with plans to increase the number of rigs by the end of 2018.

Additional information relating to the acquisition of Alta Mesa by Alta Mesa Resources, Inc. and certain other transactions that occurred on February 9, 2018, may be found in Note 1 - Description of Business and Note 5 - Business Combination of the Notes to Condensed Consolidated Financial Statements. In connection with the closing of the business combination described in Note 5, we also distributed our non-STACK assets and related liabilities to High Mesa Holdings, LP (the "AM Contributor"), which is more fully described in Note 7 - Discontinued Operations (Predecessor) of the Notes to Condensed Consolidated Financial Statements, relating to discontinued operations.

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 NGLs prices significantly decrease, such decreases 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 capacity under the Eighth A&R credit facility. The following table sets forth the average New York Mercantile Exchange prices for oil and natural gas for the three and six months ended June 30, 2018 and 2017:

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	Three Months Ended June 30,
	2018		2017		Change			%
Average NYMEX daily prices:
Oil (per bbl)	$	67.91	$	48.15	$	19.76		41	%
Natural gas (per MMBtu)	$	2.83	$	3.14	$	(0.31	)	(10	)%



	Six Months Ended June 30,
	2018		2017		Change			%
Average NYMEX daily prices:
Oil (per bbl)	$	65.40	$	49.95	$	15.45		31	%
Natural gas (per MMBtu)	$	2.84	$	3.10	$	(0.26	)	(8	)%

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 NGLs. 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. For the three months ended June 30, 2018 (Successor), we recognized a net loss on our derivative contracts of $29.2 million, which includes $14.4 million in cash settlements received for derivative contracts. We recognized a net loss on our derivative contracts of $51.9 million in the Successor Period, which includes $19.0 million in cash settlements received for derivative contracts. The objective of our hedging program is to produce, over time, 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 the impact of changes in oil and natural gas prices.

Operations Update

Our STACK properties consist largely of contiguous leased acreage in Kingfisher County and Major County, Oklahoma, which is the eastern portion of the Anadarko Basin referred to as the STACK. 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.

During the three months ended June 30, 2018, we brought 48 operated horizontal wells on production of which 4 were funded through our joint development agreement with BCE-STACK Development LLC (“BCE”). We had 25 operated horizontal wells in progress as of June 30, 2018, of which 1 was funded through our joint development agreement with BCE. As of August 1, 2018, 3 of the 25 operated horizontal wells in progress as of June 30, 2018 were on production.

As of June 30, 2018, we had 8 drilling rigs operating in the STACK focused on oil and gas drilling and 1 additional drilling rig targeting salt water disposal well drilling. At the beginning of August 2018, we had 8 drilling rigs operating in the STACK, but have begun work on adding a ninth drilling rig before year end. 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 as follows:



	Successor		Predecessor		Successor		Predecessor
	Three		Three		February 9, 2018		January 1, 2018		Six
	Months Ended		Months Ended		Through		Through		Months Ended
	June 30, 2018		June 30, 2017		June 30, 2018		February 8, 2018		June 30, 2017
Average, net to our interest (MBOE/d)	25.6		20.5		25.2		23.4		19.9
Percentage of oil and NGLs	72	%	65	%	71	%	71	%	68	%

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Results of Operations

For the Three Months Ended June 30, 2018 (Successor) Compared to Three Months Ended June 30, 2017 (Predecessor)

The tables included below set forth financial information for the three months ended June 30, 2018 (Successor) and June 30, 2017 (Predecessor). The amounts below exclude operating results related to discontinued operations.

Our oil, natural gas and NGLs revenues vary as a result of changes in commodity prices and production volumes. The following table summarizes our E&P revenues and production data for the periods presented:໿

໿



	Successor			Predecessor
	Three Months Ended June 30, 2018			Three Months Ended June 30, 2017
Net sales revenues (in thousands, except per unit data)
Oil sales	$	75,291		$	42,348
Natural gas sales	7,980			10,642
Natural gas liquids sales	10,241			6,581
Total net sales revenues	$	93,512		$	59,571

Net production:
Oil (Mbbls)	1,123			903
Natural gas (MMcf)	3,944			3,886
NGLs (Mbbls)	554			314
Total (MBoe)	2,334			1,865

Average net daily production volume:
Oil (Mbbls/d)	12.3			9.9
Natural gas (MMcf/d)	43.3			42.7
NGLs (Mbbls/d)	6.1			3.4
Total (MBoe/d)	25.6			20.5

