Alta Mesa Resources (AMRWW) 10-Q 2018 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_______________________________________

FORM 10-Q

_______________________________________

(Mark One)

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

For the quarterly period ended: June 30, 2018

OR

o   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  x    No  o

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.)    YesxNo  o

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YesoNo x

As of July 31, 2018, there were 179,058,693 shares of Class A Common Stock and 204,921,888 shares of Class C Common Stock, par value $0.0001 per share outstanding. The shares of Class A Common Stock shown as outstanding do not include 1,671,513 nonvested restricted stock awards outstanding as of July 31, 2018.

1

Table ofContents

໿

	Page Number
Glossary	3
Cautionary Statement Regarding Forward-Looking Statements	4
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Consolidated Balance Sheets	6
Consolidated Statements of Operations	8
Consolidated Statements of Cash Flows	9
Consolidated Statements of Stockholders’ Equity	10
Consolidated Statements of Changes in Partners’ Capital	11
Notes to Consolidated Financial Statements	12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
Item 3. Quantitative and Qualitative Disclosures about Market Risk	66
Item 4. Controls and Procedures	67
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	67
Item 1A. Risk Factors	67
Item 6. Exhibits	68
Signatures	69

2

Glossary of Terms

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

bbl -	Barrels
bbl/d -	Barrels per day
BOE -	Barrels of oil equivalent
Btu -	British thermal units
Completion -	The installation of permanent equipment for the production of oil and gas
Dth -	A dekatherm is a unit of energy used primarily to measure natural gas and is equal to 1 million British thermal units
Dth/d -	Dekatherms per day
EBITDA -	Earnings before interest, taxes, depreciation, depletion, amortization
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses
Mbbls -	One thousand barrels
Mbbls/d -	One thousand barrels per day
MBoe/d -	One thousand barrels of oil equivalent per day
Mcf -	One thousand cubic feet
Mcf/d -	One thousand cubic feet per day
MMBtu -	One million British thermal units
MMcf -	One million cubic feet
MMcf/d -	One million cubic feet per day
NYMEX -	New York Mercantile Exchange
NGLs -	Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline
Wellbore -	A hole that is drilled to aid in the exploration and recovery of natural resources including oil or natural gas
Working interest -	An interest in a mineral property that entitles the owner of that interest to all of the share of the mineral production from the property, usually subject to a royalty
VWAP -	Volume weighted average price

3

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.

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

4

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

5

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
	June 30, 2018		December 31, 2017
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	82,398	$	3,660
Restricted cash	1,022		1,269
Accounts receivable, net	115,222		76,161
Other receivables	226		1,388
Receivables due from related party	12,643		790
Note receivable due from related party	1,609		—
Prepaid expenses and other current assets	4,174		2,932
Current assets — discontinued operations	—		5,195
Derivative financial instruments	—		216
Total current assets	217,294		91,611
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	2,550,519		894,630
Other property, plant and equipment, net	343,357		32,140
Total property, plant and equipment, net	2,893,876		926,770
OTHER ASSETS
Equity method investment	6,956		—
Deferred financing costs, net	3,518		1,787
Notes receivable due from related party	11,262		12,369
Goodwill	699,898		—
Intangible assets, net	408,706		—
Deposits and other long-term assets	50		9,067
Non-current assets — discontinued operations	—		43,785
Deferred tax asset	11,954		—
Derivative financial instruments	—		8
Total other assets	1,142,344		67,016
TOTAL ASSETS	$	4,253,514	$	1,085,397

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

6

	Successor			Predecessor
	June 30, 2018			December 31, 2017
LIABILITIES, PARTNERS' CAPITAL AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	148,866		$	170,489
Accounts payable — affiliate	—			5,476
Advances from non-operators	6,283			5,502
Advances from related party	37,135			23,390
Asset retirement obligations	538			69
Current liabilities — discontinued operations	—			15,419
Derivative financial instruments	37,743			19,303
Total current liabilities	230,565			239,648
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	6,439			10,400
Long-term debt, net	595,084			607,440
Noncurrent liabilities — discontinued operations	—			66,862
Derivative financial instruments	6,385			1,114
Deferred tax liability	4,893			—
Other long-term liabilities	6			5,488
Total long-term liabilities	612,807			691,304
TOTAL LIABILITIES	843,372			930,952
PREFERRED STOCK, $0.0001 par value
Class A: 1,000,000 shares authorized; 3 shares issued and outstanding	—			—
Class B: 1,000,000 shares authorized; 1 share issued and outstanding	—			—
Commitments and Contingencies (Note 14)
PARTNERS' CAPITAL	—			154,445
STOCKHOLDERS' EQUITY
Common stock, $0.0001 par value
Class A: 1,200,000,000 shares authorized; 179,058,693 shares issued and outstanding	18			—
Class C: 280,000,000 shares authorized; 204,921,888 shares issued and outstanding	20			—
Additional paid in capital	1,498,023			—
Accumulated deficit	(27,793		)	—
Total stockholders' equity/partners' capital	1,470,268			154,445
Noncontrolling interest	1,939,874			—
Total equity	3,410,142			154,445
TOTAL LIABILITIES, PARTNERS' CAPITAL AND STOCKHOLDERS' EQUITY	$	4,253,514		$	1,085,397

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

7

ALTA MESA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(in thousands, except share and per share data)

	Successor			Predecessor			Successor			Predecessor
	Three			Three			February 9, 2018			January 1, 2018			Six
	Months Ended			Months Ended			Through			Through			Months Ended
	June 30, 2018			June 30, 2017			June 30, 2018			February 8, 2018			June 30, 2017
OPERATING REVENUES AND OTHER
Oil	$	75,291		$	42,348		$	115,569		$	30,972		$	89,288
Natural gas	7,980			10,642			13,190			4,276			20,233
Natural gas liquids	10,241			6,581			14,955			4,000			13,653
Product sales	19,605			—			27,974			—			—
Gathering and processing revenue	7,073			—			10,484			—			—
Other revenues	2,229			1,979			2,784			888			3,213
Total operating revenues	122,419			61,550			184,956			40,136			126,387
Gain (loss) on sale of assets and other	(63		)	—			5,916			—			—
Gain (loss) on derivative contracts	(29,219		)	18,250			(51,865		)	7,298			48,492
Total operating revenues and other	93,137			79,800			139,007			47,434			174,879
OPERATING EXPENSES
Lease operating expense	12,679			11,480			20,996			4,485			22,490
Marketing and transportation expense	2,173			6,510			3,194			3,725			12,172
Plant operating expense	3,313			—			3,900			—			—
Product expense	19,383			—			27,603			—			—
Gathering and processing expense	3,240			—			5,578			—			—
Production taxes	2,606			1,184			4,021			953			2,450
Workover expense	333			1,102			1,578			423			1,690
Exploration expense	8,083			3,192			13,038			3,633			8,239
Depreciation, depletion, and amortization expense	33,773			20,110			49,350			11,784			39,088
Impairment expense	—			—			—			—			1,188
Accretion expense	161			30			263			39			126
General and administrative expense	22,456			8,293			57,013			24,352			18,029
Total operating expenses	108,200			51,901			186,534			49,394			105,472
INCOME (LOSS) FROM OPERATIONS	(15,063		)	27,899			(47,527		)	(1,960		)	69,407
OTHER INCOME (EXPENSE)
Interest expense	(11,779		)	(12,578		)	(17,223		)	(5,511		)	(24,620		)
Interest income and other	824			299			1,370			172			548
Total other income (expense), net	(10,955		)	(12,279		)	(15,853		)	(5,339		)	(24,072		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(26,018		)	15,620			(63,380		)	(7,299		)	45,335
Income tax provision (benefit)	(3,678		)	—			(7,491		)	—			285
INCOME (LOSS) FROM CONTINUING OPERATIONS	(22,340		)	15,620			(55,889		)	(7,299		)	45,050
Loss from discontinued operations, net of tax	—			(30,934		)	—			(7,593		)	(35,449		)
NET INCOME (LOSS)	(22,340		)	(15,314		)	(55,889		)	(14,892		)	9,601
Net loss attributable to non-controlling interest	(15,896		)	—			(36,210		)	—			—
NET INCOME (LOSS) ATTRIBUTABLE TO ALTA MESA RESOURCES, INC. STOCKHOLDERS	$	(6,444	)	$	(15,314	)	$	(19,679	)	$	(14,892	)	$	9,601
NET INCOME (LOSS) PER COMMON SHARE ATTRIBUTABLE TO ALTA MESA RESOURCES INC. STOCKHOLDERS:
Basic	$	(0.04	)				$	(0.11	)
Diluted	$	(0.04	)				$	(0.12	)

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

8

ALTA MESA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)

	Successor			Predecessor
	February 9, 2018			January 1, 2018			Six
	Through			Through			Months Ended
	June 30, 2018			February 8, 2018			June 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(55,889	)	$	(14,892	)	$	9,601
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion, and amortization expense	49,350			12,414			51,298
Impairment expense	—			5,560			29,124
Accretion expense	263			140			1,052
Amortization of deferred financing costs	152			171			1,456
Amortization of debt premium	(2,051		)	—			—
Equity-based compensation expense	7,729			—			—
Dry hole expense	—			(45		)	888
Expired leases	10,658			1,250			5,922
(Gain) loss on derivative contracts	51,865			(7,298		)	(48,492		)
Settlements of derivative contracts	(18,969		)	(1,661		)	254
Premium paid on derivative contracts	—			—			(520		)
Interest converted into debt	—			103			599
Interest on notes receivable due from related party	(417		)	(85		)	(406		)
Deferred tax provision (benefit)	(7,491		)	—			—
Loss on sale of assets and other	63			1,923			—
Gain on acquisition of oil and gas properties	—			—			(1,626		)
Changes in assets and liabilities:
Accounts receivable	(8,585		)	(20,895		)	(11,478		)
Other receivables	996			(9,887		)	4,281
Receivables due from related party	(6,818		)	(117		)	(680		)
Prepaid expenses and other non-current assets	8,114			9,970			(11,644		)
Advances from related party	(10,371		)	24,116			(42,528		)
Settlement of asset retirement obligation	(806		)	(63		)	(977		)
Accounts payable, accrued liabilities, and other liabilities	(93,903		)	25,815			7,655
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES	(76,110		)	26,519			(6,221		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment	(340,631		)	(38,096		)	(151,832		)
Acquisitions, net of cash acquired	(791,819		)	—			(6,251		)
Proceeds withdrawn from Trust Account	1,042,742			—			—
Investment in equity affiliate and other, net	4,343			—			—
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(85,365		)	(38,096		)	(158,083		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	80,000			60,000			165,065
Repayments of long-term debt	(193,565		)	(43,000		)	(10,000		)
Additions to deferred financing costs	(3,670		)	—			(170		)
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	244,507			16,932			162,770
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	83,032			5,355			(1,534		)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period	388			4,990			7,618
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, end of period	$	83,420		$	10,345		$	6,084

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

9

ALTA MESA RESOURCES, INC.

