Alta Mesa Resources (AMRWW) 10-Q 2018 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_______________________________________

FORM 10-Q

_______________________________________

(Mark One)

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

For the quarterly period ended: March 31, 2018

OR

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

For the transition period from            to

Commission file number: 001-38040

_______________________________________

ALTA MESA RESOURCES, INC.

(Exact name of registrant as specified in its charter)

_______________________________________

Delaware	81-4433840
(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  ☐    

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

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

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

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  ☒ 

As of April 30, 2018, there were 170,931,140 shares of Class A Common Stock and 213,402,398 shares of Class C Common Stock, par value $0.0001 per share outstanding.

1

Table of Contents

	Page Number
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Consolidated Balance Sheets as of March 31, 2018 (Successor) and December 31, 2017 (Predecessor)	3
Consolidated Statements of Operations for the period from February 9, 2018 through March 31, 2018 (Successor), for the period from January 1, 2018 through February 8, 2018 (Predecessor) and for the Three Months ended March 31, 2017 (Predecessor)	5
Consolidated Statements of Cash Flows for the period from February 9, 2018 through March 31, 2018 (Successor), for the period from January 1, 2018 through February 8, 2018 (Predecessor) and for the Three Months ended March 31, 2017 (Predecessor)	6
Consolidated Statements of Stockholders’ Equity for the period from February 9, 2018 through March 31, 2018 (Successor)	7
Consolidated Statements of Changes in Partners’ Capital for the period from January 1, 2018 through February 8, 2018 (Predecessor)	8
Notes to Consolidated Financial Statements	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
Item 3. Quantitative and Qualitative Disclosures about Market Risk	62
Item 4. Controls and Procedures	62
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	64
Item 1A. Risk Factors	64
Item 6. Exhibits	65
Signatures	67

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PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

ALTA MESA RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands, except share and per share data) 

	Successor		Predecessor
	March 31,		December 31,
	2018		2017
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	261,063	$	3,660
Short-term restricted cash		1,295		1,269
Accounts receivable, net of allowance of $65 and $415, respectively		109,825		76,161
Other receivables		225		1,388
Receivables due from related party		7,892		790
Note receivable due from related party		1,578		—
Prepaid expenses and other current assets		5,903		2,932
Current assets — discontinued operations		—		5,195
Derivative financial instruments		—		216
Total current assets		387,781		91,611
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		2,389,522		920,563
Other property, plant and equipment, net		322,122		6,207
Total property, plant and equipment, net		2,711,644		926,770
OTHER ASSETS
Deferred financing costs, net		1,007		1,787
Notes receivable due from related party		11,039		12,369
Goodwill		650,663		—
Intangible assets, net		468,913		—
Deposits and other long-term assets		8,630		9,067
Non-current assets — discontinued operations		—		43,785
Deferred tax asset		3,813		—
Derivative financial instruments		49		8
Total other assets		1,144,114		67,016
TOTAL ASSETS	$	4,243,539	$	1,085,397
LIABILITIES, PARTNERS' CAPITAL AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	159,110	$	170,489
Accounts payable — affiliate		—		5,476
Advances from non-operators		1,312		5,502
Advances from related party		40,498		23,390
Asset retirement obligations		622		69
Current liabilities — discontinued operations		—		15,419
Derivative financial instruments		26,401		19,303
Total current liabilities		227,943		239,648
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		6,033		10,400
Long-term debt, net		584,815		607,440
Noncurrent liabilities — discontinued operations		—		66,862
Derivative financial instruments		2,916		1,114
Other long-term liabilities		1,934		5,488
Total long-term liabilities		595,698		691,304
TOTAL LIABILITIES		823,641		930,952

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PREFERRED STOCK, $0.0001 par value, 1,000,000 shares authorized
Class A: 3 shares issued and outstanding		—		—
Class B: 1 share issued and outstanding		—		—
Commitments and Contingencies (Note 13)
PARTNERS' CAPITAL		—		154,445
STOCKHOLDERS' EQUITY
Common stock, $0.0001 par value
Class A: 1,200,000,000 shares authorized,  169,371,730 shares issued and outstanding		17		—
Class C: 280,000,000 shares authorized,  213,402,398 shares issued and outstanding		21		—
Additional paid in capital		1,402,888		—
Retained earnings (accumulated deficit)		(21,349)		—
Total stockholders' equity/partners' capital		1,381,577		154,445
Non-controlling interest		2,038,321		—
Total equity		3,419,898		154,445
TOTAL LIABILITIES, PARTNERS' CAPITAL AND STOCKHOLDERS' EQUITY	$	4,243,539	$	1,085,397

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

4

ALTA MESA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(in thousands, except share and per share data)

	Successor		Predecessor
	February 9, 2018		January 1, 2018		Three
	Through		Through		Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
OPERATING REVENUES AND OTHER
Oil	$	40,278	$	30,972	$	46,940
Natural gas		5,210		4,276		9,591
Natural gas liquids		4,714		4,000		7,072
Product sales		8,369		—		—
Gathering and processing revenue		3,411		—		—
Other revenues		555		888		1,234
Total operating revenues		62,537		40,136		64,837
Gain on sale of assets and other		5,979		—		—
Gain (loss) on derivative contracts		(22,646)		7,298		30,242
Total operating revenues and other		45,870		47,434		95,079
OPERATING EXPENSES
Lease operating expense		8,317		4,485		11,010
Marketing and transportation expense		1,021		3,725		5,662
Plant operating expense		587		—		—
Product expense		8,220		—		—
Gathering and processing expense		2,338		—		—
Production taxes		1,415		953		1,266
Workover expense		1,245		423		588
Exploration expense		4,955		3,633		5,047
Depreciation, depletion, and amortization expense		15,577		11,784		18,978
Impairment expense		—		—		1,188
Accretion expense		102		39		96
General and administrative expense		34,557		24,352		9,736
Total operating expenses		78,334		49,394		53,571
INCOME (LOSS) FROM OPERATIONS		(32,464)		(1,960)		41,508
OTHER INCOME (EXPENSE)
Interest expense		(5,444)		(5,511)		(12,042)
Interest income and other		546		172		249
Total other income (expense)		(4,898)		(5,339)		(11,793)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(37,362)		(7,299)		29,715
Income tax provision (benefit)		(3,813)		—		285
INCOME (LOSS) FROM CONTINUING OPERATIONS		(33,549)		(7,299)		29,430
Loss from discontinued operations, net of tax		—		(7,593)		(4,515)
NET INCOME (LOSS)		(33,549)		(14,892)		24,915
Net loss attributable to noncontrolling interest		(20,314)		—		—
NET INCOME (LOSS) ATTRIBUTABLE TO ALTA MESA RESOURCES, INC.	$	(13,235)	$	(14,892)	$	24,915
NET INCOME (LOSS) PER COMMON SHARE:
Basic and Diluted	$	(0.08)
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
Basic and Diluted		169,371,730

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

5

ALTA MESA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)

	Successor		Predecessor
	February 9, 2018		January 1, 2018
	Through		Through		Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(33,549)	$	(14,892)	$	24,915
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion, and amortization expense		15,577		12,414		24,804
Impairment expense		—		5,560		1,220
Accretion expense		102		140		572
Amortization of deferred financing costs		—		171		962
Amortization of debt premium		(820)		—		—
Equity based compensation expense		3,466		—		—
Dry hole expense		—		(45)		—
Expired leases		4,189		1,250		3,333
(Gain) loss on derivative contracts		22,646		(7,298)		(30,242)
Settlements of derivative contracts		(4,610)		(1,661)		(1,970)
Interest converted into debt		—		103		298
Interest on notes receivable due from related party		(162)		(85)		(200)
Deferred tax provision (benefit)		(3,813)		—		—
Loss on sale of assets and other		—		1,923		—
Changes in assets and liabilities:
Accounts receivable		(3,189)		(20,895)		(5,374)
Other receivables		997		(9,887)		7,494
Receivables due from related party		(2,067)		(117)		139
Prepaid expenses and other non-current assets		(2,194)		9,970		(9,543)
Advances from related party		(7,008)		24,116		(29,791)
Settlement of asset retirement obligation		(166)		(63)		(2,394)
Accounts payable, accrued liabilities, and other liabilities		(75,960)		25,815		11,837
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES		(86,561)		26,519		(3,940)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(133,055)		(38,096)		(60,589)
Acquisitions of Alta Mesa and Kingfisher, net of cash acquired		(796,826)		—		—
Proceeds withdrawn from Trust Account		1,042,742		—		—
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		112,861		(38,096)		(60,589)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		9,000		60,000		55,065
Repayments of long-term debt		(134,065)		(43,000)		—
Additions to deferred financing costs		(1,007)		—		(64)
Capital distributions		—		(68)		—
Capital contributions		—		—		7,875
Proceeds from issuance of Class A shares		400,000		—		—
Repayment of sponsor note		(2,000)		—		—
Repayment of deferred underwriting compensation		(36,225)		—		—
Redemption of Class A common shares		(33)		—		—
NET CASH  PROVIDED BY FINANCING ACTIVITIES		235,670		16,932		62,876
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		261,970		5,355		(1,653)
CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period		388		4,990		7,618
CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, end of period	$	262,358	$	10,345	$	5,965

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

6

ALTA MESA RESOURCES, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Successor) (Unaudited)

(in thousands)

	Common Stock											Retained Earnings		Total
	Class A			Class B			Class C			Paid-In		(Accumulated		Stockholders		Noncontrolling
	Shares	Amount		Shares	Amount		Shares	Amount		Capital		Deficit)		Equity		Interests		Total Equity
Balance at February 8, 2018	3,862	$	—	25,875	$	3	—	$	—	$	3,106	$	(8,114)	$	(5,005)	$	—	$	(5,005)
Conversion of common shares from Class B to Class A at closing of Business Combination	25,875		3	(25,875)		(3)	—		—		—		—		—		—		—
Class A common shares released from possible redemption	99,638		10	—		—	—		—		996,374		—		996,384		—		996,384
Class A common shares redeemed	(3)		—	—		—	—		—		(33)		—		(33)		—		(33)
Sale of Class A common shares	40,000		4	—		—	—		—		399,996		—		400,000		—		400,000
Class C common shares issued in connection with the closing of the Business Combination	—		—	—		—	213,402		21		(21)		—		—		—		—
Noncontrolling interest in SRII Opco issued in the Business Combination	—		—	—		—	—		—		—		—		—		2,058,635		2,058,635
Balance at February 9, 2018	169,372		17	—		—	213,402		21		1,399,422		(8,114)		1,391,346		2,058,635		3,449,981
Equity based compensation	—		—	—		—	—		—		3,466				3,466		—		3,466
Net loss	—		—	—		—	—		—		—		(13,235)		(13,235)		(20,314)		(33,549)
Balance at March 31, 2018	169,372	$	17	—	$	—	213,402	$	21	$	1,402,888	$	(21,349)	$	1,381,577	$	2,038,321	$	3,419,898

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

7

ALTA MESA RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL (Predecessor) (Unaudited)

(in thousands)

	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

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

8

ALTA MESA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS

Alta Mesa Resources, Inc. (together with its consolidated subsidiaries, (“AMR,” “we,” “us,” “our,” or the “Company,”) was originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving the Company and one or more businesses.

On March 29, 2017, we consummated our initial public offering (“IPO”) generating net proceeds of approximately $1.0 billion. Simultaneously with the closing of our IPO, we completed the private sale of 15,133,333 warrants (the “Private Placement Warrants”) to Silver Run Sponsor II, LLC (the “Sponsor”) generating gross proceeds to us of $22,700,000. A total of $1.035 billion (which includes approximately $36.2 million in deferred underwriting commissions to the underwriters of the IPO), representing $1.0143 billion of the proceeds from the IPO after deducting upfront underwriting commissions of $20.7 million, and the proceeds of the sale of the Private Placement Warrants were placed in the Trust Account (the “Trust Account”) to be used to fund an initial business combination.

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

Pursuant to the Contribution Agreements, SRII Opco, LP, our newly formed subsidiary (“SRII Opco”) acquired (a) (i) all of the limited partner interests in Alta Mesa and (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa GP, (with (i) and (ii) collectively, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The acquisition of Alta Mesa and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “Business Combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.” SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco, is a wholly owned subsidiary of AMR.  As a result of the Business Combination, our only significant asset is our ownership of an approximate 44.2% partnership interest in SRII Opco. SRII Opco owns all of the economic interests in each of Alta Mesa and Kingfisher. 

In connection with the closing of the Business Combination, the Company changed its name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.” and continued the listing of its Class A Common Stock and public warrants (which were originally sold as part of the units issued in our initial public offering) on NASDAQ under the symbols “AMR” and “AMRWW,” respectively. 

Alta Mesa is an independent exploration and production company engaged primarily in the acquisition, exploration, development, and production of unconventional oil and natural gas properties in the eastern portion of the Anadarko Basin commonly referred to as the STACK.  Kingfisher owns and operates midstream oil and gas assets in the STACK and its operations are primarily comprised of crude oil gathering, natural gas gathering and processing of products.  The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area.  In connection with the closing of the Business Combination, Alta Mesa distributed the remainder of its non-STACK assets to the AM Contributor and completed its transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities.  

9

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation. As a result of the Business Combination, the Company is the acquirer for accounting purposes and Alta Mesa and Kingfisher are the acquirees. Alta Mesa is our accounting predecessor. The Company’s financial statement presentation reflects Alta Mesa as the “Predecessor” for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, which includes consolidation of Alta Mesa and Kingfisher concurrent with the Business Combination on February 9, 2018. The Business Combination was accounted for as a business combination using the acquisition method of accounting, and the Successor financial statements reflect a new basis of accounting that is based on the fair value of Alta Mesa and Kingfisher’s net assets acquired. Refer to Note 4 — Business Combination (Successor) for further information related to the Business Combination.  As a result of the application of the acquisition method of accounting resulting from the Business Combination, the financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the Transactions and the period on or after that date, to indicate that the financial statements presented are those of different entities and reflect  the application of the different basis of accounting between the periods presented.  The Successor period presented herein is from February 9, 2018 to March 31, 2018 (“Successor Period”) and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”) and the three months ended March 31, 2017 (“2017 Predecessor Period”).