Average sales prices:
Oil (per bbl)	$	67.09		$	46.90
Effect of derivative settlements on average price (per bbl)	(12.80		)	1.68
Oil, net of hedging (per bbl)	$	54.29		$	48.58

Natural gas (per Mcf)	$	2.02		$	2.74
Effect of derivative settlements on average price (per Mcf)	—			0.22
Natural gas, net of hedging (per Mcf)	$	2.02		$	2.96

Natural gas liquids (per bbl)	$	18.47		$	20.97
Effect of derivative settlements on average price (per bbl)	—			(0.51		)
Natural gas liquids, net of hedging (per bbl)	$	18.47		$	20.46

Oil revenues were 81% and 71% of our total net sales revenues for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively. Oil revenues for the three months ended June 30, 2018 (Successor) increased approximately $32.9 million, or 78%, as compared to the three months ended June 30, 2017 (Predecessor) due to higher average prices and an increase in production. The higher average prices are tied to the overall increase in oil commodity prices as discussed above. Oil production was 48% and 48% of total BOE production volume for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively.

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Natural gas revenues were 9% and 18% of our total net sales revenues for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively. Natural gas revenues for the three months ended June 30, 2018 (Successor) decreased approximately $2.7 million, or 25%, as compared to June 30, 2017 (Predecessor) due to lower average prices partially offset by an increase in production. The lower average prices are tied to the overall decrease in natural gas commodity prices as discussed above. Natural gas production was 28% and 35% of total BOE production volume for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively.

Natural gas liquids revenues were 11% and 11% of our total sales net revenues for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively. Natural gas liquids revenues for the three months ended June 30, 2018 (Successor) increased approximately $3.7 million, or 56%, as compared to June 30, 2017 (Predecessor) due to an increase in production partially offset by lower prices. Natural gas liquids production was 24% and 17% of total BOE production volume for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively. The increase in production volume was primarily due to (i) increased BOE production of oil and natural gas and (ii) an amended contract, commencing in the second quarter of 2018, which allows for a greater recovery of ethane.

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 open 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.



	Successor			Predecessor
	Three Months Ended June 30, 2018			Three Months Ended June 30, 2017
Gain (loss) on derivative contracts (in thousands):
Oil	$	(14,362	)	$	1,518
Natural gas	3			863
Natural gas liquids	—			(158		)
Total cash settlements	(14,359		)	2,223
Valuation changes	(14,860		)	16,027
Total gain (loss) on derivative contracts	$	(29,219	)	$	18,250

Operating Expenses

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

໿



	Successor		Predecessor
	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
Operating expenses (in thousands, except per unit data):
Lease operating expense	$	12,679	$	11,480
Marketing and transportation expense	11,206		6,510
Production taxes	2,606		1,184

Production cost per BOE:
Lease operating expense	$	5.43	$	6.16
Marketing and transportation expense	4.80		3.49
Production taxes	1.12		0.63

Lease operating expense primarily consists of costs related to compression, chemicals, fuel, power and water and associated labor. Lease operating expense for the three months ended June 30, 2018 (Successor) increased approximately $1.2 million, or 10%, as compared to the three months ended June 30, 2017 (Predecessor), primarily due to new wells drilled. The decrease in cost per BOE was primarily due to increased NGL production resulting from increased BOE production of oil and natural gas and from an amended contract which allows for a greater recovery of ethane, commencing in the second quarter 2018. See Note 17 — Related Party Transactions for further detail.

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Marketing and transportation expense represents throughput for our properties in the STACK at the Kingfisher processing facility. Marketing and transportation expense for the three months ended June 30, 2018 (Successor) increased approximately $4.7 million or 72%, as compared to June 30, 2017 (Predecessor), primarily due to higher volumes flowing from our operated wells into the Kingfisher plant. The fee we pay per unit to Kingfisher reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant.

Production taxes for the three months ended June 30, 2018 (Successor) increased approximately $1.4 million, or 120%, as compared to the three months ended June 30, 2017 (Predecessor), primarily due to an increase in oil and natural gas liquids revenue.

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Exploration expense consists primarily of geological and geophysical personnel and data costs, lease rental expenses, expired leases, dry hole costs and settlements of asset retirement obligations in excess of estimates. Total exploration expense increased $4.9 million, primarily due to an increase in expired leaseholds. The following table shows the components of exploration expenses for the periods presented (in thousands):

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	Successor		Predecessor
	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
Geological and geophysical costs	$	1,139	$	1,722
Exploration expense	6,579		1,446
Loss on ARO settlement	365		24
Total exploration expense	$	8,083	$	3,192

Depreciation, depletion and amortization expense was higher on a per BOE basis for the three months ended June 30, 2018 (Successor) as compared to the three months ended June 30, 2017 (Predecessor), primarily due to an increase in the depletion base resulting from the application of pushdown accounting of the Business Combination.