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

(in thousands)

	Common Stock																				Total
	Class A				Class B					Class C					Paid-In			Accumulated			Stockholders'			Noncontrolling			Total
	Shares		Amount		Shares		Amount			Shares		Amount			Capital			Deficit			Equity			Interests			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
Additional Class C common shares issued in connection with the settlement of the purchase consideration in the business combination	—		—		—		—			1,109		—			—			—			—			—			—
Noncontrolling interest in SRII Opco assumed in the business combination	—		—		—		—			—		—			—			—			—			8,758			8,758
Redemption of noncontrolling interests and Class C common shares for Class A common shares	9,589		1		—		—			(9,589	)	(1		)	90,872			—			90,872			(91,309		)	(437		)
Restricted stock awards vested	98		—		—		—			—		—			—			—			—			—			—
Equity based compensation	—		—		—		—			—		—			7,729						7,729			—			7,729
Net loss	—		—		—		—			—		—			—			(19,679		)	(19,679		)	(36,210		)	(55,889		)
Balance at June 30, 2018	179,059		$	18	—		$	—		204,922		$	20		$	1,498,023		$	(27,793	)	$	1,470,268		$	1,939,874		$	3,410,142

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

10

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.

11

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”) is an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County ("STACK"). We also operate a midstream services business through Kingfisher Midstream LLC ("Kingfisher"), a Delaware limited liability company. Kingfisher has natural gas gathering and processing and crude gathering assets located in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The Kingfisher assets are integral to our oil and natural gas operations and strategically positioned to provide similar services to other producers in the area.

We were 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 $22.7 million. 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 a 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 (i) 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, (ii) the Contribution Agreement (the “KFM Contribution Agreement”), dated August 16, 2017, with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, and, solely for certain provisions therein, the equity owners of the KFM Contributor; and (iii) the Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”), dated August 16, 2017, 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 46.6% 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, Alta Mesa distributed its non-STACK assets to the AM contributor and 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. 

12

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 the consolidation of Alta Mesa and Kingfisher concurrent with the Business Combination on February 9, 2018. The Business Combination was accounted for 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 as of the acquisition date. See Note 4 — Business Combination (Successor) for further information related to the Business Combination.  As a result of the Business Combination and the transactions contemplated by the Contribution Agreements, 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 for the three months ended June 30, 2018 and from February 9, 2018 to June 30, 2018 (“Successor Period”), (collectively, “Successor Periods”); and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”), the three months ended June 30, 2017 and the six months ended June 30, 2017 (“2017 Predecessor Period”), (collectively, the “Predecessor Periods”).

Prior to the Business Combination, Alta Mesa distributed its non-STACK assets to the AM Contributor.  The distribution of its 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, we have classified the assets and liabilities and operating results of the non-STACK assets as discontinued operations during the Predecessor Periods 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 16 — Stockholders' Equity and Partners' Capital for further discussion.

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.

Segment Reporting (Successor). The Company operates in two business segments. Alta Mesa operates in one industry segment, which is the exploration and production of oil and natural gas. Kingfisher operates in the midstream segment as the owner and operator of gas gathering and processing assets. Both operations are conducted in one geographic area of the United States and all revenues are derived from customers located in the United States.  The Company reports its consolidated financial results under two reportable segments: (1) Exploration & Production and (2) Midstream.  See Note 21 — Business Segment Information for financial information about our segments.

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. Other estimates are utilized to determine amounts related to oil and natural gas revenues, product sales and gathering and processing 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

13

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 we use and have experienced no losses to date associated with these accounts. 

Restricted Cash.The Company classifies cash balances as restricted cash when cash is legally, contractually or otherwise restricted as to withdrawal or usage. As of June 30, 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
	June 30, 2018		December 31, 2017
Cash and cash equivalents	$	82,398	$	3,660
Restricted cash	1,022		1,269
Cash of discontinued operations	—		61
Total cash, cash equivalents and restricted cash	$	83,420	$	4,990

Accounts Receivable. Our receivables arise primarily from (i) the sale of oil, natural gas and NGLs, (ii) joint interest owners' properties in which we serve as the operator, and (iii) for services rendered to non-affiliated customers. Our customers are concentrated in the oil and gas industry which 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 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 are stated at amounts due, net of an allowance for doubtful accounts. 

Accounts receivable consisted of the following (in thousands):

	Successor			Predecessor
	June 30, 2018			December 31, 2017
Oil, natural gas and natural gas liquids sales	$	40,680		$	26,916
Joint interest billings	34,762			13,821
Pooling interest (1)	39,843			35,839
Allowance for doubtful accounts	(63		)	(415		)
Total accounts receivable, net	$	115,222		$	76,161

_________________

(1) Pooling interest relates to Oklahoma’s forced pooling process which requires the Company to offer mineral interest owners the option to participate in the drilling of proposed wells.  The pooling interest listed above represents costs associated with 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 establish 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. Our assessment is based upon several factors including, but not limited to, historical experience, the length of time an invoice has been outstanding, responses from customers relating to demands for payment and the current and projected financial condition of specific customers.

14

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 the Business Combination, our property, plant and equipment was measured at fair value as of the acquisition date, which also impacted how values were assigned between the categories within property, plant, and equipment.  See Note 4 — Business Combination (Successor) for further discussion.

Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These costs consist of amounts incurred to obtain a mineral interest or right in a property, such as a lease, in addition to options to lease, and for 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 the related costs are transferred to proved oil and natural gas properties.

Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, delay rentals, gains or losses on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, 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 expensed. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly. 

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

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in Account Standards Codification (“ASC”) 360-10-35, Property, Plant and Equipment, Subsequent Measurement, or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair 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 in the Successor Periods, the 2018 Predecessor Period and the three months ended June 30, 2017 (Predecessor).  For the 2017 Predecessor Period, our evaluation of the Company’s proved properties resulted in an impairment charge 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 of unproved properties was recognized in the Successor Periods, or the Predecessor Periods.

Management evaluates whether the carrying value of all other long-lived assets, including our midstream assets, have 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 both qualitative and quantitative when determining if these assets should be evaluated for impairment.

If the carrying value is not recoverable on an undiscounted basis, an 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, an internally developed discounted cash flow analysis or an 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 related to other long-lived assets for the Successor Periods or the Predecessor Periods.

15

Other Property, Plant and Equipment — Other property, plant and equipment, such as plant equipment, a salt water disposal system, office furniture and equipment, buildings, and 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 rights of way, a 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 based on a 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. 

For the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), DD&A expense related to oil and natural gas properties was $26.1 million and $18.3 million, respectively. DD&A expense related to oil and natural gas properties was $36.9 million, $11.2 million, and $36.6 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. DD&A expense related to our midstream tangible assets was $2.0 million and $3.1 million for the three months ended June 30, 2018 (Successor) and the Successor Period, respectively.  There was no such DD&A expense for midstream assets for the 2018 and 2017 Predecessor Periods.

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 years to seven years.  Our midstream assets are depreciated using the straight-line method over their expected useful lives. The Company uses estimated lives of 35 years for its processing plant and pipelines.

For the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), depreciation expense for other property, plant and equipment was $0.4 million and $1.8 million, respectively. Depreciation expense for non-oil and natural gas properties was $0.6 million, $0.6 million, and $2.4 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. 

Deferred financing costs. Deferred financing costs reflect fees paid to lenders and third parties that are directly related to the establishment of revolving credit facility agreements or the issuance of senior secured notes. Costs related to the establishment of the current Alta Mesa and Kingfisher secured revolving credit facilities have been deferred in other noncurrent assets and are being amortized over the term of each facility as additional interest expense. During the Predecessor Periods, costs associated with the issuance of senior secured notes were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense.

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. 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.  Our reporting units for goodwill impairment evaluation purposes are the Exploration and Production and Midstream business segments. Our evaluation of goodwill for impairment, will be performed annually as of October 1 of each year. During the first quarter of 2018, the Company elected to early adopt Accounting Standards Update ("ASU") No. 2017-04, Intangibles - Goodwill and Other, Simplifying the Test for Goodwill Impairment. This newguidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Any future identified impairment of goodwill will be recognized as the amount by which a reporting unit's carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. During each annual evaluation, we will first assess qualitative factors to determine whether the existence of events or circumstances has led to a determination that it is 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 a quantitative goodwill impairment test.

As a result of the Business Combination, we recognized goodwill during the Successor Period. There was no goodwill prior to the Business Combination. All of the Company’s goodwill relates to the midstream segment and we did not identify any impairment of that goodwill as of June 30, 2018.

16

Intangible Assets (Successor). In connection with the acquisition of Kingfisher, the Company recorded the estimated fair value of acquired customer contracts and related customer 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, all of which relate to the midstream segment, 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.  If required, an impairment would be recognized in the consolidated statements of operations to reduce the carrying amount of an intangible asset to its fair value.  No impairment was identified as of June 30, 2018.

Equity Method of Accounting. We account for investments that we do not control, but have the ability to exercise significant influence using the equity method of accounting. Under this method, our equity investments are originally recorded at our acquisition cost, which approximates fair value, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. Our income from equity investments also includes amortization expense associated with the difference in basis between the initial carrying value of our equity investments in our consolidated balance sheets and our proportionate share of the underlying net assets of our investee.