Prior to the Business Combination, Alta Mesa distributed its non-STACK assets to the AM Contributor.  The distribution of its remaining non-STACK assets in 2018 and the sale of its Weeks Island field during the fourth quarter of 2017 (collectively, the “non-STACK assets”) were part of Alta Mesa’s overall strategic shift to operate only in the eastern Anadarko Basin.  As a result of the strategic shift, Alta Mesa classified the Predecessor assets and liabilities and operating results directly related to non-STACK assets as discontinued operations within the consolidated financial statements.  See Note 6 — Discontinued Operations(Predecessor) for further discussion.

Principles of Consolidation and Reporting.  The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain reclassifications of prior period consolidated financial statements have been made to conform to current reporting practices.  The consolidated financial statements include the accounts of the Company and its subsidiaries, including SRII Opco, after eliminating all significant intercompany transactions and balances. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.  Noncontrolling interests represent third-party ownership interests in SRII Opco and are presented as a component of equity. See Note 15—Stockholders' Equity and Partners’ Capital for further discussion of noncontrolling interest.

The consolidated financial statements included herein 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 consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

Use of Estimates.The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion, and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, product and gathering and compression sales, the value of oil and natural gas properties, the value of pipeline equipment, bad debts, goodwill, intangible assets, asset retirement obligations, derivative contracts, accounting for business combinations, federal and 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.

Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance Corporation provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. 

10

Restricted Cash.The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of March 31, 2018, and December 31, 2017, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute or there is unclaimed property for pooling orders in Oklahoma. 

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):

	Successor		Predecessor
	March 31,		December 31,
	2018		2017
Cash and cash equivalents	$	261,063	$	3,660
Short-term restricted cash		1,295		1,269
Cash of discontinued operations		—		61
Total cash, cash equivalents and restricted cash	$	262,358	$	4,990

Accounts Receivable. Our receivables arise primarily from the sale of oil, natural gas and natural gas liquids and joint interest owner receivables for properties in which we serve as the operator, and valid claims against nonaffiliated customers for services rendered. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry.  Accounts receivable are generally not collateralized.  We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. 

Accounts receivable consisted of the following (in thousands):

	Successor		Predecessor
	March 31,		December 31,
	2018		2017
Oil, natural gas and natural gas liquids sales	$	39,067	$	26,916
Joint interest billings		33,197		13,821
Pooling interest (1)		37,626		35,839
Allowance for doubtful accounts		(65)		(415)
Total accounts receivable, net	$	109,825	$	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 represent costs of unbilled interests on wells which the Company incurred before the pooling process was completed.  Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties.

Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated.

Property, Plant and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.  In conjunction with acquisition accounting, property, plant and equipment was measured at fair value as of the acquisition date, which also impacted how value was assigned between the categories within property, plant, and equipment.  See Note 4 — Business Combination (Successor) for discussion.

Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to the proved oil and natural gas properties.

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Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, delay rentals, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, or “suspended” on the balance sheet pending determination of whether the well has discovered proved commercial reserves.  If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly. 

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to the proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in Account Standards Codification (“ASC”) 360-10-35, Property, Plant and Equipment, Subsequent Measurement, or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved and risk-adjusted unproved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Our evaluation of the Company’s proved properties resulted in no impairment expense in the Successor Period and the 2018 Predecessor Period.  For the 2017 Predecessor Period, our evaluation of the Company’s proved properties resulted in an impairment expense of $1.2 million.

Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statements of operations. No impairment expense was recognized in the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period.

Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. The Company did not record any impairment expense related to other long-lived assets for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.

Other Property, Plant and Equipment — Other property, plant and equipment such as plant equipment, salt water disposal system, office furniture and equipment, buildings, vehicles, are recorded at cost, or fair value, if impaired.  Maintenance, repairs and minor renewals are expensed as incurred.  Plant and equipment include costs incurred to build a cryogenic processing facility along with gathering pipelines, including right of ways, crude oil gathering system, and compressors.

Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is total proved reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.  Our midstream assets are depreciated on the straight-line method based on their expected useful lives. The Company uses estimated lives of 35 years for its processing plant and pipelines.

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DD&A expense related to oil and natural gas properties was $10.8 million, $11.2 million and $18.3 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. DD&A expense related to our midstream assets was $1.1 million in the Successor Period.  There was no such DD&A expense for midstream assets for the 2018 and 2017 Predecessor Period.

Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease.  Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years.  For the Successor Period, depreciation expense was immaterial.  Depreciation expense for non-oil, natural gas, and midstream properties was $0.2 million, $0.6 million and $0.7 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. 

Intangible Assets (Successor). In connection with the acquisition of Kingfisher, the Company recorded the estimated fair value of acquired customer contracts and relationships as intangible assets, which were valued using the income approach, and are presented as Intangible Assets, net in the accompanying consolidated balance sheet of the Successor. These intangible assets have definite lives and are subject to amortization utilizing an accelerated attrition method over their economic lives, currently ranging between 10 years and 15 years. We assess intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  An impairment is recognized in the consolidated statements of income if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value.  As a result of the Business Combination, we determined all the Company’s intangible assets relate to the midstream reporting unit, and concluded that there was no impairment after evaluating the intangible assets for impairment as of March 31, 2018.

Goodwill (Successor).Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed, and it is presented as Goodwill in the accompanying consolidated balance sheet of the Successor.   Under ASC 350, Intangibles – Goodwill and Other (“ASC 350”), goodwill is not amortized but is subject to periodic impairment testing.  ASC 350 requires that an entity assign its goodwill to reporting units and test each reporting unit’s goodwill for impairment at least on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.  In our evaluation of goodwill for impairment, performed annually during the third quarter, we first assess qualitative factors to determine whether the existence of events or circumstances led to a determination that it was more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is less than its carrying amount, we are required to perform the quantitative goodwill impairment test. As a result of the Business Combination, we acquired goodwill during the Successor Period. There was no goodwill prior to the Business Combination. We determined that all of the Company’s goodwill relates to the midstream reporting unit and did not identify any significant events or circumstances that would require us to perform an impairment test as of March 31, 2018. As such, there was no impairment recognized during the Successor Period. 

Bond Premium on Senior Unsecured Notes.  In connection with the Business Combination, the Company estimated the fair value of Alta Mesa’s $500 million senior unsecured notes at $533.6 million as of the acquisition date.  The amount in excess of the principal amount was recorded as a bond premium, which is being amortized over the term of the notes using the straight-line method, which approximates the effective interest method. 

Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset.  The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset.  Accretion expense is recognized as the discounted liability is accreted to its expected settlement value.  Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.

Asset retirement obligations for the Company’s midstream processing and pipeline facilities generally become firm at the time the facilities are permanently shut down and dismantled.  These obligations may include the costs of asset disposal and additional soil remediation.  However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured due to the uncertainty associated with the future settlement dates of such obligations.

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, Derivatives and Hedging (“ASC 815”), which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 7 — Fair Value Disclosures for information on fair value).

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Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in gain (loss) on derivative contracts in the consolidated statement of operations.  Gains or losses from the settlement of matured derivatives contracts are also included in gain (loss) on derivatives contracts in the consolidated statement of operations.  Cash flows from settlements of derivative contracts are classified as operating cash flows. 

Income Taxes (Successor). Income taxes and uncertain tax positions are accounted for in accordance with ASC 740, Accounting for Income Taxes (“ASC 740”). Deferred income taxes are provided for the differences between the bases of assets and liabilities for financial reporting and income tax purposes. Tax positions meeting the more-likely-than-not recognition threshold are measured pursuant to the guidance set forth in ASC 740. We assess the ability to realize our deferred tax assets on a quarterly basis. A valuation allowance is established to reduce deferred tax assets to the amount expected to be realized when it is determined that it is more likely than not that some or all of the deferred tax assets are not realizable.

The Company is also subject to the Texas margin tax, which is considered a state income tax, and is included in “Income tax provision (benefit)” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.

We have considered our exposure under the standard at both the federal and state tax levels.  We did not record any liabilities for uncertain tax positions as of the Successor Period and December 31, 2017. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any material interest or penalties on income taxes for the 2018 Predecessor Period and the 2017 Predecessor Period.

Alta Mesa’s tax returns for the years ended December 31, 2014 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.

Income Taxes (Predecessor). Alta Mesa has historically elected under the provisions of the Internal Revenue Code of 1986, as amended, to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses of the Predecessor flowed through to the partners and were taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements of the Predecessor.

Predecessor net income (loss) for financial statement purposes differed significantly from taxable income (loss) reported to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under Alta Mesa’s amended and restated partnership agreement.  As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes could not be readily determined as Alta Mesa does not have access to information about each unitholder’s tax attributes in Alta Mesa. However, with respect to Alta Mesa, the Predecessor’s book basis in its net assets exceeded Alta Mesa’s net tax basis by $333.2 million at December 31, 2017.

We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances.

Gathering and processing revenues are generated by charging fees on a per unit basis for gathering crude oil and natural gas and processing natural gas.  The Company recognizes revenue when services have been rendered, the prices are fixed or determinable and collectability is reasonably assured.  In addition, revenue from sales of crude oil, natural gas and NGLS is recognized when title passes to the customer, which is when risk of ownership passes to the customer and physical delivery occurs, the price of the product is fixed or determinable and collectability is reasonably assured.

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

Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The fair value estimate of long-term debt under our senior secured revolving credit facilities is not considered to be materially different from carrying value due to market rates of interest.  Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments see Note 7 —  Fair Value Disclosures and Note 11 —  Long-Term Debt, Net.  

Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions, except in the case of our acquisition of Alta Mesa, as that entity was deemed to be our Predecessor for accounting purposes. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition.

Earnings (Loss) Per Share. Basic earnings (loss) per share is calculated by dividing earnings (loss) available to common shareholders by the weighted average shares-basic during each period.

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

The following table reflects the allocation of net income to common stockholders and EPS computations for the periods indicated based on a weighted average number of common stock outstanding for the period:

	Successor
	February 9, 2018 Through March 31, 2018
	(in thousands, except share and per share data)
Net loss attributable to common stock	$	(13,235)
Weighted average common shares outstanding (Basic)		169,371,730
Effect of Dilutive Securities:
Warrants, Class C Common Stock, restricted stock, and stock options		—
Weighted average common shares outstanding (Diluted)		169,371,730
Net income (loss) per common share
Basic and diluted	$	(0.08)

During the Successor Period, approximately 63.2 million of warrants, 213.4 million shares of Class C Common Stock and 6.1 million of stock options, restricted stock and restricted stock units were excluded from the calculation of diluted earnings per share as their effect would have been anti-dilutive.

Segment Reporting (Successor). The Company (Predecessor) operated in only one industry segment which is the exploration and production of oil and natural gas. All of its operations are conducted in one geographic area of the United States and all of its revenues are derived from customers located in the United States.  The Company (Successor) reports financial results under two reportable segments: (1) Exploration & Production and (2) Midstream.  See Note 20 — Business Segment Information for financial information about our segments.

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Recent Accounting Pronouncements

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. AMR is an emerging growth company.  As an emerging growth company, we have elected to use the extended transition period and as a result, we will be required to adopt the standard during the first quarter of 2019.  We expect to adopt using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.  We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues at the end of any fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates measured as of June 30, or issue more than $1.0 billion of non-convertible debt over a three-year period. It is reasonably possible that we could cease to be an emerging growth company by December 31, 2018. If we lose our emerging growth status, we would adopt the standard in the fourth quarter of 2018. 

We are in the process of assessing our contracts and evaluating the impact on the consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09 as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our future revenues and expenses under the new gross-versus-net presentation guidance. We continue to evaluate the impact of these and other provisions of ASU 2014-09 on our accounting policies, changes to relevant business practices, internal controls, and consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases.  In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases.  The standard will be effective for interim and annual periods beginning after December 15, 2018 for public companies and annual periods beginning after December 15, 2019 for all other entities, with earlier adoption permitted. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets.

At this time, we cannot reasonably estimate the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and impletion of ASU 2016-02 is expected to have an impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months.  The adoption is also expected to result in increase in depreciation, depletion and amortization expense, interest expense recorded on our consolidated statement of operations, and additional disclosures.  As part of our assessment to date, we have formed an implementation work team and will complete our evaluation in 2018.  As we continue to evaluate and implement the standard, we will provide additional information about the expected financial impact at a future date.  As an emerging growth company, we have elected to use the extended transition period and as a result, we will be required to adopt the standard in 2020.  It is reasonably possible that we could cease to be an emerging growth company by December 31, 2018.  If we do lose our emerging growth status, we would adopt the standard on January 1, 2019.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017 for public companies and for fiscal years beginning after December 15, 2018 for all other entities. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard in 2019.  It is reasonably possible that we could cease to be an emerging growth company by December 31, 2018.  If we lose our emerging growth status, we would adopt the standard in the fourth quarter of 2018.  The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our consolidated statements of cash flows. 

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In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”),  which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for interim and annual periods after December 15, 2017 for public companies and annual periods beginning after December 15, 2018 for all other entities.  The amendments should be applied prospectively on or after the effective date and disclosures are not required at transition. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance.  The Company early adopted ASU 2017-01 in the fourth quarter of 2017.  We do not expect the adoption of ASU 2017-01 to have a material impact on our consolidated financial statements; however these amendments could result in the recording of fewer business combinations in the future periods.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other, Simplifying the Test for Goodwill Impairment (ASU “2017-04”), which provides guidance to simplify the subsequent measurement of goodwill by removing Step 2 from the goodwill impairment process.  ASU 2017-04 is effective for goodwill impairment tests performed in annual or interim periods within those fiscal years beginning after December 15, 2019 for public companies and annual periods beginning after December 15, 2021 for all other entities.  The amendments should be applied prospectively on or after the effective date and disclosures regarding the reason and change in accounting principle are required at transition. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.  The Company early adopted ASU 2017-01 in the first quarter of 2018.