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	Successor		Predecessor
	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
(in thousands)
Depreciation, depletion and amortization	$	26,509	$	20,110
Depreciation, depletion and amortization per BOE	11.36		10.78

General and administrative expense (“G&A”). For the three months ended June 30, 2018 (Successor), G&A increased approximately $9.5 million, or 115%, as compared to the three months ended June 30, 2017 (Predecessor), primarily due to increased labor-related costs of $3.9 million and non-cash charges for equity compensation of $3.6 million. See Note 16 — Equity-Based Compensation for further detail on equity-based compensation awards granted during the Successor Period. No such awards were made during the Predecessor Period.

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	Successor		Predecessor
	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
(in thousands)
Equity-based compensation expense	$	3,621	$	—
General and administrative expenses	14,190		8,293
Total general and administrative expenses	$	17,811	$	8,293

Other Income (Expense)

Interest expense. For the three months ended June 30, 2018 (Successor) interest expense decreased $2.2 million, or 18%, as compared to the three months ended June 30, 2017 (Predecessor), primarily due to lower interest on the Eighth A&R credit facility of $2.1 million, resulting from the repayment of our predecessor senior secured revolving credit facility in connection with the Business Combination, and bond premium amortization of $1.2 million. These decreases were partially offset by the

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increase in other interest expense of $1.1 million related our joint development agreement with BCE. The following table summarizes our interest expense for the periods presented (in thousands):

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	Successor		Predecessor
	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
Senior secured revolving credit facility	$	80	$	2,171
Senior unsecured notes	8,613		10,183
Other	1,668		224
Total interest expense	$	10,361	$	12,578

For the Periods from February 9, 2018 Through June 30, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor) Compared to Six Months Ended June 30, 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.

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Revenues

Our oil, natural gas and NGLs revenues vary as a result of changes in commodity prices and production volumes. The following table summarizes our revenues and production data for the periods presented:໿

໿



	Successor			Predecessor			Predecessor
	February 9, 2018			January 1, 2018			Six
	Through			Through			Months Ended
	June 30, 2018			February 8, 2018			June 30, 2017
Net sales revenues (in thousands, except per unit data)
Oil sales	$	115,569		$	30,972		$	89,288
Natural gas sales	13,190			4,276			20,233
Natural gas liquids sales	14,955			4,000			13,653
Total net sales revenues	$	143,714		$	39,248		$	123,174

Net production:
Oil (Mbbls)	1,774			494			1,845
Natural gas (MMcf)	6,192			1,609			7,003
NGLs (Mbbls)	777			151			589
Total (MBoe)	3,583			914			3,601

Average net daily production volume:
Oil (Mbbls/d)	12.5			12.7			10.2
Natural gas (MMcf/d)	43.6			41.2			38.7
NGLs (Mbbls/d)	5.5			3.9			3.3
Total (MBoe/d)	25.2			23.4			19.9

Average sales prices:
Oil (per bbl)	$	65.16		$	62.68		$	48.39
Effect of derivative settlements on average price (per bbl)	(11.01		)	(6.44		)	(0.04		)
Oil, net of hedging (per bbl)	$	54.15		$	56.24		$	48.35

Natural gas (per Mcf)	$	2.13		$	2.66		$	2.89
Effect of derivative settlements on average price (per Mcf)	0.09			0.94			0.10
Natural gas, net of hedging (per Mcf)	$	2.22		$	3.60		$	2.99

Natural gas liquids (per bbl)	$	19.25		$	26.41		$	23.18
Effect of derivative settlements on average price (per bbl)	—			—			(0.66		)
Natural gas liquids, net of hedging (per bbl)	$	19.25		$	26.41		$	22.52

Oil revenues were 80%, 79% and 72% of our total net sales 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 first six months of 2018. The higher average prices are tied to the overall increase in oil commodity prices as discussed above. Oil production was approximately 50%, 54% and 51% of total BOE production volume in the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.

Natural gas revenues were 9%, 11% and 16% of our total net sales 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 first six months of 2018. The lower average prices are tied to the overall decrease in natural gas commodity

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prices as discussed above. Natural gas production was approximately 29%, 29% and 32% of total BOE production volume for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.