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 as a reduction to interest expense. 

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. As such, no obligation has been established as of June 30, 2018.

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).

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 statements 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 temporary differences between the bases of assets and liabilities for financial reporting and income tax purposes. We classify deferred tax assets and liabilities as noncurrent in our consolidated balance sheet as of June 30, 2018.

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.

17

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

We have considered our exposure under the standard at both the federal and state tax levels.  We did not record any liabilities for uncertain tax positions as of June 30, 2018 or 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 Successor 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 historically elected to be treated as an individual partnership for tax purposes

under the provisions of the Internal Revenue Code of 1986, as amended. 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 some tax basis differences are determined at the partner level and Alta Mesa did 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.

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 natural gas liquids 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.

Equity-Based Compensation (Successor). The Company recognizes compensation related to all stock-based awards in the financial statements based on their estimated grant-date fair value. The Company grants various types of stock-based awards including stock options, restricted stock, and performance-based restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and restricted stock awards are valued using the market price of the Company’s common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See Note 17 — Equity Based Compensation (Successor) for additional information regarding the Company’s equity-based compensation.

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 of long-term debt under the Alta Mesa and Kingfisher senior secured revolving credit facilities is not considered to be materially different from carrying value due to variable 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 12—  Long-Term Debt, Net.  

Acquisitions. Business combinations are accounted for using the acquisition method of accounting. Accordingly, the results of operations of the acquired businesses (Alta Mesa and Kingfisher) are included in our consolidated statements of operations

18

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. The total cost of each acquisition is allocated to tangible and intangible assets acquired and liabilities assumed based on their estimated fair values at the time of the acquisition.

Earnings (Loss) Per Share. Basic earnings (loss) per share is calculated by dividing earnings (loss) available to common stockholders by the weighted average number of shares outstanding 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, restricted stock units and stock options.

The following table reflects the net income attributable to common stockholders and earnings per share for the periods indicated based on a weighted average number of common shares outstanding for the period:

໿

	Successor
	Three Months Ended June 30, 2018			February 9, 2018 Through June 30, 2018
	(in thousands, except shares and per share data)
Net loss attributable to AMR Class A common stockholders	$	(6,444	)	$	(19,679	)
Effect of dilutive Class C securities:
Net loss attributable to noncontrolling interests assumed to be redeemed for Class A Common Stock, net of tax	(2,157		)	(4,914		)
Net loss attributable to AMR Class A common stockholders after assumed redemption	$	(8,601	)	$	(24,593	)
Weighted average Class A common shares outstanding (Basic)	173,345,982			171,908,486
Effect of dilutive securities:
Class A shares assumed issued to holders of noncontrolling interests upon redemption	34,619,947			36,204,221
Weighted average common shares outstanding (Diluted)	207,965,929			208,112,707
Loss per common share attributable to AMR common stockholders:
Basic	$	(0.04	)	$	(0.11	)
Diluted	$	(0.04	)	$	(0.12	)

For the three months ended June 30, 2018 (Successor), approximately 63.0 million of warrants and 5.9 million of stock awards, consisting 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. During the Successor Period, approximately 63.0 million of warrants and 5.7 million of stock awards, consisting 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. Additionally, 174.4 million shares of Class C Common Stock were excluded from the calculation of diluted earnings per share during the Successor Periods due to restrictions on noncontrolling interest holders of those shares at June 30, 2018 to exercise their right to cause SRII Opco to redeem a portion of their Common Units, along with an equal number of Class C shares held by noncontrolling interest holders, for the Company's Class A Common Stock.

Comprehensive Income. During the Successor Periods and the Predecessor Periods, the Company had no components of other comprehensive income. Accordingly, total comprehensive income for each period was equal to the amount of net income (loss) for those same periods as reflected in the accompanying consolidated statements of operations.

Going Concern. The Company's management is required to evaluate an entity’s ability to continue as a going concern for a period of one year following the date of the issuance of the Company’s consolidated financial statements. Footnote disclosure is required if substantial doubt exists about an entity’s ability to continue as a going concern during the evaluation period, including management’s plans to alleviate the conditions and events that raise substantial doubt of going concern, if applicable.

At the date of the issuance of these consolidated financial statements, management considers the Company to be a going concern and has prepared these consolidated financial statements on a going concern basis.

19

Recent Accounting Pronouncements Issued But Not Yet Adopted

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. Subsequent to the issuance of ASU 2014-09, the FASB amended the standard to provide clarification and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. The core principle of the new amended standard is that a company will recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration to which the company is entitled in exchange for those services. In order to comply with the new standard, companies will need to (i) identify performance obligations in each contract, (ii) estimate the amount of variable consideration to include in the transaction price and (iii) allocate the transaction price to each separate performance obligation.

ASU 2014-09, as amended, is effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act.

We are currently an emerging growth company and have elected to use the extended transition period. However, we expect to lose our emerging growth company status, effective December 31, 2018. Accordingly, we will be required to adopt ASU 2014-09 on December 31, 2018, with retroactive implementation as of January 1, 2018. ASU 2014-09 allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. We expect to adopt ASU 2014-09 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.  

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

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

At this time, we are evaluating the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and implementation of ASU 2016-02 is expected to have an impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months.  The adoption is also expected to result in a change in the amount of lease expense recorded on our consolidated statement of operations, and additional disclosures.  As part of our assessment to date, we have formed an implementation work team and will complete our evaluation in 2018.  As we continue to evaluate and implement the standard, we will provide additional information about the expected financial impact at a future date.  

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

20

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

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

NOTE 3 — SUPPLEMENTAL CASH FLOW INFORMATION

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

໿

	Successor			Predecessor
	February 9, 2018			January 1, 2018		Six
	Through			Through		Months Ended
	June 30, 2018			February 8, 2018		June 30, 2017
Supplemental cash flow information:
Cash paid for interest	$	22,996		$	1,145	$	23,452
Cash paid for income taxes	1,573			—		—
Non-cash investing and financing activities:
Change in asset retirement obligations	877			—		235
Asset retirement obligations assumed, purchased properties	—			—		89
Change in accruals or liabilities for capital expenditures	(25,798		)	4,712		37,494
Distribution of non-STACK assets (net liability)	—			33,102		—
Equity issued in Business Combination	2,067,393			—		—
Release of Common stock from possible redemption	966,384			—		—
Exchange of Class B common stock to Class A	3			—		—
Tax effect of redemption of noncontrolling interests in SRII Opco for Class A common shares and other	(437		)	—		—

NOTE 4 — BUSINESS COMBINATION

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

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 GP and (b) 100% of the economic interests in Kingfisher. 

At the closing of the Business Combination:

• the Company issued (i) 40,000,000 shares of Class A Common Stock and (ii) 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 $1,406.4 million in cash (the proceeds from 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 in SRII Opco (the “SRII Opco Common Units”) and (ii) 62,966,666 warrants to purchase SRII Opco Common Units (“SRII Opco Warrants”);

• 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 that were contributed to SRII Opco by the Contributors;

21

• 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 each 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 canceled.

During the second quarter of 2018, equity owners of the KFM Contributor elected to redeem 9,588,764 of its SRII Opco Common Units for an equal number of shares of Class A Common Stock. We elected to complete this redemption through a direct exchange, whereby the 9,588,764 SRII Opco Common Units are now owned by us, and we issued 9,588,764 shares of our Class A Common Stock to equity owners of the KFM Contributor and canceled 9,588,764 shares of our Class C Common Stock. As a result, at June 30, 2018, we own 46.6% of the limited partner interests in SRII Opco.

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 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 our Class A Common Stock equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):

໿

20-Day VWAP	Earn-Out Consideration Payable to AM Contributor	Earn-Out Consideration Payable to 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	—

໿

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 each 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 a 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 12 — Long Term Debt, Net.  

Pursuant to the Contribution Agreements, the AM Contributor and KFM Contributor delivered a final closing statement during the second quarter of 2018.  Based on the final closing statement, the AM Contributor received an additional 1,197,934 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock and the KFM Contributor remitted back to the Company $5.0 million in cash and 89,680 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock.

22

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 our assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by the Company. We have not completed the detailed valuation studies necessary to arrive at the final determination of the fair value of the assets acquired, the liabilities assumed and the related allocations of the purchase price in the Business Combination. As a result, the values of certain of our long-term assets and liabilities are preliminary in nature and are subject to change as additional information becomes available and as additional analysis is performed.  Pursuant to ASC 805, finalization of the values is to be completed within one year of the Acquisition Date.

Preliminary Estimated Purchase Price for Alta Mesa

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

	February 9, 2018 (As initially reported)		Measurement Period Adjustment (1)		February 9, 2018 (As adjusted)
Preliminary Purchase Consideration:(2)
SRII Opco Common Units issued (3)	$	1,251,782	$	9,467	$	1,261,249
Estimated fair value of contingent earn-out purchase consideration (4)	284,109		—		284,109
Settlement of preexisting working capital (5)	5,476		—		5,476
Total purchase price consideration	$	1,541,367	$	9,467	$	1,550,834

_________________

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

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

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

(4) For a period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of 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 as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to 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. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.

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

23

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):

໿

	February 9, 2018 (As initially reported)		Measurement Period Adjustment (1)		February 9, 2018 (As adjusted)
Estimated Fair Value of Assets Acquired(2)
Cash, cash equivalents and short term restricted cash	$	10,345	$	—	$	10,345
Accounts receivable	101,745		—		101,745
Other receivables	1,222		—		1,222
Receivables due from related party	907		—		907
Prepaid expenses and other current assets	1,405		—		1,405
Derivative financial instruments	352		—		352
Property and equipment:(3)
Oil and natural gas properties, successful efforts	2,314,858		9,467		2,324,325
Other property and equipment, net	43,318		—		43,318
Notes receivable due from related party	12,454		—		12,454
Deposits and other long-term assets	10,286		—		10,286
Total fair value of assets acquired	2,496,892		9,467		2,506,359
Estimated Fair Value of Liabilities Assumed (2)
Accounts payable and accrued liabilities	210,867		—		210,867
Advances from non-operators	6,803		—		6,803
Advances from related party	47,506		—		47,506
Asset retirement obligations (3)	5,998		—		5,998
Derivative financial instruments	11,585		—		11,585
Long-term debt(4)	667,700		—		667,700
Other long-term liabilities	5,066		—		5,066
Total fair value of liabilities assumed	955,525		—		955,525
Total consideration and fair value	$	1,541,367	$	9,467	$	1,550,834

_________________

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

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

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

(4) Represents the approximate fair value as of the acquisition date of Alta Mesa’s $500 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million, based on Level 1 inputs, and outstanding borrowings under the Alta Mesa Credit Facility (described in Note 12 — Long Term Debt, Net) of approximately$134.1 million as of the acquisition date.