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

NOTE 3 — SUPPLEMENTAL CASH FLOW INFORMATION

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

	Successor		Predecessor
	February 9, 2018		January 1, 2018		Three
	Through		Through		Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
Supplemental cash flow information:
Cash paid for interest	$	1,092	$	1,145	$	1,162
Non-cash investing and financing activities:
Change in asset retirement obligations		421		—		296
Change in accruals or liabilities for capital expenditures		(36,866)		4,712		21,111
Distribution of non-STACK assets (net liability)		—		33,102		—
Equity issued in Business Combination		2,058,635		—		—

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NOTE 4 — BUSINESS COMBINATION (Successor)

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

Pursuant to the AM Contribution Agreement and Kingfisher Contribution Agreement, SRII Opco acquired (a) (i) all of the limited partner interests in Alta Mesa and (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa and (b) 100% of the economic interests in Kingfisher. 

At the closing of the Business Combination,

· The Company issued 40,000,000 shares of Class A Common Stock and warrants to purchase 13,333,333 shares of Class A Common Stock to Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”) pursuant to the terms of that certain Forward Purchase Agreement, dated as of March 17, 2017 (the “Forward Purchase Agreement”) for cash proceeds of $400 million to us;

· The Company contributed $1,406 million in cash (the proceeds of the Forward Purchase Agreement and the net proceeds (after redemptions) of the Trust Account) to SRII Opco, in exchange for (i) 169,371,730 of the common units (approximately 44.2%) representing limited partner interests (the “SRII Opco Common Units”) in SRII Opco issued to us and (ii) 62,966,666 warrants to purchase SRII Opco Common Units (“SRII Opco Warrants”) issued to us;

· The Company caused SRII Opco to issue 213,402,398 SRII Opco Common Units (approximately 55.8%) to the Contributors in exchange for the ownership interests in Alta Mesa, Alta Mesa GP and Kingfisher contributed to SRII Opco by the Contributors;

· The Company agreed to cause SRII Opco to issue up to 59,871,031 SRII Opco Common Units to the AM Contributor and the KFM Contributor if the earn-out consideration provided for in the Contribution Agreements is earned by the AM Contributor or the KFM Contributor pursuant to the terms of the Contribution Agreements;

· The Company issued to each of the Contributors a number of shares of Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), equal to the number of the SRII Opco Common Units received by such Contributor at the closing;

· SRII Opco distributed to the KFM Contributor cash in the amount of approximately $814.8 million in partial payment for the ownership interests in Kingfisher contributed by the KFM Contributor; and

· SRII Opco entered into an amended and restated voting agreement with the owners of the remaining 10% voting interests in Alta Mesa GP whereby such other owners agreed to vote their interests in Alta Mesa GP as directed by SRII Opco.

Holders of AMR’s Class C Common Stock, together with holders of Class A Common Stock, voting as a single class, have the right to vote on all matters properly submitted to a vote of the stockholders, but holders of Class C Common Stock are not entitled to any dividends or liquidating distributions from us. After a specified period of time after Closing, the Contributors will generally have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. However, we may, at our option, effect a direct exchange of cash or Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption by SRII Opco. Upon the future redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be cancelled.

Pursuant to the AM Contribution Agreement and the KFM Contribution Agreement, for a period of seven years following the closing, the Alta Mesa Contributor and the Kingfisher Contributor may 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 AMR’s Class A Common Stock equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):

		Earn-Out Consideration Payable to	Earn-Out Consideration Payable to
20-Day VWAP		AM Contributor	KFM Contributor
$	14.00	10,714,285 SRII Opco Common Units	7,142,857 SRII Opco Common  Units
$	16.00	9,375,000 SRII Opco Common Units	6,250,000 SRII Opco Common Units
$	18.00	13,888,889 SRII Opco Common Units	—
$	20.00	12,500,000 SRII Opco Common Units	—

18

Neither the AM Contributor nor the KFM Contributor will 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 or the KFM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor and/or the KFM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor and the KFM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of our 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.

We also contributed $560 million in net cash to Alta Mesa at the closing. Our source for these funds was from the sale of our securities to investors in a public offering and in private placements.  Alta Mesa used a portion of the amount to repay its outstanding balance under its Alta Mesa Credit Facility described in Note 11.  

Pursuant to the Contribution Agreements, the AM Contributor and KFM Contributor delivered a final closing statement.  Subsequent to quarter end, it was determined that the AM Contributor would receive a positive adjustment amount and be issued 1,197,934 additional SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock and the KFM Contributor would remit back to the Company a negative adjustment of $5.0 million in cash and 89,680 SRII Opco Common Units and an equivalent number of shares of our 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 (“ASC 805”), and uses the fair value concepts defined in FASB ASC 820, Fair Value Measurements ("ASC 820"). ASC 805 requires, among other things, that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by the Company.

Preliminary Estimated Purchase Price for Alta Mesa

The preliminary estimated purchase price consideration for Alta Mesa is as follows (in thousands):

	At February 9,
	2018
Preliminary Purchase Consideration: (1)
SRII Opco Common Units (158,402,398 valued at $7.90 per unit) (2)	$	1,251,782
Estimated fair value of contingent earn-out purchase consideration (3)		284,109
Settlement of preexisting working capital (4)		5,476
Total purchase price consideration	$	1,541,367

_________________

(1) The preliminary purchase price consideration is for 100% of the limited partner interests in Alta Mesa and 100% of the economic interests and 90% of the voting interests in AMH GP.  The preliminary purchase price consideration does not include the effects of the final closing statement adjustments, which adjustments were determined subsequent to March 31, 2018.

(2) 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 $7.90 per unit and reflects discounts for holding requirements and liquidity.

(3) For a period of seven years following Closing, the AM Contributor will be entitled to receive earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of Class C Common Stock) if the 20-day VWAP of our Class A Common Stock 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 using 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 the Company (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. dollars overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.

(4) Settlement of preexisting working capital between Alta Mesa and Kingfisher.

19

Preliminary Estimated Purchase Price Allocation for Alta Mesa

The following table summarizes the allocation of the 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):

	At February 9,
	2018
Estimated Fair Value of Assets Acquired (1)
Cash, cash equivalents and short term restricted cash	$	10,345
Accounts Receivable		101,745
Other Receivables		1,222
Receivables due from related party		907
Prepaid expenses and other current assets		1,405
Derivative financial instruments		352
Property and equipment: (2)
Oil and natural gas properties, successful efforts		2,314,858
Other property and equipment, net		43,318
Notes receivable due from related party		12,454
Deposits and other long-term assets		10,286
Total fair value of assets acquired		2,496,892
Estimated Fair Value of Liabilities Assumed  (1)
Accounts payable and accrued liabilities		210,867
Advances from non-operators		6,803
Advances from related party		47,506
Asset retirement obligations		5,998
Derivative financial instruments		11,585
Long-term debt (3)		667,700
Other long-term liabilities		5,066
Total fair value of liabilities assumed		955,525
Total consideration and fair value	$	1,541,367

_________________

(1) The preliminary purchase price is allocated based on Alta Mesa’s STACK Assets.

(2) The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discounts rates, and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change.

(3) Represents the approximate fair value of Alta Mesa’s $500 million aggregate principal amount of the 7.875% senior unsecured notes due December 15, 2024 using Level 1 inputs as of the acquisition date of approximately $533.6 million, and outstanding borrowings under the Alta Mesa Credit Facility (described in Note 11) of $134.0 million as of the acquisition date.

20

Preliminary Estimated Purchase Price for Kingfisher

The estimated purchase consideration paid for Kingfisher is as follows (in thousands):

	At February 9,
	2018
Preliminary Purchase Consideration:
Cash (1)	$	814,820
SRII Opco Common Units (55,000,000 valued at $7.90 per unit) (2)		434,640
Estimated fair value of contingent earn-out purchase consideration (3)		88,105
Settlement of preexisting working capital (4)		(5,476)
Total purchase price consideration	$	1,332,089

_________________

(1) The cash consideration after estimated adjustments to net working capital, debt, transaction expenses, capital expenditures and banking fees was $814.8 million.

(2) At closing, KFM Contributor received consideration of 55,000,000 SRII Opco Common Units. At closing, the estimated fair value of an SRII Opco Common Unit was assumed to be $7.90 per unit and reflects discounts for holding requirements and liquidity.

(3) Pursuant to ASC 805 and ASC 480, the Kingfisher earn-out consideration has been valued at fair value as of the Closing Date and has been classified in stockholders’ 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 using the fair value hierarchy. The key inputs included the quoted market price for the Company’s Class A Common Stock, market volatility of a peer group of companies similar to the Company (due to the lack of trading activity in the Company’s 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. Dollars overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.

(4) Settlement of preexisting working capital between Alta Mesa and Kingfisher.

21

Preliminary Estimated Purchase Price Allocation for Kingfisher

The following table summarizes the allocation of the preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed in connection with the acquisition of Kingfisher in the Business Combination.  The allocation is as follows (in thousands):

	At February 9,
	2018
Estimated Fair Value of Assets Acquired
Cash and cash equivalents	$	7,648
Accounts Receivable		4,334
Prepaid expenses		550
Property, plant and equipment: (1)
Pipeline		272,442
Other property, plant and equipment		519
Intangible assets (2)		472,432
Goodwill (3)		650,663
Total fair value of assets acquired		1,408,588
Estimated Fair Value of Liabilities Assumed
Accounts payable and accrued liabilities		33,499
Long-term debt		43,000
Total fair value of liabilities assumed		76,499
Total consideration and fair value	$	1,332,089

_________________

(1) The fair value measurements of crude oil, natural gas and NGL gathering, processing and storage assets are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of gathering, processing and storage assets were measured using valuation techniques that convert future cash flows to a single discounted amount. These valuations required significant judgments and estimates made by management based on assumptions believed to be reasonable at the time of the valuation, but which are inherently uncertain. The estimates and assumptions are sensitive and may be subject to change.

(2) The identifiable intangible assets acquired are primarily related to customer relationships held by Kingfisher prior to Closing. The intangible assets acquired were based upon the estimated fair value as of the acquisition date. The intangible assets have definite lives and are subject to amortization over their economic lives, currently ranging from approximately 10-15 years.

(3) Goodwill is measured as the excess of the total purchase consideration over the net acquisition date fair value of the assets acquired and liabilities assumed. Goodwill will not be amortized but will be tested for impairment at least annually or whenever certain indicators of impairment are present. If, in the future, it is determined that goodwill is impaired, an impairment charge would be recorded at that time. The factors that make up the goodwill reflected in the preliminary purchase price allocation include expected synergies, including future cost efficiencies with continual flow of activity of Alta Mesa production into the Kingfisher processing facility as the basin expands, as well as other benefits that are expected to be generated.

22

Unaudited Pro Forma Operating Results

The following unaudited pro forma combined financial information has been prepared as if the Business Combination and other related transactions had taken place on January 1, 2017. The unaudited pro forma consolidated financial information has been prepared using the acquisition method of accounting in accordance with GAAP.

The information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including depletion of Alta Mesa’s fair-valued proved oil and gas properties, and the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the 2018 Predecessor Period and the 2017 Predecessor Period, were adjusted to exclude $65.2 million of transaction-related costs incurred by Alta Mesa. These costs are not included as they are directly related to the Business Combination and are nonrecurring.

The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Business Combination taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.

	Three Months Ended		Three Months Ended
	March 31, 2018		March 31, 2017
	(in thousands)
Total operating revenues	$	112,037	$	75,452
Net income (loss)		(12,100)		25,265
Net income (loss) attributable to Alta Mesa Resources, Inc.		(5,281)		8,218
Basic and diluted net income (loss) per share	$	(0.03)	$	0.05

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

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

	Successor		Predecessor
	March 31,			December 31,
	2018			2017
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	899,465	$	84,590
Accumulated impairment of unproved properties		—		—
Unproved properties, net		899,465		84,590
Proved oil and natural gas properties		1,500,830		1,092,095
Accumulated depreciation, depletion, amortization and impairment		(10,773)		(256,122)
Proved oil and natural gas properties, net		1,490,057		835,973
TOTAL OIL AND NATURAL GAS PROPERTIES, net		2,389,522		920,563
OTHER PROPERTY AND EQUIPMENT
Land		4,954		2,912
Salt water disposal system		42,113		—
Plant and equipment		275,361		—
Office furniture and equipment, vehicles		979		20,008
Accumulated depreciation		(1,285)		(16,713)
OTHER PROPERTY AND EQUIPMENT, net		322,122		6,207
TOTAL PROPERTY, PLANT AND EQUIPMENT, net	$	2,711,644	$	926,770

NOTE 6 — DISCONTINUED OPERATIONS (Predecessor)

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

23

Prior to the Business Combination, Alta Mesa had notes payable to its founder (“Founder Notes”) that bear simple interest at 10%. In connection with the Transactions described in Note 1, the Founder Notes were converted into equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK 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 for the 2017 Predecessor Period.

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

	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

24

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

	Predecessor
	January 1, 2018		Three
	Through		Months Ended
	February 8, 2018		March 31, 2017
Loss from Discontinued Operations
Operating revenues and other:
Oil	$	1,617	$	12,405
Natural gas		1,023		3,094
Natural gas liquids		236		547
Other revenues		16		116
Total operating revenues		2,892		16,162
Loss on sale of assets		(1,923)		—
Total operating revenues and other		969		16,162
Operating expenses:
Lease operating expenses		1,770		7,960
Marketing and transportation		83		381
Production and ad valorem taxes		167		1,802
Workover expense		127		795
Exploration expense		—		3,095
Depreciation, depletion and amortization expense		630		5,826
Impairment		5,560		32
Accretion		101		476
General and administrative expense		21		12
Total operating expenses		8,459		20,379
Interest expense		(103)		(298)
Loss from discontinued operations, net of state income taxes	$	(7,593)	$	(4,515)

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

	Predecessor
	January 1, 2018		Three
	Through		Months Ended
	February 8, 2018		March 31, 2017
Total operating cash flows of discontinued operations	$	(6,838)	$	738
Total investing cash flows of discontinued operations		(570)		(910)

NOTE 7 — FAIR VALUE DISCLOSURES

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.