Natural gas liquid revenues were 10%, 10% and 11% of our total net sales 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 an increase in production during the period, partially offset by lower average prices. Natural gas liquids production was approximately 22%, 17% and 16% of total BOE production volume for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. The increase in production volume was primarily due to (i) increased BOE production of oil and natural gas and (ii) an amended contract commencing in the second quarter 2018, which allows for a greater recovery of ethane.

Gain (loss) on sale of assets and other primarily includes a gain for the sale of seismic data totaling $5.9 million in the Successor Period.

Gain (loss) on derivative contracts presented in the table below represents cash settlements related to the commodity as well as fair value changes in 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.



	Successor			Predecessor
	February 9, 2018			January 1, 2018			Six
	Through			Through			Months Ended
	June 30, 2018			February 8, 2018			June 30, 2017
Gain (loss) on derivative contracts (in thousands):
Oil	$	(19,527	)	$	(3,184	)	$	(81	)
Natural gas	558			1,523			725
Natural gas liquids	—			—			(391		)
Total cash settlements	(18,969		)	(1,661		)	253
Valuation changes	(32,896		)	8,959			48,239
Total gain (loss) on derivative contracts	$	(51,865	)	$	7,298		$	48,492

Operating Expenses

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

໿



	Successor		Predecessor
	February 9, 2018		January 1, 2018		Six
	Through		Through		Months Ended
	June 30, 2018		February 8, 2018		June 30, 2017
Operating expenses (in thousands, except per unit data):
Lease operating expense	$	20,996	$	4,485	$	22,490
Marketing and transportation expense	16,788		3,725		12,172
Production taxes	4,021		953		2,450

Production cost per BOE:
Lease operating expense	$	5.86	$	4.91	$	6.25
Marketing and transportation expense	4.69		4.08		3.38
Production taxes	1.12		1.04		0.68

Lease operating expense primarily consists of costs related to compression, chemicals, fuel, power and water and associated labor. Lease operating expense per BOE was $5.86 for the Successor Period, $4.91 for the 2018 Predecessor Period and $6.25 for the 2017 Predecessor Period. The lease operating expense cost per BOE for the Successor Period and 2018 Predecessor Period was lower as compared to the 2017 Predecessor Period primarily due to increased NGL production resulting from higher

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BOE production of oil and natural gas and from an amended contract which allows for a greater recovery of ethane, commencing in the second quarter of 2018. See Note 17 — Related Party Transactions for further detail.

Marketing and transportation expense represents throughput for our properties in the STACK at the Kingfisher processing facility. The increase is primarily due to higher volumes flowing from our operated wells into the Kingfisher plant. The fee we pay per unit to Kingfisher reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant.

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

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

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	Successor		Predecessor
	February 9, 2018		January 1, 2018			Six
	Through		Through			Months Ended
	June 30, 2018		February 8, 2018			June 30, 2017
Geological and geophysical costs	$	1,590	$	2,440		$	3,580
Exploratory dry hole costs	—		(45		)	—
Exploration expense	10,782		1,179			4,623
Loss on ARO settlements	666		59			36
Total exploration expense	$	13,038	$	3,633		$	8,239

Depreciation, depletion and amortization expense was lower on a per BOE basis for the Successor Period as compared to the 2018 Predecessor Period and the 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 related to the Business Combination.

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Successor

Predecessor

February 9, 2018

January 1, 2018

Six

Through

Months Ended

June 30, 2018

February 8, 2018

June 30, 2017

(in thousands)

Depreciation, depletion and amortization

37,445

11,784

39,088

Depreciation, depletion and amortization per BOE

10.45

12.89

10.85

General and administrative expense (“G&A”) includes non-cash charges for equity compensation in the Successor Period. See Note 16 — Equity-Based Compensation for further detail on equity-based compensation awards granted during the Successor Period. No such awards were made during the Predecessor Periods. G&A expenses for the Successor Period and the 2018 Predecessor Period included $25.7 million and $17.0 million, respectively, of transaction expenses primarily attributable to the consummation of the Business Combination.

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	Successor		Predecessor
	February 9, 2018		January 1, 2018		Six
	Through		Through		Months Ended
	June 30, 2018		February 8, 2018		June 30, 2017
(in thousands)
Equity-based compensation expense	$	6,389	$	—	$	—
General and administrative expenses	42,881		24,352		18,029
Total general and administrative expenses	$	49,270	$	24,352	$	18,029

Other Income (Expense)

Interest expense. Interest expense in the Successor Period includes amortization of our deferred financing cost related to the Eighth A&R credit facility, interest on our senior unsecured notes, bond premium amortization, and other expenses such as commitment fees and interest expense related our joint development agreement with BCE. The following table summarizes our interest expense for the periods presented (in thousands):

໿



	Successor		Predecessor		Predecessor
	February 9, 2018		January 1, 2018		Six
	Through		Through		Months Ended
	June 30, 2018		February 8, 2018		June 30, 2017
Senior secured revolving credit facility	$	80	$	867	$	3,741
Senior unsecured notes	13,535		3,399		20,347
Other	1,942		1,245		532
Total interest expense	$	15,557	$	5,511	$	24,620

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 interest on our debt 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, borrowings under the Eighth A&R credit facility and capital contributions from our parent AMR.