24

Preliminary Estimated Purchase Price for Kingfisher

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

໿

໿

	February 9, 2018 (As initially reported)			Measurement Period Adjustments (1)			February 9, 2018 (As adjusted)
Preliminary Purchase Consideration:
Cash (2)	$	814,820		$	(5,008	)	$	809,812
SRII Opco Common Units issued (3)	434,640			(709		)	433,931
Estimated fair value of contingent earn-out purchase consideration (4)	88,105			—			88,105
Settlement of preexisting working capital (5)	(5,476		)	—			(5,476		)
Total purchase price consideration	$	1,332,089		$	(5,717	)	$	1,326,372

_________________

(1) The measurement period adjustments relate to the KFM Contributor remitting back to the Company $5.0 million in cash and 89,680 of SRII Opco Common Units valued at $7.90 per unit based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 (Successor).

(2) The cash consideration paid at February 9, 2018 is net of estimated net working capital adjustments, transaction expenses, capital expenditures and banking fees.

(3) At closing, the KFM Contributor received consideration of 55,000,000 SRII Opco Common Units valued at approximately $7.90 per unit, reflecting discounts for holding requirements and liquidity.

(4) 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.

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

25

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):

໿

	February 9, 2018 (As initially reported)		Measurement Period Adjustments (1)			February 9, 2018 (As adjusted)
Estimated Fair Value of Assets Acquired
Cash and cash equivalents	$	7,648	$	—		$	7,648
Accounts receivable	4,334		—			4,334
Prepaid expenses	550		—			550
Property, plant and equipment: (2)
Pipeline	272,442		—			272,442
Other property, plant and equipment	519		—			519
Intangible assets (3)	472,432		(54,952		)	417,480
Goodwill (4)	650,663		49,235			699,898
Total fair value of assets acquired	1,408,588		(5,717		)	1,402,871
Estimated Fair Value of Liabilities Assumed
Accounts payable and accrued liabilities	33,499		—			33,499
Long-term debt	43,000		—			43,000
Total fair value of liabilities assumed	76,499		—			76,499
Total consideration and fair value	$	1,332,089	$	(5,717	)	$	1,326,372

_________________

(1) The measurement period adjustments are recognized in the reporting period in which the adjustments were determined and calculated as if the accounting had been completed at the acquisition date. The measurement period adjustments relate to a change in the purchase price consideration based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 (Successor) and a revision in the value of Kingfisher's customer relationship intangible assets resulting from an adjustment to the initial discount rate used.

(2) The estimated fair values of crude oil, natural gas and NGL gathering, processing and storage assets are determined using valuation techniques that convert future cash flows to a single discounted amount and involved the use of certain inputs that are not observable in the market (Level 3 inputs). These valuations required significant judgments and estimates by management at the time of the valuation. Actual results may vary from these estimates.

(3) The identifiable intangible assets acquired are primarily related to customer relationships held by Kingfisher prior to Closing and are reflected at their estimated fair values as of the acquisition date determined using valuation techniques that convert future cash flows to a single discounted amount and involve the use of certain inputs that are not observable in the market (Level 3 inputs). These valuations required significant judgments and estimates by management at the time of the valuation. The intangible assets have definite lives and are subject to amortization over their economic lives, currently ranging from approximately 10-15 years.

(4) Goodwill reflected in the preliminary purchase price allocation includes 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.

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 information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including depletion of Alta Mesa’s 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 Periods, were adjusted to exclude $65.2 million of transaction-related costs incurred by the Company, Alta Mesa and Kingfisher. These costs are not included as they are directly related to the Business Combination and are nonrecurring.

26

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 June 30, 2017		February 9, 2018 Through June 30, 2018			Six Months Ended June 30, 2017
	(in thousands)
Total operating revenues	$	75,171	$	234,456		$	150,623
Net income (loss)	11,492		(34,440		)	36,757
Net income (loss) attributable to Alta Mesa Resources, Inc.	3,753		(11,725		)	11,971
Basic and diluted net income (loss) per share	0.02		(0.07		)	0.07

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

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

	Successor			Predecessor
	June 30, 2018			December 31, 2017
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	891,787		$	84,590
Accumulated impairment of unproved properties	—			—
Unproved properties, net	891,787			84,590
Proved oil and natural gas properties	1,695,596			1,061,105
Accumulated depreciation, depletion, amortization and impairment	(36,864		)	(251,065		)
Proved oil and natural gas properties, net	1,658,732			810,040
TOTAL OIL AND NATURAL GAS PROPERTIES, net	2,550,519			894,630
OTHER PROPERTY, PLANT AND EQUIPMENT
Land	5,600			2,912
Salt water disposal system	44,028			30,990
Plant and equipment	295,337			—
Office furniture and equipment, vehicles	2,105			20,008
Accumulated depreciation	(3,713		)	(21,770		)
OTHER PROPERTY, PLANT AND EQUIPMENT, net	343,357			32,140
TOTAL PROPERTY, PLANT AND EQUIPMENT, net	$	2,893,876		$	926,770

NOTE 6 — DISCONTINUED OPERATIONS (Predecessor)

Alta Mesa distributed its non-STACK assets and related liabilities to the AM Contributor immediately prior to the Closing Date of the Business Combination. The distribution of Alta Mesa’s non-STACK assets and related liabilities 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 Periods. 

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 –Description of Business, the Founder Notes were converted into an equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK asset distribution.  The balance of the Founder Notes at the time of conversion was approximately $28.3 million, including accrued interest.  Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period and $0.3 million and $0.6 million for the three months ended June 30, 2017 (Predecessor) and 2017 Predecessor Period, respectively.

27

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

	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

28

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

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

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

໿

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

NOTE 7—FAIR VALUE MEASUREMENTS

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

In connection with the acquisition of Alta Mesa, 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 $530.1 million at June 30, 2018 (Successor).  This estimation is based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination. See Note 12—Long-Term Debt, Net for information on long-term debt.

29

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

Oil, natural gas, and midstream properties are subject to impairment testing and potential impairment write down, as discussed in Note 2 — Summary of Significant Accounting Policies. During the 2017 Predecessor Period, certain of Alta Mesa's oil and natural gas properties with a carrying amount of $3.3 million were written down to their fair value of $2.1 million, resulting in an impairment charge of $1.2 million.  Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data. 

New additions to asset retirement obligations result from estimations for new or acquired properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $0.9 million, zero and $0.6 million in additions to asset retirement obligations measured at fair value during the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2018 and December 31, 2017, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:

໿

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

The amounts above are presented on a gross basis.  We will net the value of assets and liabilities with the same counterparty where master netting agreements are in place for purposes of presentation in our consolidated balance sheets. For additional information on derivative contracts, see Note 8—Derivative Financial Instruments.

NOTE 8—DERIVATIVE FINANCIAL INSTRUMENTS

Alta Mesa has entered into forward-swap contracts and collar contracts to reduce its exposure to price risk in the spot market for oil, natural gas and natural gas liquids. From time to time, Alta Mesa also utilizes 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 Alta Mesa's derivative contracts are executed by affiliates of its lenders under the Alta Mesa Credit Facility described in Note 12 -- Long Term Debt, Net, and are collateralized by the security interests of the respective affiliated lenders in certain of their assets under the Alta Mesa Credit Facility. The derivative contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (bbl) per month, natural gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production equivalent to volumes in gallons (gal) per month. The derivative contracts represent agreements between Alta Mesa 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. 

30

From time to time, Alta Mesa enters into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.  As of June 30, 2018, Alta Mesa is not a party to any interest rate swap agreements

Alta Mesa has not designated any of its derivative contracts as fair value or cash flow hedges.  Accordingly, Alta Mesa uses mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statements of operations at each reporting date.

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the 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 Alta Mesa's derivative instruments, none of which have been designated as hedging instruments under ASC 815:

Fair Values of Derivative Contracts:

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

໿

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

໿

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

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

31

The following table summarizes the effect of Alta Mesa's derivative instruments in the consolidated statements of operations (in thousands):

໿

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

Although Alta Mesa's counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow Alta Mesa, under certain circumstances, 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 12 — Long Term Debt, Net.

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

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

OIL DERIVATIVE CONTRACTS

໿

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

32

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

NATURAL GAS DERIVATIVE CONTRACTS

໿

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

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

Alta Mesa had the following open financial basis swaps at June 30, 2018:

NATURAL GAS BASIS SWAP DERIVATIVE CONTRACTS

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

_________________

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

OIL BASIS SWAP DERIVATIVE CONTRACTS

໿

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

_________________

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

33

NOTE 9 — INTANGIBLE ASSETS

Our intangible assets with finite lives include customer relationships within theMidstream segment acquired as part of the Business Combination. Intangible assets consisted of the following (in thousands):

໿

	Successor
	June 30, 2018
Customer contracts and related customer relationships	$	417,480
Accumulated amortization	(8,774		)
Intangibles, net	$	408,706
Weighted average amortization (years)	12

Amortization expense was $5.3 million and $8.8 million for the three months ended June 30, 2018 (Successor) and the Successor Period, respectively.  There was no amortization expense for the 2018 Predecessor Period and the 2017 Predecessor Periods, as there were no intangible assets as of these dates.  Estimated amortization expense for each of the subsequent five years and thereafter is as follows (in thousands):

໿

	Successor
Fiscal Year:	June 30, 2018
Remainder of 2018	$	10,377
2019	34,663
2020	40,998
2021	39,637
2022	38,490
Thereafter	244,541
Total amortization	$	408,706

NOTE 10 — EQUITY METHOD INVESTMENT

We account for our investment in unconsolidated affiliates under the equity method (See Note 2 – Summary of Significant Accounting Policies). The carrying value of the Company’s investment in unconsolidated affiliates is recorded in the consolidated balance sheets as “Equity method investments” and the Company records its share of such earnings (loss) in the consolidated statements of operations as “Income (loss) from equity investments.”