The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest.  In connection with the Business Combination, we recorded the fair value of Alta Mesa’s $500 million unsecured senior notes at $533.6 million as of the acquisition date. We have estimated the fair value of the senior notes to be $520.6 million at March 31, 2018.  This estimation is based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination. See Note 11 — Long-Term Debt, Net for information on long-term debt.

25

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

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

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

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

	Level 1		Level 2		Level 3		Total
	(in thousands)
At March 31, 2018: (Successor)
Financial Assets:
Derivative contracts for oil and natural gas		—	$	4,481		—	$	4,481
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	33,749		—	$	33,749
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.  Presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 8 — Derivative Financial Instruments.

NOTE 8 — DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

26

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

	Successor
	March 31, 2018
					Net Fair
	Gross		Gross amounts		Value of Assets
	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	1,539	$	(1,539)	$	—
Derivative financial instruments, long-term assets		2,942		(2,893)		49
Total	$	4,481	$	(4,432)	$	49

					Net Fair
	Gross		Gross amounts		Value of Liabilities
	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	27,940	$	(1,539)	$	26,401
Derivative financial instruments, long-term liabilities		5,809		(2,893)		2,916
Total	$	33,749	$	(4,432)	$	29,317

	Predecessor
	December 31, 2017
					Net Fair
	Gross		Gross amounts		Value of Assets
	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		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

					Net Fair
	Gross		Gross amounts		Value of Liabilities
	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		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

27

The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:

		Successor		Predecessor
Derivatives not	February 9, 2018		January 1, 2018		Three
designated as hedging	Through		Through		Months Ended
instruments under ASC 815	March 31, 2018		February 8, 2018		March 31, 2017
	(in thousands)
Gain (loss) on derivative contracts
Oil commodity contracts	$	(22,579)	$	5,431	$	26,085
Natural gas commodity contracts		(67)		1,867		3,899
Natural gas liquids commodity contracts		—		—		258
Total gain (loss) on derivative contracts	$	(22,646)	$	7,298	$	30,242

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the Alta Mesa Credit Facility described in Note 11— Long Term Debt, net.

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

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

OIL DERIVATIVE CONTRACTS

	Volume	Weighted		Range
Period and Type of Contract	in Bbls	Average		High		Low
2018
Price Swap Contracts	1,832,000	$	53.22	$	61.26	$	50.27
Collar Contracts
Short Call Options	1,559,000		61.09		64.60		60.50
Long Put Options	1,559,000		51.18		60.00		50.00
Short Put Options	1,559,000		41.48		52.50		40.00
2019
Collar Contracts
Short Call Options	1,788,500		61.84		65.35		56.50
Long Put Options	1,971,000		50.00		50.00		50.00
Short Put Options	1,971,000		38.43		40.00		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 March 31, 2018:

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in	Weighted		Range
Period and Type of Contract	MMBtu	Average		High		Low
2018
Price Swap Contracts	4,280,000	$	2.80	$	2.85	$	2.75
Collar Contracts
Short Call Options	1,985,000		3.30		3.75		3.14
Long Put Options	1,680,000		2.82		2.90		2.75
Short Put Options	610,000		2.40		2.40		2.40
2019
Collar Contracts
Short Call Options	1,350,000		3.47		3.75		3.30
Long Put Options	900,000		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 March 31, 2018:

NATURAL GAS BASIS SWAP DERIVATIVE CONTRACTS

						Weighted
						Average Spread
Volume in MMBtu (1)	Reference Price 1 (1)	Reference Price 2 (1)	Period			($ 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)

_________________

(1) Represents short swaps that fix the basis differentials between WAHA and NYMEX Henry Hub.

OIL BASIS SWAP DERIVATIVE CONTRACTS

						Weighted
						Average Spread
Volume in Bbl (1)	Reference Price 1  (1)	Reference Price 2  (1)	Period			($ per Bbl)
1,104,000	CMA Oil	WTI	July '18	—	Dec '18	$	(0.54)

_________________

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

NOTE 9 — INTANGIBLE ASSETS

Our intangible assets with finite lives include customer relationships within themidstream segment. Intangible assets consist of the following as of March 31, 2018 (in thousands):

	March 31, 2018
Customer Relationships	$	472,432
Accumulated amortization		(3,519)
Intangibles, net	$	468,913
Weighted average amortization (years)		12

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Amortization expense was $3.5 million for the Successor Period.  There was no amortization expense for the 2018 Predecessor Period and the 2017 Predecessor Period.  Estimated amortization expense for each of the subsequent five years and thereafter is as follows (in thousands):

Fiscal Year:	March 31, 2018
Remainder of 2018	$	15,839
2019		35,170
2020		42,002
2021		41,222
2022		40,562
Thereafter		294,118
Total amortization	$	468,913

There were no intangible assets at December 31, 2017.

NOTE 10 — ASSET RETIREMENT OBLIGATIONS

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

	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		421
Liabilities settled		(166)
Revisions to estimates		300
Accretion expense		102
Balance, as of March 31 (Successor)		6,655
Less: Current portion		622
Long-term portion	$	6,033

NOTE 11 — LONG-TERM DEBT, NET

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

	Successor		Predecessor
	March 31,		December 31,
	2018		2017
Alta Mesa senior secured revolving credit facility	$	—	$	117,065
Kingfisher secured revolving credit facility		52,000		—
7.875% senior unsecured notes due 2024		500,000		500,000
Unamortized premium on senior unsecured notes		32,815		—
Unamortized deferred financing costs		—		(9,625)
Total long-term debt, net	$	584,815	$	607,440

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Alta Mesa Senior Secured Revolving Credit Facility.  In connection with the consummation of the Business Combination, all indebtedness under the Alta Mesa 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—Description of Business), Alta Mesa entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Alta Mesa Credit Facility”). The Alta Mesa Credit Facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base.  In April 2018, the borrowing base was increased to $400.0 million until the next scheduled redetermination in October 2018.  The Alta Mesa Credit Facility does not permit Alta Mesa to borrow funds if at the time of such borrowing it is not in compliance with the financial covenants set forth in the Alta Mesa Credit Facility. As of March 31, 2018, Alta Mesa has no borrowings under the Alta Mesa Credit Facility and has $13.6 million of outstanding letters of credit reimbursement obligations.

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

The Alta Mesa Credit Facility contains restrictive covenants that may limit Alta Mesa’s 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 Alta Mesa Credit Facility permits Alta Mesa to make distributions to any parent entity (i) to pay for reimbursement of third party costs and expenses that are general and administrative expenses incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the Tax Receivable Agreement.  See Note 17 — Income Taxes for further information regarding the Tax Receivable Agreement.  In addition, Alta Mesa can make restricted payments, so long as certain conditions are met, to any direct or indirect parent for the sole purpose of making a loan or capital contribution to Kingfisher in an amount up to $300 million until August 9, 2018.

The Alta Mesa Credit Facility also requires Alta Mesa to maintain the following two financial ratios:

· a current ratio, tested quarterly, commencing within the fiscal quarter ending June 30, 2018, of Alta Mesa’s consolidated current assets to its 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 Alta Mesa’s consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to Alta Mesa’s 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 times 4/4ths, of not greater than 4.0 to 1.0.

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

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

Kingfisher Senior Secured Revolving Credit Facility.On August 8, 2017, Kingfisher entered into a $200 million revolving credit facility with a syndicate of lenders (the “Kingfisher Credit Facility”). The Kingfisher Credit Facility has a four-year term, with repayment due at maturity on August 8, 2021. ABN AMRO Capital USA LLC acts as agent, initial letter of credit issuer, bookrunner and lead arranger. The Kingfisher Credit Facility includes a letter of credit sublimit of $20 million for the issuance of letters of credit. Kingfisher has the option to increase its borrowing capacity under its revolving credit facility by an amount not to exceed $50 million (for a total commitment of $250 million subject to certain conditions). Kingfisher’s revolving credit facility is available to fund capital expenditures, working capital, general corporate purposes and to finance approved acquisitions.

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The Kingfisher Credit Facility is secured by substantially all of Kingfisher’s real property interests, pledged equity and intangibles. The applicable margins are dependent upon the Kingfisher’s leverage ratio, with the highest margins for Eurodollar Loans and Base Rate loans being 3.25% and 2.25%, respectively. The Kingfisher Credit Facility is subject to commitment fees ranging from 0.50% to 0.375% based on the leverage grid. Additionally the Kingfisher Credit Facility is subject to customary affirmative and negative covenants and events of default relating to Kingfisher.

As of March 31, 2018, the outstanding balance of the Kingfisher Credit Facility was $52.0 million.

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

The senior notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, Alta Mesa may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, Alta Mesa 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 Alta Mesa 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, Alta Mesa 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 Alta Mesa’s material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of Alta Mesa existing and future senior indebtedness; senior in right of payment to all of Alta Mesa existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of Alta Mesa existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Alta Mesa Credit Facility; and structurally subordinated to all existing and future indebtedness and obligations of any of Alta Mesa 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 Alta Mesa’s line of business. 

Under the terms of the indenture for the senior notes, if Issuers 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 Alta Mesa to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase. The closing of the Business Combination did not constitute a change of control under the indenture governing the senior notes because certain existing owners of Alta Mesa and SRII Opco entered into an amended and restated voting agreement with respect to the voting interests in Alta Mesa GP.  See Note 4 — 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 of 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;

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· 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 $20.0 million.

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

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

Bond Premium (Successor).  As discussed in Note 6,  the fair value of the Alta Mesa 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 Alta Mesa senior notes.  The bond premium amortization recorded in the Successor Period was $0.8 million.  The unamortized bond premium related to the senior notes are netted with long-term debt on the consolidated balance sheet as of March 31, 2018. 

Maturities (Successor).  Future maturities of long-term debt, excluding unamortized bond premium, at March 31, 2018 are as follows:

	(in thousands)
2019	$	—
2020		—
2021		52,000
2022		—
2023		500,000
Thereafter		—
	$	552,000

Deferred financing costs.As of December 31, 2017, Alta Mesa had $11.4 million of unamortized deferred financing costs.  As a result of the Business Combination, the 2018 Predecessor Period deferred financing costs have been adjusted to a fair value of zero at February 9, 2018.  During the Successor Period, we incurred new deferred financing costs related to Alta Mesa’s Credit Facility of $1.0 million.  Amortization expense of zero,  $0.2 million and $1.0 million is included in interest expense on the consolidated statements of operations for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. 

NOTE 12 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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

	Successor		Predecessor
	March 31,		December 31,
	2018		2017
Capital expenditures	$	50,117	$	48,771
Revenues and royalties payable		31,861		29,514
Operating expenses/taxes		23,138		14,632
Interest		12,355		2,587
Derivative settlement payable		2,826		2,106
Other		540		4,301
Total accrued liabilities		120,837		101,911
Accounts payable		38,273		68,578
Accounts payable and accrued liabilities	$	159,110	$	170,489

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NOTE 13 — COMMITMENTS AND CONTINGENCIES

Contingencies

Environmental claims. Various landowners have sued Alta Mesa in lawsuits concerning several fields in which Alta Mesa has 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 its oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our condensed consolidated financial statements at March 31, 2018.

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

Litigation (Predecessor).On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” a former subsidiary of Alta Mesa), 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 Alta Mesa and Oklahoma Energy Acquisitions, LP and Alta Mesa Services, LP, each a wholly owned subsidiary of Alta Mesa, (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty.  The suit alleges that the AMH Parties made improper post production deductions for midstream services 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, Alta Mesa accrued approximately $4.7 million in accounts payable and accrued liabilities in its consolidated balance sheets and in general and administrative expense in its consolidated statements of operations in connection with this litigation. On March 12, 2018, the Class settlement was approved by the Court.  During January 2018, approximately $4.7 million was paid to fund the settlement.

On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries.  Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to us in contravention of these agreements.  Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only.  Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants.  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, Alta Mesa 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 Alta Mesa.  Under the Plan, participants were granted performance appreciation rights (“PARs”) with a stipulated initial designated value. The Business Combination described in Note 4 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 was recorded in general and administrative expense in the 2018 Successor Period.  Following the closing of the Business Combination, the Plan was terminated.

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Nonqualified Deferred Compensation: In 2013, Alta Mesa 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 Business Combination, we terminated the Retirement Plan resulting in approximately $9.4 million being recorded in general and administrative expense in the Successor Period. 

Commitments

Office and Equipment Leases. We lease office space, as well as certain field equipment such as compressors, under long-term operating lease agreements.  The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease.  Equipment leases are generally for two years or less. Total rent expense, net of sublease income, including office space and compressors, were approximately $1.5 million, $1.1 million, and $2.6 million for the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively.

At March 31, 2018, the future minimum base rentals for non-cancelable operating leases are as follows: 

	(in thousands)
Remainder of 2018	$	1,284
2019		1,545
2020		1,593
2021		1,620
2022		839
Thereafter		368
	$	7,249

Firm transportation contracts.  The Company has entered into certain firm transportation contracts that extend through 2036.  At March 31, 2018, the future minimum commitments related to these contracts are as follows:

	(in thousands)
Remainder of 2018	$	9,702
2019		10,976
2020		7,876
2021		7,876
2022		7,876
Thereafter		84,742
	$	129,048

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 8 — Derivative Financial Instruments for further details on derivatives.

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NOTE 15 — SHAREHOLDERS’ EQUITY AND PARTNERS’ CAPITAL

Redeemable Preferred Stock and Shareholders’ Equity (Successor)

Class A Common Stock.Holders of our Class A Common Stock are entitled to one vote for each share held on all matters to be voted on by our stockholders. Holders of the Class A Common Stock and holders of the Class C Common Stock will vote together as a single class on all matters submitted to a vote of our stockholders, except as required by law. Unless specified in our certificate of incorporation (including any certificate of designation of preferred stock) or the Bylaws, or as required by applicable provisions of the Delaware General Corporation Law or applicable stock exchange rules, the affirmative vote of a majority of our shares of common stock that are voted is required to approve any such matter voted on by our stockholders. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50% of the shares voted for the election of directors can elect all of the directors (subject to the right of the holders of our Series A Preferred Stock and Series B Preferred Stock to nominate and elect up to seven directors). Subject to the rights of the holders of any outstanding series of preferred stock, our stockholders are entitled to receive ratable dividends when, as and if declared by the board of directors out of funds legally available therefor.