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 for 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 considered 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 the Eighth A&R 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 the Eighth A&R credit facility will provide us with the financial flexibility and wherewithal to meet our cash

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requirements, including normal operating needs, and pursue our currently planned and future development 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”, 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. As described further in Note 11 of the Notes to Condensed Consolidated Financial Statements, we may, from time to time, redeem certain amounts of the outstanding senior notes at specified amounts in relation to the principal balance of the notes redeemed.

As of June 30, 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, we entered into the Eighth A&R credit facility with Wells Fargo Bank, National Association, as the administrative agent. The Eighth A&R credit facility, which will mature on February 9, 2023, 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 June 30, 2018, we have no borrowings under the Eighth A&R credit facility and have $21.9 million of outstanding letters of credit.

As of June 30, 2018, we were in compliance with the financial ratios described above.

Cash flow provided by (used in) operating activities

Cash provided by (used in) operating activities was $(45.5) million, $26.5 million and $(6.2) 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 were approximately $28.3 million, $(2.4) million, and $49.2 million for the Successor Period, 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Changes in working capital and other assets and liabilities resulted in a decrease in cash of $73.8 million and $55.4 million for the Successor Period and the 2017 Predecessor Period, respectively. Changes in working capital and other assets and liabilities during the 2018 Predecessor Period resulted in an increase in cash of approximately $28.9 million.

Cash flow used in investing activities

Investing activities used cash of approximately $307.7 million, $38.1 million and $151.8 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively, primarily for capital expenditures. During the 2017 Predecessor Period, cash used for acquisitions totaled $6.3 million.

Cash flow provided by financing activities

Cash provided by financing activities was $417.9 million, $16.9 million and $162.8 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, capital distribution of $7.0 million and incurred deferred financing costs of $1.4 million. The 2018 Predecessor Period included proceeds from the issuance of 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 the issuance of long-term debt totaling $165.1 million and capital contributions totaling $7.9 million, partially offset by repayments of long-term debt totaling $10.0 million.

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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 June 30, 2018 was a net liability of $44.1 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 $30.0 million (decrease in value) or $33.3 million (increase in value), respectively, as of June 30, 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 June 30, 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 June 30, 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.

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 June 30, 2018.

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ITEM 6. Exhibits



3.1	Certificate of Limited Partnership of Alta Mesa Holdings, LP, dated September 26, 2005 (incorporated by reference from Exhibit 3.3 to Alta Mesa Holdings, LP’s Registration Statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.2	Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa Holdings, LP, dated as of February 9, 2018 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on February 14, 2018 (File No. 333-173751)).
3.3	Articles of Organization of Alta Mesa Holdings GP, LLC, dated September 26, 2005 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s Registration Statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.4	Sixth Amended and Restated Limited Liability Company Agreement of Alta Mesa Holdings GP, LLC, dated February 9, 2018 (incorporated by reference from Exhibit 3.2 to Alta Mesa Holdings, LP’s Current Report on Form 8-K filed with the SEC on February 14, 2018 (File No. 333-173751)).
3.5	Certificate of Incorporation of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.7 to Alta Mesa Holdings, LP’s Registration Statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.6	Bylaws of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.8 to Alta Mesa Holdings, LP’s Registration Statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
4.3	Indenture, dated December 8, 2016, by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp,. the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Alta Mesa Holdings, LP's current report on Form 8-K filed with the SEC on December 8, 2016 (File No. 333-173751).
31.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101*	Interactive data files.
* filed herewith.

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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.



	ALTA MESA HOLDINGS, LP
	(Registrant)

	By:	ALTA MESA HOLDINGS GP, LLC, its
August 15, 2018		general partner

	By:	/s/ Harlan H. Chappelle
		Harlan H. Chappelle
		President and Chief Executive Officer
August 15, 2018
	By:	/s/ Michael A. McCabe
		Michael A. McCabe
		Vice President and Chief Financial Officer

Alta Mesa Holdings, LP - FORM 10-Q - August 15, 2018

Attached files

Alta Mesa Holdings, LP Reports