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 crude oil pipeline, which is owned by Cimarron Express Pipeline, LLC (“Cimarron Express”) and constructed and operated by Blueknight, will extend from northeastern Kingfisher County, Oklahoma, to Blueknight’s crude oil terminal in Cushing, Oklahoma.  Cimarron Express is owned 50% by an affiliate of Kingfisher and 50% by an affiliate of Ergon, Inc.  During the three months ended June 30, 2018 (Successor), we invested $7.0 million in Cimarron Express.

34

NOTE 11 — 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	877
Liabilities settled	(806		)
Liabilities transferred in sale of properties	(20		)
Revisions to estimates	665
Accretion expense	263
Balance, as of June 30 (Successor)	6,977
Less: Current portion	538
Long-term portion	$	6,439

NOTE 12 — LONG-TERM DEBT, NET

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

໿

	Successor		Predecessor
	June 30, 2018		December 31, 2017
Alta Mesa senior secured revolving credit facility	$	—	$	117,065
Kingfisher secured revolving credit facility	63,500		—
7.875% senior unsecured notes due 2024	500,000		500,000
Unamortized premium on senior unsecured notes	31,584		—
Unamortized deferred financing costs	—		(9,625		)
Total long-term debt, net	$	595,084	$	607,440

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 June 30, 2018, Alta Mesa has no borrowings under the Alta Mesa Credit Facility and has $21.9 million of outstanding letters of credit.

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 or, for Eurodollar loans, in one, three or six-month tranches. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, plus a margin ranging from 2.00% and 3.00%.  Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-

35

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. 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 collateral 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 general and administrative expenses (“G&A”) incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the Tax Receivable Agreement.  See Note 18 — Income Taxes for further information regarding the Tax Receivable Agreement. 

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

• a current ratio, tested quarterly, commencing with 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 for the four-fiscal quarter period then ended, of not greater than 4.0 to 1.0. 

As of June 30, 2018, Alta Mesa was in compliance with the financial ratios described above.

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.Prior to May 30, 2018, Kingfisher was party to a $200.0 million Revolving credit facility with ABN AMRO Capital USA, LLC, as administrative agent, and certain other financial institutions as lenders (the "prior credit facility"). The prior credit facility was initially entered into on August 8, 2017 and was scheduled to mature in August 2021. The principal amount of borrowings outstanding under this credit facility at May 30, 2018 totaled $59.5 million.

Effective May 30, 2018, Kingfisher entered into a $300.0 million amended and restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent and letter of credit issuer, and certain other financial institutions, as lenders (“the Kingfisher Credit Facility”) which replaced the prior credit facility with ABN AMRO. The Kingfisher Credit Facility matures on May 30, 2023. Initial borrowings of $62.5 million under this new facility were utilized to repay amounts outstanding under the prior credit facility, including accrued interest and various fees due the new lenders, as well as third parties involved in the establishment of the new credit facility.

Availability under the Kingfisher Credit Facility will be redetermined each fiscal quarter as the lesser of (1) the $300.0 million commitment under the Kingfisher Credit Facility and (2) the maximum amount that, together with the aggregate amount of all then-outstanding consolidated funded indebtedness (other than indebtedness under the Kingfisher Credit Facility) would result in Kingfisher being in pro forma compliance with all applicable leverage ratios at such time.

The amounts outstanding under the Kingfisher Credit Facility are secured by first priority liens on substantially all of Kingfisher’s and its subsidiaries’ real property and associated assets and all of the stock of Kingfisher’s operating subsidiaries that are guarantors of the new credit facility. Additionally, SRII Opco, LP has pledged its membership interests in Kingfisher as security for Kingfisher’s obligations. If an event of default occurs under the new credit facility, the administrative agent will have the right to proceed against the pledged membership interests and take control of substantially all of the assets of Kingfisher and its subsidiaries that are guarantors.

36

Kingfisher has a choice of borrowing in Eurodollars or at the reference rate, with such borrowings bearing interest, payable quarterly for reference rate loans or, for Eurodollar loans, in one, three or six-month tranches.  Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, plus a margin ranging from 2.00% to 3.25% (which changes to 1.75% to 2.75% from and after a qualifying IPO).  Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus an applicable margin ranging from 1.00% to 2.25% (which changes to 0.75% to 1.75% from and after a qualifying IPO).

The Kingfisher Credit Facility also contains restrictive covenants that may limit Kingfisher’s ability to, among other things, incur additional indebtedness (but with a carve-out that allows Kingfisher to incur indebtedness under senior unsecured notes, subject to certain restrictions, including pro forma financial covenant compliance), 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 credit facility permits Kingfisher to (i) make distributions to pay its parent entity for reimbursement of general corporate operating and overhead costs and expenses incurred in the ordinary course of business of such parent entity pursuant to its management services agreement, (ii) make permitted tax distributions, and (iii) make cash distributions so long as certain requirements relating to Kingfisher's consolidated earnings before interest, taxes, depreciation, amortization and material projects (“Consolidated Adjusted EBITDA”), its leverage ratio, and Kingfisher Credit Facility usage are satisfied, in addition to other customary requirements.

The Kingfisher Credit Facility also requires it to maintain the following financial ratios, which utilize Consolidated Adjusted EBITDA annualized by multiplying the Consolidated Adjusted EBITDA 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, Consolidated Adjusted EBITDA for the four-fiscal quarter period then ended:

• a total leverage ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of its consolidated funded indebtedness as of the end of such fiscal quarter to its Consolidated Adjusted EBITDA for such rolling fiscal quarter period, of not greater than 4.5 to 1.0 (which increases to 4.75 after Consolidated EBITDA equal to or greater than $75.0 million is achieved for a rolling fiscal quarter period or a qualifying IPO occurs);

• from and after the incurrence of indebtedness under senior unsecured notes, a senior secured leverage ratio, tested quarterly, of its consolidated funded secured indebtedness as of the end of such fiscal quarter to its Consolidated Adjusted EBITDA for such rolling fiscal quarter period, of not greater than 3.5 to 1.0; and

• a minimum interest coverage ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of its Consolidated Adjusted EBITDA for such rolling fiscal quarter period to its consolidated interest expense for such rolling fiscal quarter period, of not less than 2.5 to 1.0.

As of June 30, 2018, outstanding borrowings under the Kingfisher Credit Facility totaled $63.5 million and there were no outstanding letters of credit. Kingfisher was also in compliance with the financial ratios specified in the KFM Credit Facility at that date.

Senior Unsecured Notes.  Alta Mesa has$500 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) 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. 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 for an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, 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

37

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's existing and future senior indebtedness; senior in right of payment to all of Alta Mesa's existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of Alta Mesa's 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's 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 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.

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

As of June 30, 2018, Alta Mesa was in compliance with the indentures governing the senior notes.

Bond Premium (Successor).  As discussed in Note 7, 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 recognized in interest expense was $1.2 million and $2.1 million for the three months ended June 30, 2018 (Successor) and the Successor Period, respectively.  The unamortized bond premium related to the senior notes is included as a component of long-term debt in the consolidated balance sheet as of June 30, 2018. 

Maturities (Successor).  Future maturities of long-term debt, excluding unamortized bond premium, at June 30, 2018 are as follows:

໿

Fiscal Year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	63,500
Thereafter	500,000
	$	563,500

38

Deferred financing costs.As of December 31, 2017, Alta Mesa had $11.4 million of unamortized deferred financing costs related to both its senior secured notes and the Alta Mesa Credit Facility.  As a result of the Business Combination, Alta Mesa's unamortized deferred financing costs have been adjusted to a fair value of zero at February 9, 2018.  During the Successor Period, we incurred additional deferred financing costs related to Alta Mesa’s Credit Facility and Kingfisher's new credit facility entered into on May 30, 2018 of $1.4 million and $2.3 million, respectively. These costs are reflected as deferred financing costs, net in other noncurrent assets in the consolidated balance sheet as of June 30, 2018 (Successor).  The amortization of the deferred financing costs is included in interest expense in the consolidated statements of operations. For the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), the amortization of deferred financing costs was $0.2 million and $0.5 million, respectively. For the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, the amortization of deferred financing costs was $0.2 million, $0.2 million, and $1.5 million, respectively. 

NOTE 13 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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

໿

	Successor		Predecessor
	June 30, 2018		December 31, 2017
Accruals for capital expenditures	$	63,830	$	48,771
Revenues and royalties payable	36,702		29,514
Accruals for operating expenses/taxes	9,884		14,632
Accrued interest	1,786		2,587
Derivative settlement payable	4,510		2,106
Other	6,377		4,301
Total accrued liabilities	123,089		101,911
Accounts payable	25,777		68,578
Accounts payable and accrued liabilities	$	148,866	$	170,489

NOTE 14 — 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 consolidated financial statements at June 30, 2018.

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

Litigation (Predecessor). On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” 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.

39

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

Litigation (Successor). On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including 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 Kingfisher 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 Successor Period.  Following the closing of the Business Combination, the Plan was terminated.

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 the 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 and certain field equipment such as compressors, under long-term operating lease agreements.  On April 1, 2018, Alta Mesa amended its lease agreement for its corporate headquarters located in Houston, Texas.  The amended lease agreement provides for office 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 April 2028. Any initial rent-free months are amortized over the life of the lease.  Equipment leases are generally for two years or less. For the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), total rent expense, net of sublease income, including office space and compressors, was approximately $0.8 million and $2.6 million, respectively. Total rent expense, net of sublease income, including office space and compressors, were approximately $1.5 million, $1.1 million, and $5.2 million for the Successor Period, the 2018 Predecessor Period, and for the 2017 Predecessor Period, respectively.