In the event of a liquidation, dissolution or winding up of the Company, the holders of the Class A Common Stock are entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the Class A Common Stock. Our stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the Class A Common Stock.

Class C Common Stock.  In connection with the Business Combination, we issued 213,402,398 shares of Class C Common Stock to the Contributors which are outstanding as of March 31, 2018.

Holders of Class C Common Stock, together with holders of Class A Common Stock voting as a single class, will have the right to vote on all matters properly submitted to a vote of the stockholders. In addition, the holders of Class C Common Stock, voting as a separate class, will be entitled to approve any amendment, alteration or repeal of any provision of our certificate of incorporation that would alter or change the powers, preferences or relative, participating, optional or other or special rights of the Class C Common Stock. Holders of Class C Common Stock will not be entitled to any dividends from the Company and will not be entitled to receive any of our assets in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.

Shares of Class C Common Stock may be issued only to the Contributors, their respective successors and assigns, as well as any permitted transferees of the Contributors. A holder of Class C Common Stock may transfer shares of Class C Common Stock to any transferee (other than the Company) only if such holder also simultaneously transfers an equal number of such holder’s SRII Opco Common Units to such transferee in compliance with the amended and restated limited partnership agreement of SRII Opco. The Contributors generally have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. The Company may, however, at its option, effect a direct exchange of cash or Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption by SRII Opco. Upon the future redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be cancelled.

Redeemable Series A Preferred Stock.As of March 31, 2018, Bayou City Energy Management LLC (“Bayou City”), HPS Investment Partners, LLC (“HPS”) and AM Equity Holdings, LP (“AM Management”) own the three outstanding shares of our Series A Preferred Stock, and may not transfer the Series A Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate. The holders of the Series A Preferred Stock are not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holders are not entitled to any dividends from the Company but will be entitled to receive, after payment or provision for debts and liabilities and prior to any distribution in respect of our Class A Common Stock or any other junior securities, liquidating distributions in an amount equal to $0.0001 per share of Series A Preferred Stock in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.

The Series A Preferred Stock is not convertible into any other security of the Company, but will be redeemable for the par value thereof by us upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series A Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. For so long as the Series A Preferred Stock remains outstanding, the holders of the Series A Preferred Stock will be entitled to nominate and elect directors to our board of directors for a period of five years following the closing of the Business Combination based on their and their affiliates’ beneficial ownership of Class A Common Stock. 

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Redeemable Series B Preferred Stock.As of March 31, 2018, the Riverstone Contributor owns the only outstanding share of our Series B Preferred Stock, and may not transfer the Series B Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate (as defined in the limited partnership agreement of SRII Opco). The holder of the Series B Preferred Stock is not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holder is not entitled to any dividends from the Company but will be entitled to receive, after payment or provision for debts and liabilities and prior to any distribution in respect of our Class A Common Stock or any other junior securities, liquidating distributions in an amount equal to $0.0001 per share of Series B Preferred Stock in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.

The Series B Preferred Stock is not convertible into any other security of the Company, but will be redeemable for the par value thereof by us upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series B Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. For so long as the Series B Preferred Stock remains outstanding, the holder of the Series B Preferred Stock will be entitled to nominate and elect directors to our board of directors for a period of five years following the closing of the Business Combination based on its and its affiliates’ beneficial ownership of Class A Common Stock.

Public Warrants. As of March 31, 2018, the Company had 62,966,666 warrants outstanding, consisting of 34,500,000 public warrants originally sold as part of the Units in the IPO (“Public Warrants”) and 13,333,333 Private Placement Warrants sold to the Company’s Sponsor in a private placement. Additionally, in connection with the Business Combination, we issued 15,133,333 Forward Purchase Warrants to Riverstone VI SR II Holdings, LP.

Each whole Public Warrant entitles the holder to purchase one whole share of our Class A Common Stock for $11.50 per share. The warrants become exercisable 12 months from February 9, 2018 and will expire February 9, 2023 or earlier upon redemption or liquidation.  Pursuant to the warrant agreement, a warrant holder may exercise its Public Warrants only for a whole number of shares of Class A Common Stock. No fractional Public Warrants have been issued and only whole Public Warrants trade. 

No Public Warrant will be exercisable and the Company will not be obligated to issue shares of Class A Common Stock upon exercise of a Public Warrant unless Class A Common Stock issuable upon such exercise has been registered, qualified or deemed to be exempt under the securities laws of the state of residence of the registered holder of the Public Warrants. In the event that the conditions in the two immediately preceding sentences are not satisfied with respect to a Public Warrant, the holder of such Public Warrant will not be entitled to exercise such Public Warrant and such Public Warrant may have no value and expire worthless.

Private Placement Warrants. As of March 31, 2018, 15,133,333 Private Placement Warrants remained outstanding. The Private Placement Warrants are identical to the public warrants underlying the Units sold in the Initial Public Offering.

Forward Purchase Warrants.  The Forward Purchase Warrants have terms and provisions that are identical to those of the Private Placement Warrants, including as to exercise price, exercisability and exercise period, except the Forward Purchase Warrants are not subject to the lock-up that is applicable to the Private Placement Warrants. The Forward Purchase Warrants were sold in a private placement pursuant to a purchase agreement between us and our Sponsor and have the terms set forth in a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and the Company.

Noncontrolling Interest.  The noncontrolling interest relates to SRII Opco Common Units that were originally issued to the Alta Mesa Contributor, the Kingfisher Contributor and the Riverstone Contributor in connection with the Business Combination and continue to be held by holders other than the Company. At the date of the Business Combination, the noncontrolling interest held 55.8% (Alta Mesa Contributor 36.2%, Kingfisher Contributor 14.4%, and Riverstone Contributor 5.2%) of the ownership in SRII Opco. The noncontrolling interest percentage is affected by various equity transactions such as Class C Common Stock conversions and Class A Common Stock activities.

The Company has consolidated the financial position, results of operations and cash flows of SRII Opco and reflected that portion retained by other holders of Common Units as a noncontrolling interest.

Management and Control.  Alta Mesa’samended and restatedpartnership 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 Alta Mesa GP (as defined below) referred to as “GP Units”.  Alta Mesa GP owns all the GP Units and SRII Opco owns all the LP Units. 

Since Alta Mesa is a limited partnership, its operations and activities are managed by the board of directors (the “Board of Directors”) of its general partner, Alta Mesa 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 Alta Mesa GP and (ii) Class B Units, which hold 100% of the voting interests in Alta Mesa GP. 

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SRII Opco is the sole owner of Alta Mesa’s 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, and HPS, own an aggregate 10% of the Class B Units.  Alta Mesa GP’s Board of Directors are selected by the Class B Members.  Notwithstanding the foregoing, voting control of Alta Mesa GP is vested in SRII Opco pursuant to a voting agreement.

All distributions under Alta Mesa’s amended and restated partnership agreement are made to the limited partners pro rata when Alta Mesa GP so directs.

NOTE 16 — EQUITY BASED COMPENSATION (Successor)

Following the closing of the Business Combination, we adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”).  A total of 50,000,000 shares of 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”), nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other stock-based awards in Class A Common Stock. Pursuant to the LTIP, certain grants of stock-based awards were deemed granted on February 9, 2018.  During the Successor Period, the Company recognized non-cash stock-based compensation expense of $3.5 million resulting from stock option, 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 have service-based vesting schedules of three years. The exercise for an option under the LTIP may not be below the fair value of the Company’s Class A Common Stock on the grant date.  On the Closing Date, the Company granted 4,143,231 stock options to employees.

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

	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	4,143,231		4.62	4.3
Exercised	—		—	—
Forfeited or expired	—		—	—
Outstanding as of March 31, 2018	4,143,231		4.62	4.3	$	19,129
Exercisable as of March 31, 2018	—	$	—	—	$	—

Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period.  The Company estimates the fair value using the Black-Scholes option-pricing model.  Expected volatilities are based on the re-levered asset volatility implied by a set of comparable companies.  Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date.  The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.

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

	Successor
	February 9, 2018
	Through
	March 31, 2018
Expected term (in years)	4.5
Expected stock volatility	64.5%
Dividend yield	—
Risk-free interest rate	2.4%

As of March 31, 2018, there was $18.1 million of unrecognized compensation cost related to non-vested stock options. The Company expects to recognize that cost on a pro rata basis over a weighted average period of 2.8 years.

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Restricted stock.  On February 9, 2018, the Company granted 73,376 fully-vested restricted stock awards to certain of its directors and 1,160,094 restricted stock awards to employees, one third of which vest on each anniversary of the grant date over three years, subject to the employee’s continued service.

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

	Successor
	Restricted Stock Awards		Weighted Average Grant - Date Fair Value per share
Outstanding as of February 9, 2018		—	$	—
Granted		1,233,470		8.94
Exercised		—		—
Forfeited or expired		—		—
Outstanding as of March 31, 2018		1,233,470	$	8.94

Compensation cost for the service-based vesting restricted shares is based upon the grant-date market value of the award, recognized ratably over the applicable vesting period.  Unrecognized compensation cost related to unvested restricted shares at March 31, 2018 was $9.8 million, which the Company expects to recognize over a weighted average period of 2.8 years.

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

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

	Successor
	RSUs		Weighted Average Grant - Date Fair Value per unit
Outstanding as of February 9, 2018		—	$	—
Granted		718,163		8.94
Exercised		—		—
Forfeited or expired		—		—
Outstanding as of March 31, 2018		718,163	$	8.94

As of March 31, 2018, there was $5.3 million of unrecognized compensation cost related to the unvested RSUs which we expect to recognize on a pro rata basis over a weighted average period of 0.8 years.

NOTE 17 — INCOME TAXES

As a result of the Business Combination, the Company’s wholly owned subsidiary, SRII Opco GP, is the general partner of SRII Opco who became the sole managing member of Alta Mesa GP and Kingfisher, and as a result, we began consolidating the financial results of Alta Mesa and Kingfisher. SRII Opco is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, SRII Opco is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by SRII Opco is passed through to and included in the taxable income or loss of its limited partners, including the Company, on a pro rata basis. The Company is subject to U.S. federal income taxes, in addition to state and local income taxes with respect to its allocable share of any taxable income or loss of SRII Opco, as well as any stand-alone income or loss generated by the Company.

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Income tax benefit recorded in the Successor Period is based on applying an estimated annual effective income tax rate to the net loss incurred from February 9, 2018 through March 31, 2018.  There were no significant unusual or infrequently occurring items which are required to be recorded as discrete items in the Successor Period.  The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgement including, but not limited to, the Successor’s expected operating income for the year, projections of the proportion of income earned and taxed in various jurisdictions, the effect of non-controlling interest, permanent and temporary differences and the likelihood of recovering deferred tax assets in the current year  the accounting estimates used to compute the income tax benefit may change as new events occur, more experience is obtained, additional information becomes known or as the tax environment changes.

Income tax (expense) benefit are included in the consolidated statements of operations are detailed below (in thousands):

	Successor
	February 9, 2018
	Through
	March 31, 2018
Current taxes:
Federal	$	—
State		—
		—
Deferred taxes:
Federal		(3,111)
State		(702)
		(3,813)
Income tax benefit	$	(3,813)

In connection with the completion of the Business Combination, we entered into the Tax Receivable Agreement with SRII Opco, the AM Contributor, and the Riverstone Contributor. This agreement generally provides for the payment by us of 85% of the amount of net cash savings, if any, in U.S. federal, state and local income tax that we actually realize (or are deemed to realize in certain circumstances) in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for AMR Class A Common Stock (or, in certain circumstances, cash) pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by Kingfisher or otherwise used in Kingfisher’s midstream business, and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings.

The payment obligations under the Tax Receivable Agreement are obligations of the Company and not obligations of SRII Opco, and we expect that the payments we will be required to make under the Tax Receivable Agreement may be substantial. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been entitled to any of the tax benefits subject to the Tax Receivable Agreement. In other words, we would calculate our federal, state and local income liabilities as if no tax attributes arising from a redemption or direct exchange of SRII Opco Common Units had been transferred to us. The term of the Tax Receivable Agreement will continue until all such tax benefits have been utilized or have expired, unless we exercise our right to terminate the Tax Receivable Agreement or the Tax Receivable Agreement is otherwise terminated.

As of March 31, 2018, no exchange of SRII Common Units has occurred and there has not been an early termination under the Tax Receivable Agreement; therefore, we have not recorded a Tax Receivable Agreement liability at this time.

The AM Contributor, the Riverstone Contributor, and their permitted transferees (together, the “TRA Holders”) will not reimburse us for any cash payments previously made under the Tax Receivable Agreement if any tax benefits initially claimed by us are challenged by the IRS or other relevant tax authority and are ultimately disallowed, except that excess payments made to TRA Holders will be netted against payments otherwise to be made, if any, to the TRA Holders after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

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Additionally, if the Tax Receivable Agreement terminates early (at our election or as a result of our material breach of our obligations under the Tax Receivable Agreement, whether as a result of our failure to make any payment when due, failure to honor any other material obligation under it or by operation of law as a result of the rejection of the Tax Receivable Agreement in a case commenced under the United States Bankruptcy Code or otherwise), we would be required to make a substantial, immediate lump-sum payment. This payment would equal the present value of hypothetical future payments that could be required to be paid under the Tax Receivable Agreement (calculated using a discount rate of 18%). The calculation of the hypothetical future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including that (i) we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement, (ii) all taxable income of the Company is subject to the maximum applicable tax rates throughout the relevant period and (iii) certain loss or credit carryovers will be utilized through the expiration date of such carryovers.