40

At June 30, 2018, the future minimum base rentals for non-cancelable operating leases were as follows: 

໿

Fiscal Year	(in thousands)
Remainder of 2018	$	1,293
2019	2,673
2020	2,753
2021	2,812
2022	3,009
Thereafter	15,257
	$	27,797

Firm transportation contracts.  The Company has entered into certain firm transportation contracts that extend through 2036.  At June 30, 2018, the future minimum commitments related to these contracts were as follows:

໿

Fiscal Year	(in thousands)
Remainder of 2018	$	6,984
2019	10,976
2020	7,876
2021	7,876
2022	7,876
Thereafter	85,215
	$	126,803

NOTE 15 — 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.

NOTE 16 — STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL

Redeemable PreferredStockand Stockholders’ 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 our 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

41

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, 204,921,888 of which are outstanding as of June 30, 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 canceled. During the three months ended June 30, 2018 (Successor), we issued 9,588,764 shares of our Class A common stock to equity owners of the KFM Contributors and canceled 9,588,764 shares of our Class C Common Stock as a result of the direct exchange of SRII Opco Common Units redemption. See Note 4 - Business Combination (Successor) for further discussion.

Redeemable Series A Preferred Stock. As of June 30, 2018, Bayou City Energy Management LLC (“Bayou City”), HPS Investment Partners, LLC (“HPS”) and AM Equity Holdings, LP (“AM Management”) each own one of 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 up to five years following the closing of the Business Combination based on their and their affiliates’ beneficial ownership of common stock. 

Redeemable Series BPreferred Stock. As of June 30, 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 up to five years following the closing of the Business Combination based on its and its affiliates’ beneficial ownership of common stock.

42

Warrants. As of June 30, 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”), 15,333,333 Private Placement Warrants sold to the Company’s Sponsor and 13,133,333 Forward Purchase Warrants issued 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 are currently exercisable 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. 

The Private Placement Warrants are identical to the Public Warrants underlying the Units sold in the Initial Public Offering, except the Private Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees.

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 non-redeemable so long as they are held by our Sponsor or its permitted transferees. 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 non-controlling interest relates to SRII Opco Common Units that were originally issued to the AM Contributor, the KFM 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 owners held 55.8% (AM Contributor 36.2%, KFM Contributor 14.4%, and Riverstone Contributor 5.2%) of the limited partner interests in SRII Opco. The non-controlling interest percentage is affected by various equity transactions such as Class C Common Stock conversions and Class A Common Stock activities described above. As of June 30, 2018, the noncontrolling interest owners held 53.4% of the limited partner interests in SRII Opco.

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

Management and Control (Predecessor).  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 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 Alta Mesa 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. 

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 President and Chief Executive Officer and a director, Michael Ellis, the founder of Alta Mesa and our Chief Operating Officer—Upstream 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 17 — 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. Prior to the Business Combination, we did not have any equity based compensation programs. Pursuant to the LTIP, certain grants of stock-based awards were made on February 9, 2018.  During the Successor Period, the Company recognized non-cash stock-based compensation expense of $7.7 million resulting from stock options, restricted stock and RSUs awards, which is included in general and administrative expense in the accompanying consolidated

43

statements of operations.  Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.

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

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

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	4,888,418		4.49		—
Exercised	—		—		—
Forfeited or expired	(32,911	)	4.62		—
Outstanding as of June 30, 2018	4,855,507		$	4.48	6.7	$	21,753
Exercisable as of June 30, 2018	—		$	—	—	$	—

Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable three-year vesting period.  The Company estimates the fair value using the Black-Scholes option-pricing model.  Expected volatilities are based on the re-levered asset volatility implied by a set of comparable companies.  Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to 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 June 30, 2018
Expected term (in years)	4.5
Expected stock volatility	64.6	%
Dividend yield	—
Risk-free interest rate	2.4	%

As of June 30, 2018, there was $19.0 million of unrecognized compensation cost related to non-vested stock options. The Company expects to recognize that cost on a pro rata basis over a weighted average period of 2.7 years.

Restricted stock.  Restricted stock granted to employees generally vests in one-third increments each year on the anniversary date following the date of grant, based on continued employment. Prior to vesting, no dividends are paid and the shares may not be traded. During the period from February 9, 2018 to June 30, 2018, the Company granted 98,199 fully-vested restricted stock awards to certain of its directors and 1,784,247 restricted stock awards to employees. Shares granted to directors vest immediately upon grant.

44

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	1,784,247		8.34
Vested	(98,199	)	8.46
Forfeited or expired	(14,627	)	8.94
Outstanding as of June 30, 2018	1,671,421		$	8.33

Compensation cost for restricted shares is based upon the grant-date market value of the award, recognized ratably over the applicable vesting period, subject to the employee's continued service.  Unrecognized compensation cost related to unvested restricted shares at June 30, 2018 was $12.3 million, which the Company expects to recognize over a weighted average remaining period of 2.7 years.

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

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

	Successor
	PSUs		Weighted Average Grant Date Fair Value per unit
Outstanding as of February 9, 2018	—		$	—
Granted	802,940		8.73
Vested	—		—
Forfeited or expired	(3,901	)	8.94
Outstanding as of June 30, 2018	799,039		$	8.73

As of June 30, 2018, there was $3.1 million of unrecognized compensation cost related to the unvested PSUs which we expect to recognize on a pro rata basis over a weighted average remaining period of 0.5 years.

NOTE 18 — 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 which 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.

The 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 June 30, 2018.  During the second quarter of 2018, there were two exchanges of SRII Common units made by the KFM contributors. The tax effects of these transactions were treated as discrete items for purposes of the annual effective income tax rate calculation.  The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment 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

45

effect of noncontrolling 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) is included in the consolidated statements of operations are detailed below (in thousands):

໿

	Successor
	February 9, 2018 Through June 30, 2018
Current taxes:
Federal	$	—
State	—
	—
Deferred taxes:
Federal	(6,111		)
State	(1,380		)
	(7,491		)
Income tax benefit	$	(7,491	)

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 tax 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 June 30, 2018, no exchange of SRII Common Units has occurred, which would trigger a payment under the Tax Receivable Agreement, 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

46

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 19 — RELATED PARTY TRANSACTIONS

On September 29, 2017, Alta Mesa entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC, a Delaware limited liability company (“NWGP”), which was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of High Mesa, Inc. (“High Mesa”).  The promissory note 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 maturing on February 28, 2019.  At June 30, 2018 and December 31, 2017, amounts due under the promissory note totaled $1.6 million and $1.5 million, respectively.

Alta Mesa also has an $8.5 million long-term note receivable from HMS.  The long-term note receivable, which matures on December 31, 2019, bears interest at 8% per annum, payable quarterly.  As of June 30, 2018, and December 31, 2017, the balance of the note receivable amounted to $11.3 million and $10.8 million, respectively.  The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve.  For the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), interest income on the note receivable from our affiliate amounted to approximately $0.3 million and $0.2 million, respectively. Interest income on the note receivable from our affiliate amounted to approximately $0.4 million, $0.1 million, and $0.4 million for the Successor Period, the 2018 Predecessor Period, and 2017 Predecessor Period, respectively. Such amounts have been added to the balance of the note receivable.

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

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 $47,000 and $36,000 for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively. Total expenditures under this arrangement were approximately $83,000, $28,000, and $80,000 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 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 $67,100 and $57,700 for the three months ended June 30, 2018

47

(Successor) and 2017 (Predecessor), respectively. For the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, David McClure received total compensation of approximately $1,012,000, $938,500, and $125,200, 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 $34,700 and $34,600 for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively. For the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, David Pepper received total compensation of approximately $137,900, $153,100, and $73,300 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. 

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. Alta Mesa is responsible for any drilling and completion costs exceeding the aggregate limit of $64 million in any tranche. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return.  Following the completion of each joint well, Alta Mesa and BCE will each bear its respective proportionate working interest share of all subsequent costs and expenses related to such joint well.  Mr. William McMullen, 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.  During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill the additional wells under the joint development agreement. As of June 30, 2018, 52 joint wells have been drilled or spudded leaving 28 wells to be drilled under the joint development agreement. As of June 30, 2018 (Successor) and December 31, 2017 (Predecessor), $37.1 million and $23.4 million, respectively, in advances from related party were reflected in our consolidated balance sheets, which represents net advances remaining from BCE for their working interest share of the drilling and development cost as part of the joint development agreement. BCE may request refunds of certain advances, as they did subsequent to June 30, 2018, if funded wells previously on the drilling schedule were subsequently removed. At the request of BCE, approximately $32.4 million of advances for such wells was refunded on July 26, 2018. On August 3, 2018, replacement AFEs were issued to BCE for another 10 wells to be drilled this year with a cash call made to BCE for approximately $26.0 million.

In connection with the Closing, Alta Mesa 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 June 30, 2018 (Successor) and December 31, 2017 (Predecessor), approximately $0.9 million and $0.8 million, respectively, were due from High Mesa for reimbursement of expenses which are recorded as receivables due from related party on the consolidated balance sheets.

48

NOTE 20 — SUBSIDIARY GUARANTORS

All of Alta Mesa’s material wholly-owned subsidiaries are guarantors under the terms of its senior notes and the Alta Mesa Credit Facility. 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 the Alta Mesa Credit Facility, are immaterial subsidiaries.  Kingfisher’s material wholly-owned subsidiary is a guarantor under the terms of the Kingfisher 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. There are restrictions on dividends, distributions, loans or other transfers of funds from the subsidiary guarantors to us.

NOTE 21 — 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 ultimately 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 Periods, as such no disclosure is noted for these periods. For additional information regarding the Company’s reportable segments, see Note 2—Summary of Significant Accounting Policies.  

	Successor
	Three Months Ended June 30, 2018
	Exploration and Production			Midstream			Eliminations			Total
	(in thousands)
Product line revenues from third-party customers	$	93,512		$	26,678		$	—		$	120,190
Inter-segment revenues	—			21,135			(21,135		)	—
Total segment product line revenues	$	93,512		$	47,813		$	(21,135	)	120,190
Other revenues										2,229
Total operating revenues										$	122,419
Operating income (loss)	$	(12,929	)	$	(1,629	)	$	—		$	(14,558	)
Other income (expense)	(9,541		)	(1,418		)	—			(10,959		)
Segment net income (loss) before tax	$	(22,470	)	$	(3,047	)	$	—		(25,517		)
Corporate expenses										(501		)
Income (loss) from continuing operations before income taxes										$	(26,018	)

49

	Successor
	February 9, 2018 Through June 30, 2018
	Exploration and Production			Midstream			Eliminations			Total
	(in thousands)
Product line revenues from third-party customers	$	143,714		$	38,458		$	—		$	182,172
Inter-segment revenues	—			32,431			(32,431		)	—
Total segment product line revenues	$	143,714		$	70,889		$	(32,431	)	182,172
Other revenues										2,784
Total operating revenues										$	184,956
Operating income (loss)	$	(42,850	)	$	(3,247	)	$	—		$	(46,097	)
Other income (expense)	(14,191		)	(1,666		)	—			(15,857		)
Segment net income (loss) before tax	$	(57,041	)	$	(4,913	)	$	—		(61,954		)
Corporate expenses										(1,426		)
Income (loss) from continuing operations before income taxes										$	(63,380	)

The following table summarizes our revenue by product line for the periods presented:

	Successor
	Three Months Ended June 30, 2018
	Exploration and Production		Midstream		Eliminations			Total
	(in thousands)
Product line revenues:
Oil sales	$	75,291	$	—	$	—		$	75,291
Natural gas sales	7,980		—		—			7,980
Natural gas liquids sales	10,241		—		—			10,241
Product sales	—		31,708		(12,103		)	19,605
Gathering and processing revenue	—		16,105		(9,032		)	7,073
Total product line revenues	$	93,512	$	47,813	$	(21,135	)	120,190
Other revenues								2,229
Total operating revenues								$	122,419

໿

	Successor
	February 9, 2018 Through June 30, 2018
	Exploration and Production		Midstream		Eliminations			Total
	(in thousands)
Product line revenues:
Oil sales	$	115,569	$	—	$	—		$	115,569
Natural gas sales	13,190		—		—			13,190
Natural gas liquids sales	14,955		—		—			14,955
Product sales	—		46,812		(18,838		)	27,974
Gathering and processing revenue	—		24,077		(13,593		)	10,484
Total product line revenues	$	143,714	$	70,889	$	(32,431	)	182,172
Other revenues								2,784
Total operating revenues								$	184,956

50

The following table summarizes total assets by segment:

໿

໿

	Successor
	June 30, 2018
	Exploration and Production		Midstream		Eliminations			Total
	(in thousands)
Total segment assets	$	2,817,744	$	1,425,028	$	(4,145	)	$	4,238,627
Corporate assets								14,887
Total assets								$	4,253,514

NOTE 22—SUBSEQUENT EVENTS

The Company’s Board of Directors has authorized a share repurchase program to acquire up to $50 million of outstanding Class A common stock. Repurchases may be made at the Company’s discretion in accordance with applicable securities laws from time to time in open market or private transactions.

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

51

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

Alta Mesa Resources, Inc., together with its consolidated subsidiaries, (“AMR,” “we,” “us,” “our,” or the “Company”) is an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County ("STACK").

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

We also operate a midstream services business through Kingfisher Midstream LLC ("Kingfisher"). Kingfisher has natural gas gathering and processing and crude gathering assets located in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The Kingfisher assets are integral to our oil and natural gas operations and strategically positioned to provide similar services to other producers in the area.

Additional information relating to the formation of the Company and the acquisition of Alta Mesa and Kingfisher on February 9, 2018, may be found in Notes 1 and 4 of the Notes to Consolidated Financial Statements. In connection with closing of the business combination involving Alta Mesa and Kingfisher, Alta Mesa also distributed its non-STACK assets and related liabilities to High Mesa Holdings, LP (the "AM Contributor"), which is more fully described in Note 6 of the Notes to Consolidated Financial Statements, relating to discontinued operations.

As a result of the acquisition of Alta Mesa and Kingfisher and the consummation of the transactions described in Note 1 of the Notes to Consolidated Financial Statements, the Company's financial statement presentation reflects Alta Mesa as the "Predecessor" for periods prior to February 9, 2018. The Company, including the consolidated results of Alta Mesa and Kingfisher, is the "Successor" for periods since February 9, 2018.

Outlook, Market Conditions and Commodity Prices

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

Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and it is uncertain whether the increase in market prices experienced in recent months will be sustained.  As a result, we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues.  In the event that oil, natural

52

gas and NGLs prices significantly decrease, such decreases could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, goodwill and intangible assets, our proved reserves and our ability to finance operations, including the amount of the borrowing capacity under the Alta Mesa and Kingfisher senior secured revolving credit facilities.  The following table sets forth the average New York Mercantile Exchange prices for oil and natural gas for the three and six months ended June 30, 2018 and 2017:

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

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

Our derivative contracts are reported at fair value on our consolidated balance sheets and are sensitive to changes in the price of oil, natural gas and NGLs. Changes in these derivative assets and liabilities are reported in our consolidated statements of operations as gain (loss) on derivative contracts, which include both the non-cash increase and decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. For the three months ended June 30, 2018 (Successor), we recognized a net loss on our derivative contracts of $29.2 million, which includes $14.4 million in cash settlements received for derivative contracts. We recognized a net loss on our derivative contracts of $51.9 million in the Successor Period, which includes $19.0 million in cash settlements received for derivative contracts. The objective of our hedging program is to produce, over time, relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and we expect these gains and losses to continue to reflect the impact of changes in oil and natural gas prices.

Operations Update

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

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

53

wells in progress as of June 30, 2018, of which 1 was funded through our joint development agreement with BCE.  As of August 1, 2018, 3 of the 25 operated horizontal wells in progress as of June 30, 2018 were on production.

As of June 30, 2018, we had 8 drilling rigs operating in the STACK focused on oil and gas drilling and 1 additional drilling rig targeting salt water disposal well drilling.  At the beginning of August 2018, we had 8 drilling rigs operating in the STACK, but have begun work on adding a ninth drilling rig before year end.  We plan to continue targeting the Mississippian-age Osage, Meramec, and Manning formations and the Pennsylvanian-age Oswego formation with horizontal drilling.  We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Osage formations.

Production from our STACK assets was as follows:

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

Kingfisher’s midstream assets include approximately 400 miles of existing low and high-pressure pipelines, two cryogenic natural gas processing plants with a combined 260 MMcf/d of gas processing capacity, 90 MMcf/d in offtake processing capacity, field compression facilities, 50,000 barrels of crude storage, 90,000 gallons of onsite NGL bullet storage and marketing capabilities. Additionally, Kingfisher owns 145,000 Dth/d of firm transport residue pipeline capacity on nearby interstate pipelines, with Alta Mesa owning an additional 100,000 Dth/d of firm transport residue pipeline capacity.  

On May 10, 2018, Kingfisher announced a partnership to develop a long-haul crude pipeline project, the Cimarron Express Pipeline, from the existing crude storage tank located at the Kingfisher natural gas plant site to a crude terminal site at Cushing, Oklahoma.  Kingfisher 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. Kingfisher has also begun expansion of its natural gas system, with a high-pressure line planned to connect the existing system to Southeastern Major County, Oklahoma.

During the three months ended June 30, 2018, Kingfisher gathered gas volumes of 96 MMcf/d and connected 51 new wells to the system. Kingfisher also gathered crude volumes of 4,264 bbl/d.

Results of Operations

Business Segments

Our discussion of results of operations is presented on a 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.  See Note 21 – Business Segment Information to our consolidated financial statements for further detail.

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

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

54

Exploration & Production Segment Results

Revenues

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

	Successor			Predecessor
	Three Months Ended June 30, 2018			Three Months Ended June 30, 2017
Revenues (in thousands, except per unit data)
Oil sales	$	75,291		$	42,348
Natural gas sales	7,980			10,642
Natural gas liquids sales	10,241			6,581
Total E&P sales revenues	$	93,512		$	59,571
Net production:
Oil (Mbbls)	1,123			903
Natural gas (MMcf)	3,944			3,886
NGLs (Mbbls)	554			314
Total (MBoe)	2,334			1,865
Average net daily production volume:
Oil (Mbbls/d)	12.3			9.9
Natural gas (MMcf/d)	43.3			42.7
NGLs (Mbbls/d)	6.1			3.4
Total (MBoe/d)	25.6			20.5
Average sales prices:
Oil (per bbl)	$	67.09		$	46.90
Effect of derivative settlements on average price (per bbl)	(12.80		)	1.68
Oil, net of hedging (per bbl)	$	54.29		$	48.58
Natural gas (per Mcf)	$	2.02		$	2.74
Effect of derivative settlements on average price (per Mcf)	—			0.22
Natural gas, net of hedging (per Mcf)	$	2.02		$	2.96
Natural gas liquids (per bbl)	$	18.47		$	20.97
Effect of derivative settlements on average price (per bbl)	—			(0.51		)
Natural gas liquids, net of hedging (per bbl)	$	18.47		$	20.46

໿

໿

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

Natural gas revenues were 9% and 18% of our total E&P sales revenues for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively. Natural gas revenues for the three months ended June 30, 2018 (Successor) decreased approximately $2.7 million, or 25%, as compared to June 30, 2017 (Predecessor) due to lower average prices partially offset by

55

an increase in production. The lower average prices are tied to the overall decrease in natural gas commodity prices as discussed above. Natural gas production was 28% and 35% of total BOE production volume for the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), respectively.

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

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

໿

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

Operating Expenses

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

໿

	Successor		Predecessor
	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
Operating expenses (in thousands, except per unit data):
Lease operating expense	$	12,679	$	11,480
Marketing and transportation expense	2,173		6,510
Production taxes	2,606		1,184
Production cost per BOE:
Lease operating expense	$	5.43	$	6.16
Marketing and transportation expense	0.93		3.49
Production taxes	1.12		0.63

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

Marketing and transportation expense in the Predecessor Period largely represents throughput for our properties in the STACK at the Kingfisher processing facility. Marketing and transportation expense for the three months ended June 30, 2018

56

(Successor) decreased approximately $4.3 million, or 67%, as compared to June 30, 2017 (Predecessor) primarily due to inter-segment elimination with our midstream segment. 