Payments will generally be due under the Tax Receivable Agreement within 30 days following the finalization of the schedule with respect to which the payment obligation is calculated, although interest on such payments will begin to accrue from the due date (without extensions) of such tax return until such payment due date at a rate equal to LIBOR, plus 100 basis points. Except in cases where we elect to terminate the Tax Receivable Agreement early or we have available cash but fail to make payments when due, generally we may elect to defer payments due under the Tax Receivable Agreement if we do not have available cash to satisfy our payment obligations under the Tax Receivable Agreement or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the Tax Receivable Agreement generally will accrue interest at a rate of LIBOR plus 500 basis points; provided, however, that interest will accrue at a rate of LIBOR plus 100 basis points if we are unable to make such payment as a result of limitations imposed by existing credit agreements.

Because we are a holding company with no operations of our own, our ability to make payments under the Tax Receivable Agreement is dependent on the ability of SRII Opco to make distributions to us in an amount sufficient to cover our obligations under the Tax Receivable Agreement; this ability, in turn, may depend on the ability of SRII Opco’s subsidiaries to make distributions to it. The ability of SRII Opco and its subsidiaries to make such distributions will be subject to, among other things, the applicable provisions of Delaware law that may limit the amount of funds available for distribution and restrictions in relevant debt instruments issued by SRII Opco and/or its subsidiaries. To the extent that we are unable to make payments under the Tax Receivable Agreement for any reason, such payments will be deferred and will accrue interest until paid.

NOTE 18 — RELATED PARTY TRANSACTIONS

Alta Mesa entered into a promissory note receivable with its affiliate Northwest Gas Processing, LLC, a Delaware limited liability company (“NWGP”), effective September 29, 2017, for approximately $1.5 million.  The promissory note was issued by NWGP to Alta Mesa and bears interest (or paid-in-kind interest from time to time) on the principal balance at a rate of 8% per annum, with interest payable in quarterly installments beginning January 1, 2018, and matures on February 28, 2019.  During the fourth quarter 2017, the $1.5 million promissory note was transferred from NWGP to High Mesa Services, LLC.

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement were approximately $36,000,  $28,000, and $43,000 for the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively. The contract may be terminated by either party without penalty upon 30 days’ notice.  These amounts are recorded in general and administrative expense (“G&A”) on the consolidated statements of operations.

David McClure, our Vice President of Facilities and Midstream, and the son-in-law of our Chief Executive Officer, Harlan H. Chappelle, received total compensation of approximately $44,500,  $938,500, and $67,500 for the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively. These amounts are recorded in G&A expense on the consolidated statements of operations.

David Pepper, one of our Landmen, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $23,200,  $153,100, and $38,700 for the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively. These amounts are recorded in G&A expense on the consolidated statements of operations.

On January 13, 2016, Alta Mesa’s 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 Alta Mesa’s drilling operations and to allow Alta Mesa 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.  As of March 31, 2018, 67 joint wells have been drilled or spudded leaving 13 wells to be drilled under the joint development agreement.

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Under the joint development agreement, as amended on December 31, 2016, BCE committed to fund 100% of Alta Mesa’s 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, we and BCE will each bear our respective proportionate working interest share of all subsequent costs and expenses related to such joint well.  Mr. McMullen, our director, 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.  As of March 31, 2018 and December 31, 2017, we recorded $40.5 million and $23.4 million in advances from related party on our consolidated balance sheets, which represents net advances from BCE for their working interest share of the drilling and development cost as part of the joint development agreement. During the Successor Period, BCE advanced us approximately $39.5 million to drill additional wells under the joint development agreement.

Management Services Agreement-High Mesa

In connection with the Closing, we entered into a management services agreement (the “High Mesa Agreement”) with High Mesa with respect to our non-STACK assets that were distributed to High Mesa’s subsidiary in connection with the business combination. Under the High Mesa Agreement, during the 180-day period following the Closing (the “Initial Term”), we will provide certain administrative, management and operational services necessary to manage the business of High Mesa and its subsidiaries (the “Services”), in each case, subject to and in accordance with an approved budget. Thereafter, the High Mesa Agreement shall automatically renew for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. For a period of 60 days following the expiration of the term, we are obligated to assist High Mesa with the transition of the Services from Alta Mesa to a successor service provider. As compensation for the Services, including during any transition to a successor service provider, High Mesa will pay us each month (i) a management fee of $10,000, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses incurred in connection with any emergency. As of March 31, 2018 and December 31, 2017, approximately $7.9 million and $0.8 million, respectively, were due from High Mesa for reimbursement of expenses which is recorded in the receivables due from related party on the consolidated balance sheets.

We have a note receivable due from High Mesa Services, LLC (“HMS”), a subsidiary of High Mesa.  The $8.5 million long-term note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019.  As of March 31, 2018, and December 31, 2017, the balance of the note receivable amounted to $11.0 million and $10.8 million, respectively.  The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve.  Interest income on the note receivable from our affiliate amounted to approximately $0.1 million, $0.1 million and $0.2 million for the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period.  Such amounts have been added to the balance of the note receivable.

NOTE 19 — SUBSIDIARY GUARANTORS

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

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NOTE 20 — BUSINESS SEGMENT INFORMATION

We disclose the results of our reportable segments in accordance with ASC 280, Segment Reporting.  As a result of the Business Combination, the company has two reportable segments: (1) Exploration & Production and (2) Midstream.  These segments represent the Company’s two operating units, each offering different products and services.  Each segment is led by the Company’s Chief Operating Decision Maker (“CODM”).  The CODM evaluates segment performance using operating income, which is defined as total operating and other revenue less total operating expenses. The Company’s corporate activities have been allocated to the supported business segments accordingly.  The company had one reportable segment in the 2018 Predecessor Period and 2017 Predecessor period. For additional information regarding the Company’s reportable segments, see Note 2 — Summary of Significant Accounting Policies.  

	Successor
	February 9, 2018 Through March 31, 2018
	Exploration and
	Production		Midstream		Eliminations			Total
	(in thousands)
Operating revenues from external customers	$	27,353	$	18,517	$	—	$	45,870
Operating inter-segment revenues		6,737		4,562		(11,299)		—
Total operating revenues		34,090		23,079		(11,299)		45,870
Operating income (loss)		(29,921)		(1,618)		—		(31,539)
Other income (expense)		(4,650)		(248)		—		(4,898)
Segment net income (loss) before tax	$	(34,571)	$	(1,866)	$	—	$	(36,437)
Corporate general and administrative expenses								925
Income (loss) from continuing operations before income taxes							$	(37,362)

The following table summarizes our revenue by product line.

	Successor
	February 9, 2018 Through March 31, 2018
	Exploration and
	Production		Midstream		Eliminations			Total
	(in thousands)
Product line revenue:
Oil sales	$	40,278	$	—	$	—	$	40,278
Natural gas sales		5,210		—		—		5,210
Natural gas liquids sales		4,714		—		—		4,714
Product sales		—		15,106		(6,737)		8,369
Gathering and processing revenue		—		7,973		(4,562)		3,411
Total product line revenue (1)	$	50,202	$	23,079	$	(11,299)	$	61,982

_________________

(1) Total product line revenue excludes other revenue and gain (loss) on derivative contracts.

The following table summarizes total assets by segment:

	Successor
	March 31, 2018
	Exploration and
	Production		Midstream		Eliminations			Total
	(in thousands)
Total segment assets	$	2,828,379	$	1,415,497	$	(4,092)	$	4,239,784
Corporate assets								3,755
Total assets							$	4,243,539

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NOTE 21 — SUBSEQUENT EVENTS

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

Cimarron Express Pipeline.  On May 10, 2018, a subsidiary of Kingfisher and Blueknight Energy Partners, L.P. (“Blueknight”), an unaffiliated third party, entered into definitive agreements for the purpose of constructing and operating a new crude oil pipeline serving STACK producers in central Oklahoma.  The 65-mile, 16-inch crude oil pipeline, which will be owned by Cimarron Express Pipeline, LLC (“Cimarron Express”) and constructed and operated by an affiliate of Blueknight, will extend from northeastern Kingfisher County, Oklahoma, to Blueknight’s crude oil terminal in Cushing, Oklahoma. The receipt terminal for the newly constructed pipeline will be located at Kingfisher’s crude oil storage facility located in northeastern Kingfisher County, where it will have connectivity to Kingfisher’s crude oil gathering system and truck unloading facilities. The pipeline will provide direct market access at Cushing for producers and will have an initial capacity of 90,000 barrels per day, expandable to over 175,000 barrels per day.  Cimarron Express is owned 50% by an affiliate of Kingfisher and 50% by an affiliate of Ergon, Inc.  In connection with the transaction, Alta Mesa entered into a long-term acreage dedication and transportation agreement with Cimarron Express, which includes the dedication of the production from approximately 120,000 net acres in Kingfisher and Garfield counties in Oklahoma.

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

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

Overview

We were a blank check company incorporated as a Delaware corporation and formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses.  On February 9, 2018 (the “Closing Date”), we consummated the acquisition of (i) all of the limited partnership interests in Alta Mesa Holdings, LP (“Alta Mesa”), (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa Holdings GP, LLC, Alta Mesa’s sole general partner (“Alta Mesa GP”) and (iii) all of the membership interests in Kingfisher Midstream, LLC (“Kingfisher”), pursuant to:

· the Contribution Agreement, dated as of August 16, 2017 (the “AM Contribution Agreement”), among High Mesa Holdings, LP (the “AM Contributor”), High Mesa Holdings GP, LLC, the sole general partner of the AM Contributor, Alta Mesa, Alta Mesa GP, LLC, us and the equity owners of the AM Contributor;

· the Contribution Agreement, dated as of August 16, 2017 (the “KFM Contribution Agreement”), among KFM Holdco, LLC (the “KFM Contributor”), Kingfisher, us and the equity owners of the KFM Contributor; and

· the Contribution Agreement, dated as of August 16, 2017 (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”), between Riverstone VI Alta Mesa Holdings, L.P. (the “Riverstone Contributor” and, together with the AM Contributor and the KFM Contributor, the “Contributors”) and us.

The acquisition of Alta Mesa 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.”

At the closing of the Business Combination (the “Closing”),

· we issued 40,000,000 shares of Class A Common Stock and warrants to purchase 13,333,333 shares of Class A Common Stock to Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”) pursuant to the terms of that certain Forward Purchase Agreement, dated as of March 17, 2017 (the “Forward Purchase Agreement”) for cash proceeds of $400.0 million to us;

· we contributed $1,406.4 million in cash (the proceeds of the Forward Purchase Agreement and the net proceeds (after redemptions) of the Trust Account) to SRII Opco, LP, a Delaware limited partnership (“SRII Opco”), in exchange for (i) 169,371,730 of the common units (approximately 44.2%) representing limited partner interests (the “SRII Opco Common Units”) in SRII Opco issued to us and (ii) 62,966,666 warrants to purchase SRII Opco Common Units (“SRII Opco Warrants”) issued to us;

· we caused SRII Opco to issue 213,402,398 SRII Opco Common Units (approximately 55.8%) to the Contributors in exchange for the ownership interests in Alta Mesa, Alta Mesa GP and Kingfisher contributed to SRII Opco by the Contributors;

· we agreed to cause SRII Opco to issue up to 59,871,031 SRII Opco Common Units to the AM Contributor and the KFM Contributor if the earn-out consideration provided for in the Contribution Agreements is earned by the AM Contributor or the KFM Contributor pursuant to the terms of the Contribution Agreements;

· we issued to each of the Contributors a number of shares of Class C common stock, par value $0.0001 per share (the “Class C Common Stock”) equal to the number of the SRII Opco Common Units received by such Contributor at the Closing;

· SRII Opco distributed to the KFM Contributor cash in the amount of approximately $814.8 million in partial payment for the ownership interests in Kingfisher contributed by the KFM Contributor; and

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· SRII Opco entered into an amended and restated voting agreement with the owners of the remaining 10% voting interests in Alta Mesa GP whereby such other owners agreed to vote their interests in Alta Mesa GP as directed by SRII Opco.

In connection with the Closing, we also issued (i) one share of Series A Preferred Stock, par value $0.0001 per share (“Series A Preferred Stock”), to each of Bayou City Energy Management, LLC (“Bayou City”), HPS Investment Partners, LLC (“HPS”), and AM Equity Holdings, LP (“AM Management”), and (ii) one share of Series B Preferred Stock, par value $0.0001 per share (“Series B Preferred Stock”), to the Riverstone Contributor. For so long as the Series A Preferred Stock or Series B Preferred Stock remains outstanding, as applicable, the holders thereof are entitled to nominate and elect directors to our board of directors for a period of up to five years following the Closing based on their and their affiliates’ beneficial ownership of Class A Common Stock.

Pursuant to the AM Contribution Agreement and the KFM Contribution Agreement, for a period of seven years following the Closing, the AM Contributor and the KFM Contributor may be entitled to receive additional SRII Opco Common Units (and a corresponding number of shares of Class C Common Stock) as earn-out consideration if the 20-Day VWAP of the Class A Common Stock equals or exceeds specified prices as follows (each such payment, an “Earn-Out Payment”):

		Earn-Out Consideration Payable to	Earn-Out Consideration Payable to
20-Day VWAP		AM Contributor	KFM Contributor
$	14.00	10,714,285 SRII Opco Common Units	7,142,857 SRII Opco Common  Units
$	16.00	9,375,000 SRII Opco Common Units	6,250,000 SRII Opco Common Units
$	18.00	13,888,889 SRII Opco Common Units	—
$	20.00	12,500,000 SRII Opco Common Units	—

The AM Contributor and the KFM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of our 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.

On February 6, 2018, our stockholders voted to approve the Business Combination. In connection with that vote, the holders of shares of Class A Common Stock originally sold as part of the units issued in our IPO (such holders, the “public stockholders”), were provided with the opportunity to redeem shares of Class A Common Stock then held by them for cash equal to approximately $10.00 per share. Public holders of 3,270 shares of Class A Common Stock elected to redeem those shares and, at the Closing, $32,944 held in the Trust Account was paid to such redeeming shareholders and the remaining $1,042.7 million held in the Trust Account was disbursed to us. We used these funds, along with the proceeds of the Forward Purchase Agreement, to fund our obligations under the Contribution Agreements and to pay the underwriters’ deferred discount.

In connection with the closing of the Business Combination, the Company changed its name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.” and continued the listing of its Class A Common Stock and Public Warrants on NASDAQ under the symbols “AMR” and “AMRWW,” respectively. Following the Business Combination, our only significant asset is our ownership of an approximate 44.2% partnership interest in SRII Opco. SRII Opco owns all of the economic interests in each of Alta Mesa (which owns our E&P Business) and Kingfisher (which owns our Midstream Business).  Refer to Note 4 —Business Combination (Successor) for further discussion of the Business Combination.

Alta Mesa is an exploration and production company focused on the development and acquisition of unconventional oil and natural gas reserves in the eastern portion of the Anadarko Basin referred to as the STACK. Kingfisher owns and operates midstream oil and gas assets in the STACK and its operations are primarily comprised of crude oil gathering, natural gas gathering and processing of products.  The STACK is an acronym describing both its location — Sooner Trend Anadarko Basin Canadian and Kingfisher County — and the multiple, stacked productive formations present in the area. Alta Mesa has transitioned its focus from its prior diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities. The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates.  Alta Mesa maintains operational control of the majority of its exploration and production properties, either through directly operating them or through operating arrangements with other interest owners. 

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Distribution of Non-Stack Assets

On February 8, 2018, Alta Mesa distributed the remainder of its non-STACK assets to the AM Contributor as a dividend.  The Founder Notes were converted into equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK assets.  The balance of the Founder Notes at the time of conversion was approximately $28.3 million including accrued interest.  Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period and $0.3 million for the 2017 Predecessor Period.

Presentation of Financial and Operating Data

As a result of the Business Combination, we are treated as the accounting acquirer and Alta Mesa is the accounting acquiree and the accounting predecessor.  Pursuant to Accounting Standard Codification (“ASC”) 805, Business Combinations (“ASC 805”), the identifiable assets acquired and liabilities assumed were provisionally recorded at their estimated fair values on the Closing Date of the Business Combination (also referred to herein as the “acquisition date”).  As a result of the application of the acquisition method of accounting resulting from the Business Combination, the financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented.  The Successor period is from February 9, 2018 to March 31, 2018 (“Successor Period”) and the Predecessor periods are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”) and for the three months ended March 31, 2017 (“2017 Predecessor Period”).

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

As noted above, Alta Mesa distributed the remainder of its non-STACK assets to the AM Contributor in connection with the closing of the Business Combination.  The distribution of its remaining non-STACK assets during the first quarter of 2018 and the sale of its Weeks Island field during the fourth quarter of 2017 (collectively, the “non-STACK assets”) were part of Alta Mesa’s overall strategic shift to operate only in the eastern Anadarko Basin.  As a result, the Predecessor’s assets and liabilities and operating results directly related to non-STACK assets are presented as discontinued operations within the consolidated financial statements. See Note 6 — Discontinued Operations (Predecessor) for further discussion.

Alta Mesa is an exploration and production company focused on the development and acquisition of unconventional oil and natural gas reserves in the eastern portion of the Anadarko Basin referred to as the STACK. Kingfisher owns and operates midstream oil and gas assets in the STACK and its operations are primarily comprised of crude oil gathering, natural gas gathering and processing of products.  The STACK is an acronym describing both its location — Sooner Trend Anadarko Basin Canadian and Kingfisher County — and the multiple, stacked productive formations present in the area. Alta Mesa has transitioned its focus from its prior diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities. The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates.  Alta Mesa maintains operational control of the majority of its exploration and production properties, either through directly operating them or through operating arrangements with other interest owners. 

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. 

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

							Three Months Ended
		2018					March 31,
		Jan-18		Feb-18		Mar-18	2018		2017		Change		%
Average NYMEX daily prices:
Oil (per bbl)	$	63.55	$	62.16	$	62.77	$	62.86	$	51.78	$	11.08		21%
Natural gas (per MMBtu)		3.15		2.66		2.70		2.85		3.06		(0.21)		(7)%

Our 2018 anticipated non-acquisition capital expenditures for our E&P segment ranges between $500 million and $580 million.  Our 2018 anticipated non-acquisition capital expenditures for our Midstream segment ranges between $175 million and $220 million.  We are currently utilizing eight drilling rigs as of May 2018, which will result in drilling between 170 and 180 gross wells in the STACK.  Following the closing of the Business Combination, we have allocated our 2018 capital expenditures to develop the STACK for Alta Mesa and to expand capacity and well connects for Kingfisher.

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

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

Operations Update

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

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

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

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

Kingfisher’s midstream energy asset network includes approximately 400 miles of existing low and high pressure pipelines, a 60 MMcf/d cryogenic natural gas processing plant, 90 MMcf/d in offtake processing, compression facilities, 50,000 BBLs of crude storage, NGL storage and purchasing and marketing capabilities. In addition to the physical assets, Kingfisher Midstream also owns more than 200,000 Dth/d of firm transport residue pipeline capacity on nearby interstate pipelines.  On April 23, 2018, Kingfisher commissioned a 200 MMcf/d cryogenic plant adjacent to the 60 MMcf/d plant resulting in a total processing and offtake capacity of 350 MMcf/d.  Additionally, on May 10, 2018, Kingfisher Midstream announced a partnership to develop a long-haul crude pipeline project from the existing crude storage tank located at the Kingfisher Midstream plant site to Cushing, OK.  Kingfisher Midstream will have a 50% equity interest in the pipeline project which will have an initial capacity of 90,000 barrels per day, expandable to over 175,000 barrels per day.

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Results of Operations

Business Segments

Our discussion is presented on both a consolidated and segment basis.  Our two reportable segments are (1) Exploration & Production (“E&P”) and (2) Midstream, which separately offer different products and services.  We evaluate segment performance using operating income, which is defined as total operating and other revenue less total operating expenses.  Refer to Note 20 – Business Segment Information to our consolidated financial statements for further detail.

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

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

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Exploration & Production Segment Results

Revenues

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

The following tables summarizes our E&P revenues and production data for the periods presented:

	Successor		Predecessor		Predecessor
	February 9, 2018		January 1, 2018
	Through		Through		Three Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
Revenues (in thousands, except per unit data)
Oil sales	$	40,278	$	30,972	$	46,940
Natural gas sales		5,210		4,276		9,591
Natural gas liquids sales		4,714		4,000		7,072
Other revenues		555		888		1,234
Total E&P operating revenues and other	$	50,757	$	40,136	$	64,837
Net production:
Oil (MBbls)		651		494		942
Natural gas (MMcf)		2,248		1,609		3,117
NGL's (MBbls)		223		151		275
Total (MBoe)		1,249		914		1,737
Average net daily production volume:
Oil (MBbls/d)		12.8		12.7		10.5
Natural gas (MMcf/d)		44.1		41.2		34.6
NGL's (MBbls/d)		4.4		3.9		3.1
Total (MBoe/d)		24.5		23.4		19.3
Average sales prices:
Oil (per Bbl)	$	61.84	$	62.68	$	49.82
Effect of derivative settlements on average price (per Bbl)		(7.93)		(6.44)		(1.70)
Oil net of hedging (per Bbl)	$	53.91	$	56.24	$	48.12
Natural gas (per Mcf)	$	2.32	$	2.66	$	3.08
Effect of derivative settlements on average price (per Mcf)		0.25		0.94		(0.04)
Natural gas net of hedging (per Mcf)	$	2.57	$	3.60	$	3.04
Natural gas liquids (per Bbl)	$	21.18	$	26.41	$	25.70
Effect of derivative settlements on average price (per Bbl)		—		—		(0.85)
Natural gas liquids net of hedging (per Bbl)	$	21.18	$	26.41	$	24.85

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

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

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

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

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

	Successor		Predecessor
	February 9, 2018		January 1, 2018		Three
	Through		Through		Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
Gain (loss) on derivative contracts (in thousands):
Oil	$	(5,165)	$	(3,184)	$	(1,599)
Natural gas		555		1,523		(138)
Natural gas liquids		—		—		(233)
Total cash settlements		(4,610)		(1,661)		(1,970)
Valuation changes		(18,036)		8,959		32,212
Total gain (loss) on derivative contracts	$	(22,646)	$	7,298	$	30,242

Operating Expenses

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

	Successor		Predecessor		Predecessor
	February 9, 2018		January 1, 2018		Three	Three
	Through		Through		Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
Operating Expenses (in thousands, except per unit data):
Lease operating expense	$	8,317	$	4,485	$	11,010
Marketing and transportation expense		1,021		3,725		5,662
Production taxes		1,415		953		1,266
Production cost per BOE:
Lease operating expense	$	6.66	$	4.91	$	6.34
Marketing and transportation expense		0.82		4.08		3.26
Production taxes		1.13		1.04		0.73

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

Marketing and transportation expense for the Successor Period, the 2018 Predecessor Period, and 2017 Predecessor represents throughput for our properties in the STACK at the Kingfisher processing facility. Marketing and transportation expense in the Successor Period is lower due to intersegment elimination with our midstream segment. 

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

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

	Successor		Predecessor		Predecessor
	February 9, 2018		January 1, 2018
	Through		Through		Three Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
Geological and geophysical costs	$	451	$	2,440	$	1,858
Exploratory dry hole costs		—		(45)		—
Exploration expense		4,203		1,179		3,177
Loss on ARO settlement		301		59		12
Total exploration expense	$	4,955	$	3,633	$	5,047

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

	Successor		Predecessor		Predecessor
	February 9, 2018		January 1, 2018
	Through		Through		Three Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
(in thousands)
Depreciation, depletion and amortization	$	10,936	$	11,784	$	18,978
Depreciation, depletion and amortization per BOE		8.76		12.89		10.93

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

	Successor		Predecessor		Predecessor
	February 9, 2018		January 1, 2018
	Through		Through		Three Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
(in thousands)
Equity based compensation expense	$	2,768	$	—	$	—
General and administrative expenses		28,691		24,352		9,736
Total general and administrative expenses	$	31,459	$	24,352	$	9,736

Other Income (Expense)

Interest expense.  The following table presents information about interest expense (in thousands):

	Successor		Predecessor		Predecessor
	February 9, 2018		January 1, 2018		Three
	Through		Through		Months Ended
	March 31, 2018		February 8, 2018		March 31, 2017
Interest expense
Alta Mesa senior secured revolving credit facility	$	—	$	867	$	1,570
Senior unsecured notes		4,922		3,399		10,164
Other		274		1,245		308
Total interest expense	$	5,196	$	5,511	$	12,042

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Midstream Segment Results

Revenues

Our midstream revenues are primarily derived from natural gas gathering and processing, and crude oil gathering and transportation.

The following tables summarizes our midstream revenues for the periods presented (in thousands):

	Successor
	February 9, 2018
	Through
	March 31, 2018
Product sales	$	8,369
Gathering and processing revenue		3,411
Total Midstream operating revenues	$	11,780

Product sales were recognized from the sales of the processed residue, condensate and natural gas liquids. We process the natural gas on behalf of the producer and sell the resulting gas, condensate and NGL’s at a market price.  We remit to the producer an agreed upon price from the resulting sales, which shows up in product expense. The product sales are recognized when sold to the 3rd party purchaser. The Company acquired Kingfisher on February 9, 2018 pursuant to the Business Combination.

Gathering and processing revenues were driven by natural gas volumes gathered and processed under its commercial agreements and the fees assessed for such services.  The throughput of natural gas gathered and processed is derived from level of activity by dedicated upstream producers’ drilling and completing wells. 

Expenses

The following table summarizes midstream operating expense for the periods indicated (in thousands):

	Successor
	February 9, 2018
	Through
	March 31, 2018
Plant operating expense	$	587
Product expense		8,220
Gathering and processing expense		2,338
Depreciation, depletion and amortization		4,641
General and administrative expense		2,173
Interest expense		248

Plant operating expense represent expenses incurred to operate the gas processing facility, which primarily includes company labor and plant maintenance.  

Product expense represent payments to producers for their agreed upon percent of proceeds from the sale of the processed natural gas, condensate, and NGLs.

Gathering and processing expense for the Successor Period include compression, gathering, processing, & deficiency fees for offtakes along with NGL trucking fees & residue pipeline fees.

DD&A includes depreciation on the midstream facility and gathering system and amortization of related customer contracts, all recorded at fair value as part of the Business Combination.

General and administrative expense primarilyincludes insurance and labor-related costs.

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Liquidity and Capital Resources

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

Our 2018 anticipated non-acquisition capital expenditures for our E&P segment ranges between $500 million and $580 million.  Our 2018 anticipated non-acquisition capital expenditures for our Midstream segment ranges between $175 million and $220 million.  We are currently utilizing eight drilling rigs as of May 2018, which will result in drilling between 170 and 180 gross wells in the STACK.

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

We strive to maintain financial flexibility and may access 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 Alta Mesa Credit Facility and the Kingfisher 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 Alta Mesa Credit Facility and the Kingfisher Credit Facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned and future development 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. 

Alta Mesa Senior Secured Revolving Credit Facility

In connection with the consummation of the Business Combination, all indebtedness under the Alta Mesa senior secured revolving credit facility was repaid in full. On February 9, 2018, Alta Mesa entered into the Eighth Amended and Restated Senior Secured Revolving Credit Facility with Wells Fargo Bank, National Association, as the administrative agent (the “Alta Mesa Credit Facility”). The Alta Mesa Credit Facility is for an aggregate of $1.0 billion with an initial $350.0 million borrowing base.  In April 2018, the borrowing base was increased to $400 million until the next scheduled redetermination date in October 2018.  The Alta Mesa Credit Facility does not permit Alta Mesa to borrow funds if at the time of such borrowing if it is not in compliance with the financial covenants set forth in the Alta Mesa Credit Facility.

As of May 21, 2018, Alta Mesa has no outstanding borrowings under the Alta Mesa Credit Facility and has $21.9 million of outstanding letters of credit reimbursement obligations.

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

The Alta Mesa Credit Facility contains restrictive covenants that may limit Alta Mesa’s 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 its organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Alta Mesa Credit Facility permits Alta Mesa to make distributions to any parent entity (i) to pay for reimbursement of third party costs and expenses that are general and administrative expenses incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the Tax Receivable Agreement (as described below).  In addition, Alta Mesa can make restricted payments, so long as certain conditions are met, to any direct or indirect parent for the sole purpose of making a loan or capital contribution to Kingfisher in an amount up to $300 million until August 9, 2018.

The Alta Mesa Credit Facility also requires Alta Mesa to maintain the following two financial ratios:

· a current ratio, tested quarterly, commencing in the fiscal quarter ending June 30, 2018, of Alta Mesa’s consolidated current assets to its 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 Alta Mesa’s consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to its 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 times 4/4ths, of not greater than 4.0 to 1.0.

Alta Mesa is not subject to financial covenants ratios as of March 31, 2018.  Alta Mesa will be required to maintain financial ratios commencing on the fiscal quarter ending June 30, 2018.

Kingfisher Senior Secured Revolving Credit Facility

On August 8, 2017, Kingfisher entered into a $200 million revolving credit facility with a syndicate of lenders (the “Kingfisher Credit Facility”). The Kingfisher Credit Facility has a four-year term, with repayment due at maturity on August 8, 2021. ABN AMRO Capital USA LLC acts as agent, initial letter of credit issuer, bookrunner and lead arranger. The Kingfisher Credit Facility includes a letter of credit sublimit of $20 million for the issuance of letters of credit. Kingfisher has the option to increase its borrowing capacity under its revolving credit facility by an amount not to exceed $50 million (for a total commitment of $250 million subject to certain conditions). Kingfisher’s revolving credit facility is available to fund capital expenditures, working capital, general corporate purposes and to finance approved acquisitions.

The Kingfisher Credit Facility is secured by substantially all of Kingfisher’s real property interests, pledged equity and intangibles. The applicable margins are dependent upon the Kingfisher’s leverage ratio, with the highest margins for Eurodollar Loans and Base Rate loans being 3.25% and 2.25%, respectively. The Kingfisher Credit Facility is subject to commitment fees ranging from 0.50% to 0.375% based on the leverage grid. Additionally the Kingfisher Credit Facility is subject to customary affirmative and negative covenants and events of default relating to Kingfisher.

As of March 31, 2018, the outstanding balance of the Kingfisher Credit Facility was $52.0 million. 

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Senior Unsecured Notes

We have $500 million in aggregate principal amount of 7.875% senior unsecured notes, or the “senior notes”, due December 15, 2024 which were issued at par by Alta Mesa and its wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016.  Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, Alta Mesa may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, Alta Mesa 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 Alta Mesa 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, Alta Mesa 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 Alta Mesa’s material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of Alta Mesa existing and future senior indebtedness; senior in right of payment to all of Alta Mesa existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of Alta Mesa existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Alta Mesa Credit Facility; and structurally subordinated to all existing and future indebtedness and obligations of any of Alta Mesa 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) 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 Issuers experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase. The closing of the Business Combination did not constitute a change of control under the indenture governing the senior notes because certain existing owners of Alta Mesa and SRII Opco entered into an amended and restated voting agreement with respect to the voting interests in Alta Mesa GP. 

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 of 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 $20.0 million.

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

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

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Tax Receivable Agreement.  In connection with the completion of the Business Combination, we entered into the Tax Receivable Agreement with SRII Opco, the AM Contributor, and the Riverstone Contributor. This agreement generally provides for the payment by us of 85% of the amount of net cash savings, if any, in U.S. federal, state and local income tax that we actually realize (or are deemed to realize in certain circumstances) in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for AMR Class A Common Stock (or, in certain circumstances, cash) pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by Kingfisher or otherwise used in Kingfisher’s midstream business, and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings.

The payment obligations under the Tax Receivable Agreement are obligations of the Company and not obligations of SRII Opco, and we expect that the payments we will be required to make under the Tax Receivable Agreement may be substantial. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been entitled to any of the tax benefits subject to the Tax Receivable Agreement. In other words, we would calculate our federal, state and local income liabilities as if no tax attributes arising from a redemption or direct exchange of SRII Opco Common Units had been transferred to us. The term of the Tax Receivable Agreement will continue until all such tax benefits have been utilized or have expired, unless we exercise our right to terminate the Tax Receivable Agreement or the Tax Receivable Agreement is otherwise terminated.

As of March 31, 2018, no exchange of SRII Common Units has occurred and there has not been an early termination under the Tax Receivable Agreement; therefore, we have not recorded a Tax Receivable Agreement liability at this time.

The AM Contributor, the Riverstone Contributor, and their permitted transferees (together, the “TRA Holders”) will not reimburse us for any cash payments previously made under the Tax Receivable Agreement if any tax benefits initially claimed by us are challenged by the IRS or other relevant tax authority and are ultimately disallowed, except that excess payments made to TRA Holders will be netted against payments otherwise to be made, if any, to the TRA Holders after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

Additionally, if the Tax Receivable Agreement terminates early (at our election or as a result of our material breach of our obligations under the Tax Receivable Agreement, whether as a result of our failure to make any payment when due, failure to honor any other material obligation under it or by operation of law as a result of the rejection of the Tax Receivable Agreement in a case commenced under the United States Bankruptcy Code or otherwise), we would be required to make a substantial, immediate lump-sum payment. This payment would equal the present value of hypothetical future payments that could be required to be paid under the Tax Receivable Agreement (calculated using a discount rate of 18%). The calculation of the hypothetical future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including that (i) we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement, (ii) all taxable income of the Company is subject to the maximum applicable tax rates throughout the relevant period and (iii) certain loss or credit carryovers will be utilized through the expiration date of such carryovers.

Payments will generally be due under the Tax Receivable Agreement within 30 days following the finalization of the schedule with respect to which the payment obligation is calculated, although interest on such payments will begin to accrue from the due date (without extensions) of such tax return until such payment due date at a rate equal to LIBOR, plus 100 basis points. Except in cases where we elect to terminate the Tax Receivable Agreement early or we have available cash but fail to make payments when due, generally we may elect to defer payments due under the Tax Receivable Agreement if we do not have available cash to satisfy our payment obligations under the Tax Receivable Agreement or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the Tax Receivable Agreement generally will accrue interest at a rate of LIBOR plus 500 basis points; provided, however, that interest will accrue at a rate of LIBOR plus 100 basis points if we are unable to make such payment as a result of limitations imposed by existing credit agreements.

Because we are a holding company with no operations of our own, our ability to make payments under the Tax Receivable Agreement is dependent on the ability of SRII Opco to make distributions to us in an amount sufficient to cover our obligations under the Tax Receivable Agreement; this ability, in turn, may depend on the ability of SRII Opco’s subsidiaries to make distributions to it. The ability of SRII Opco and its subsidiaries to make such distributions will be subject to, among other things, the applicable provisions of Delaware law that may limit the amount of funds available for distribution and restrictions in relevant debt instruments issued by SRII Opco and/or its subsidiaries. To the extent that we are unable to make payments under the Tax Receivable Agreement for any reason, such payments will be deferred and will accrue interest until paid.

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Cash flow provided by (used in) operating activities

Cash provided by (used in) operating activities was ($86.6) million, $26.5 million and ($3.9) million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Cash-based items of net income (loss) including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense were approximately $3.0 million, ($2.4) million $23.7 million for the Successor Period, 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Working capital and other assets and liabilities resulted in a decrease of $89.6 million, and $27.6 million for the Successor Period and the 2017 Predecessor Period respectively.  The 2018 Predecessor Period working capital and other assets and liabilities had an increase of approximately $28.9 million.

Cash flow provided by (used in) investing activities

Investing activities provided cash of approximately $112.9 million in the Successor Period.   Proceeds withdrawn from the Trust account provided cash of approximately $1.0 billion offset by net cash used of approximately $796.8 million attributable to the Business Combination and approximately $133.1 million for capital expenditures for property, plant and equipment.  Investing activities used cash for capital expenditures for property and equipment of approximately $38.1 million and $60.6 million for the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.

Cash flow provided by financing activities

Cash provided by financing activities was $235.7 million in the Successor Period.  Proceeds provided by the issuance of Class A common stock related to the forward purchase contract of approximately $400.0 million was offset by net cash used of approximately $172.3 million for payments of deferred underwriting compensation, sponsor note and senior secured revolving credit facility.  Cash provided by financing activities was $16.9 million and $62.9 million for the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. The 2018 Predecessor Period included proceeds from long-term debt totaling $60.0 million, offset by repayments of long-term debt totaling $43.0 million. The 2017 Predecessor period included proceeds from long-term debt totaling $55.1 million and capital contributions totaling $7.9 million.

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Cautionary Statement Regarding Forward-Looking Statements

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

Forward-looking statements may include statements about:

· 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;

· operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, natural gas liquids, crude oil and midstream products;

· 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.

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

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

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

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

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

For information regarding our exposure to certain market risks, see “Item 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 7 and 8 to our consolidated financial statements for a description of our outstanding derivative contracts at the most recent reporting date.

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

We are subject to interest rate risk on our variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts.  A 1% increase in interest rates would increase interest expense on Kingfisher’s credit facility by $0.5 million, based on the balance outstanding at March 31, 2018. As of March 31, 2018, Alta Mesa has no outstanding balance under their senior secured credit facility.   

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

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Changes in Internal Control Over Financial Reporting

Other than changes related to the succession (i.e., the acquisition of Alta Mesa) and the acquisition of Kingfisher, there has been no change in our internal control over financial reporting during the three months ended March 31, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting

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PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM 1A. Risk Factors

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

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ITEM 6. Exhibits

2.1	Second Amended and Restated Certificate of Incorporation of Alta Mesa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Alta Mesa Resources’ Current Report on Form 8-K filed with the SEC on February 9, 2018).
2.2	Certificate of Designations of Series A Preferred Stock (incorporated by reference to Exhibit 3.2 to Alta Mesa Resources’ Current Report on Form 8-K filed with the SEC on February 9, 2018).
2.3	Certificate of Designation of Series B Preferred Stock (incorporated by reference to Exhibit 3.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
2.4	Bylaws (incorporated by reference to the Registrant’s Registration Statement on Form S-1 filed with the SEC on (Registration No. 333-216409) filed with the SEC on March 2, 2017).
2.5	Amended and Restated Agreement of Limited Partnership of SRII Opco, LP, dated February 9, 2018 (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
4.1	Registration Rights Agreement, dated as of February 9, 2018, by and among Alta Mesa Resources, Inc., High Mesa Holdings, L.P., KFM Holdco, LLC and Riverstone VI Alta Mesa Holdings, L.P. (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
4.2	Amendment No. 1 to Registration Rights Agreement, dated as of February 9, 2018, by and among Alta Mesa Resources, Inc., Silver Run Sponsor II, L.L.C., and the other holders party thereto. (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.1	Eighth Amended and Restated Credit Agreement, dated as of February 9, 2018, among Alta Mesa Holdings, LP, Alta Mesa Resources, Inc., the lenders party hereto from time to time, and Wells Fargo Bank, National Association, as administrative agent for such Lenders (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.2	First Amendment to Credit Agreement and Limited Consent, dated as of February 9, 2018, by and among Kingfisher Midstream, LLC, each of the lenders from time to time party thereto and ABN AMRO Capital USA LLC, as administrative agent and LC Issuer (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.3	Tax Receivable Agreement, dated as of February 9, 2018, by and among Alta Mesa Resources, Inc., SRII Opco, LP, Riverstone VI Alta Mesa, L.P., and High Mesa Holdings LP (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.4	Restrictive Covenant Agreement, dated February 9, 2018, by and between Alta Mesa Resources, Inc. and Asset Risk Management, LLC (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.5	Form of Indemnity Agreement with Directors (incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.6	Form of Indemnity Agreement Amendment (incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.7	Management Services Agreement, dated February 9, 2018, by and between Alta Mesa Holdings, LP and High Mesa, Inc. (incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.8	Amended and Restated Voting Agreement, by and among Alta Mesa Holdings GP, LLC, BCE-AMH Holdings, LLC, BCE-MESA Holdings, LLC, Mezzanine Partiers II Delaware Subsidiary, LLC, Offshore Mezzanine Partners Master Fund II, L.P., Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., The Northwestern Mutual Life Insurance Company, The Northwestern Mutual Life Insurance Company For its Group Annuity Separate Account, Northwestern Mutual Capital Strategic Equity Fund III, L.P., Michael E. Ellis, Harlan H. Chappelle and SRII Opco, LP, dated as of February 9, 2018 (incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.9	Operating Transition Services Agreement, dated February 9, 2018, by and between Kingfisher Midstream, LLC, and Asset Risk Management, LLC (incorporated by reference to Exhibit 10.11 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.10	Letter Agreement, dated as of February 9, 2018, by and between Alta Mesa Resources, Inc. and James T. Hackett (incorporated by reference to Exhibit 10.12 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.11	Employment Agreement, dated as of February 9, 2018, by and between Alta Mesa Services, LP and Harlan H. Chappelle (incorporated by reference to Exhibit 10.13 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.12	Employment Agreement, dated as of February 9, 2018, by and between Alta Mesa Services, LP and Michael E. Ellis (incorporated by reference to Exhibit 10.14 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).

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10.13	Employment Agreement, dated as of February 9, 2018, by and between Alta Mesa Services, LP and Michael A. McCabe (incorporated by reference to Exhibit 10.15 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.14	Employment Agreement, dated as of February 9, 2018, by and between Alta Mesa Services, LP and Homer “Gene” Cole (incorporated by reference to Exhibit 10.16 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.15	Employment Agreement, dated as of February 9, 2018, by and between Alta Mesa Services, LP and David Murrell (incorporated by reference to Exhibit 10.17 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.16	Employment Agreement, dated as of February 9, 2018, by and between Alta Mesa Services, LP and Ronald J. Smith (incorporated by reference to Exhibit 10.18 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.17	Alta Mesa Resources Inc. 2018 Long Term Incentive Plan (incorporated by reference to Exhibit 10.19 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
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 RESOURCES, INC.
	(Registrant)
May 21, 2018
	By:	/s/ Harlan H. Chappelle
		Harlan H. Chappelle
		Chief Executive Officer
May 21, 2018
	By:	/s/ Michael A. McCabe
		Michael A. McCabe
		Chief Financial Officer

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