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

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

໿

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

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

໿

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

General and administrative expense(“G&A”). For the three months endedJune 30, 2018 (Successor), G&A increased approximately $9.5 million, or 115%, as compared to the three months ended June 30, 2017 (Predecessor), primarily due to increased labor-related costs of $3.9 million and non-cash charges for equity compensation of $3.6 million.  See Note 17 — Equity-Based Compensation for further detail on equity-based compensation awards granted during the Successor Period. No such awards were made during the Predecessor Period.

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

Other Income (Expense)

Interest expense. For the three months ended June 30, 2018 (Successor), interest expense decreased $2.2 million, or 18%, as compared to the three months ended June 30, 2017 (Predecessor), primarily due to lower interest on Alta Mesa's senior secured revolving credit facility of $2.1 million, resulting from the repayment of the predecessor Alta Mesa senior secured revolving credit facility in connection with the Business Combination, and bond premium amortization of $1.2 million. These decreases were partially offset by the increase in other interest expense of $1.1 million related our joint development agreement with BCE. The following table summarizes our interest expense for the periods presented (in thousands):

໿

57

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

Midstream Segment Results

Revenues

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

The following table summarizes our midstream revenues, net of inter-segment eliminations (in thousands):

໿

	Successor
	Three Months Ended June 30, 2018
Product sales	$	19,605
Gathering and processing revenue	7,073
Total Midstream operating revenues	$	26,678

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 NGLs at a market price.  We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense. The product sales are recognized when sold to the third-party purchaser. The Company acquired Kingfisher (our Midstream business) on February 9, 2018 pursuant to the Business Combination.

Gathering and processing revenues were driven by natural gas volumes gathered and processed and crude oil volumes gathered under commercial agreements and the fees assessed for such services.  Certain contracts provide for fee revenue, which may be charged to a producer customer even if the underlying production volumes are not flowing to Kingfisher. The throughput of natural gas gathered and processed and crude oil gathered is derived from the level of activity of the producer customers drilling and completing wells. 

Expenses

The following table summarizes our midstream expenses, net of inter-segment eliminations (in thousands):

	Successor
	Three Months Ended June 30, 2018
Plant operating expense	$	3,313
Product expense	19,383
Gathering and processing expense	3,240
Depreciation, depletion and amortization	7,264
Interest expense	1,418

As midstream revenues and expenses are reported net of inter-segment eliminations in the tables above, they should not be construed as representing gross margin for this segment on a stand-alone basis.

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

58

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

Gathering and processing expense includes compression, gathering, processing, & deficiency fees for offtakes along with NGL trucking fees & residue pipeline fees.

Depreciation, depletion and amortization expense 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 primarily includes non-cash charges for equity compensation, labor-related costs and insurance.

	Successor
	Three Months Ended June 30, 2018
(in thousands)
Equity-based compensation expense	$	465
General and administrative expenses	3,675
Total general and administrative expenses	$	4,140

For the Periods from February 9, 2018 Through June 30, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor) Compared to Six Months Ended June 30, 2017 (Predecessor)

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

Exploration & Production Segment Results

Revenues

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

59

໿

	Successor			Predecessor
	February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 9, 2018			Six Months Ended June 30, 2017
Revenues (in thousands, except per unit data)
Oil sales	$	115,569		$	30,972		$	89,288
Natural gas sales	13,190			4,276			20,233
Natural gas liquids sales	14,955			4,000			13,653
Total E&P sales revenues	$	143,714		$	39,248		$	123,174
Net production:
Oil (Mbbls)	1,774			494			1,845
Natural gas (MMcf)	6,192			1,609			7,003
NGLs (Mbbls)	777			151			589
Total (MBoe)	3,583			914			3,601
Average net daily production volume:
Oil (Mbbls/d)	12.5			12.7			10.2
Natural gas (MMcf/d)	43.6			41.2			38.7
NGLs (Mbbls/d)	5.5			3.9			3.3
Total (MBoe/d)	25.2			23.4			19.9
Average sales prices:
Oil (per bbl)	$	65.16		$	62.68		$	48.39
Effect of derivative settlements on average price (per bbl)	(11.01		)	(6.44		)	(0.04		)
Oil, net of hedging (per bbl)	$	54.15		$	56.24		$	48.35
Natural gas (per Mcf)	$	2.13		$	2.66		$	2.89
Effect of derivative settlements on average price (per Mcf)	0.09			0.94			0.10
Natural gas, net of hedging (per Mcf)	$	2.22		$	3.60		$	2.99
Natural gas liquids (per bbl)	$	19.25		$	26.41		$	23.18
Effect of derivative settlements on average price (per bbl)	—			—			(0.66		)
Natural gas liquids, net of hedging (per bbl)	$	19.25		$	26.41		$	22.52

໿

໿

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

Natural gas revenues were 9%, 11% and 16% of our total E&P net sales revenues for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Natural gas revenues for the Successor Period and the 2018 Predecessor Period decreased compared to the 2017 Predecessor Period due to lower average prices, partially offset by an increase in production in the first six months of 2018. The lower average prices are tied to the overall decrease in natural gas commodity prices as discussed above. Natural gas production was approximately 29%, 29% and 32% of total BOE production volume for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.

Natural gas liquid revenues were 10%, 10% and 11% of our total E&P net sales revenues for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Natural gas liquid revenues for the Successor Period and the 2018 Predecessor Period increased compared to the 2017 Predecessor Period due to an increase in production during the period,

60

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

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

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

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

໿

Operating Expenses

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

໿

	Successor		Predecessor
	February 9, 2018		January 1, 2018		Six
	Through		Through		Months Ended
	June 30, 2018		February 8, 2018		June 30, 2017
Operating expenses (in thousands, except per unit data):
Lease operating expense	$	20,996	$	4,485	$	22,490
Marketing and transportation expense	3,194		3,725		12,172
Production taxes	4,021		953		2,450
Production cost per BOE:
Lease operating expense	$	5.86	$	4.91	$	6.25
Marketing and transportation expense	0.89		4.08		3.38
Production taxes	1.12		1.04		0.68

Lease operating expense primarily consists of costs related to compression, chemicals, fuel, power and water and associated labor. Lease operating expense per BOE was $5.86 for the Successor Period, $4.91 for the 2018 Predecessor Period and $6.25 for the 2017 Predecessor Period.  The lease operating expense cost per BOE for the Successor Period and 2018 Predecessor Period was lower as compared to the 2017 Predecessor Period primarily due to increased NGL production resulting from higher BOE production of oil and natural gas and an amended contract which allows for a greater recovery of ethane, commencing in the second quarter of 2018.  

Marketing and transportation expense in the Predecessor Periods largely represents throughput for our properties in the STACK at the Kingfisher processing facility. Marketing and transportation expense in the Successor Period was lower due to inter-segment elimination with our midstream segment.

61

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

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

໿

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

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

໿

	Successor		Predecessor
	February 9, 2018		January 1, 2018		Six
	Through		Through		Months Ended
	June 30, 2018		February 8, 2018		June 30, 2017
(in thousands)
Depreciation, depletion and amortization	$	37,445	$	11,784	$	39,088
Depreciation, depletion and amortization per BOE	$	10.45	$	12.89	$	10.85

General and administrative expense(“G&A”) includes non-cash charges for equity compensation in the Successor Period.  See Note 17 — Equity-Based Compensation for further detail on equity-based compensation awards granted during the Successor Period. No such awards were made during the Predecessor Periods. G&A expenses for the Successor Period and the 2018 Predecessor Period included $25.7 million and $17.0 million, respectively, of transaction expenses primarily attributable to the consummation of the Business Combination.

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

Other Income (Expense)

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

໿

62

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

Midstream Segment Results

Revenues

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

The following table summarizes our midstream revenues, net of inter-segment eliminations (in thousands):

໿

	Successor
	February 9, 2018 Through June 30, 2018
Product sales	$	27,974
Gathering and processing revenue	10,484
Total Midstream operating revenues	$	38,458

Product sales were recognized from the sale of processed residue, condensate and NGLs. We process the natural gas on behalf of the producer and sell the resulting gas, condensate and NGLs at a market price.  We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense. The product sales are recognized when sold to the third-party purchaser. The Company acquired Kingfisher (our Midstream business) on February 9, 2018 pursuant to the Business Combination.

Gathering and processing revenues were driven by natural gas volumes gathered and processed and crude oil volumes gathered under its commercial agreements and the fees assessed for such services.  Certain contracts provide for fee revenue, which may be charged to a producer customer even if the underlying production volumes are not flowing to Kingfisher. The throughput of natural gas gathered and processed and crude oil gathered is derived from level of activity of the producer customers drilling and completing wells. 

Expenses

The following table summarizes our midstream operating expense, net of inter-segment eliminations (in thousands):

	Successor
	February 9, 2018 Through June 30, 2018
Plant operating expense	$	3,900
Product expense	27,603
Gathering and processing expense	5,578
Depreciation, depletion and amortization	11,905
Interest expense	1,666

As midstream revenues and expenses are reported net of inter-segment eliminations in the tables above, they should not be construed as representing gross margin for this segment on a stand-alone basis.

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

63

Product expense represents 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 includes compression, gathering, processing, & deficiency fees for offtakes along with NGL trucking fees & residue pipeline fees.

Depreciation, depletion and amortization expense 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 primarily includes non-cash charges for equity compensation, labor-related costs and insurance.

	Successor
	February 9, 2018 Through June 30, 2018
(in thousands)
Equity-based compensation expense	$	507
General and administrative expenses	5,806
Total general and administrative expenses	$	6,313

Liquidity and Capital Resources

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

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

We strive to maintain financial flexibility and may access 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 and the Kingfisher Credit Facilities 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 and the Kingfisher Credit Facilities 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. 

64

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, which will mature on February 9, 2023, is for an aggregate of $1.0 billion with an initial $350.0 million borrowing base.  In April 2018, 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 it is not in compliance with the financial covenants set forth in the Alta Mesa Credit Facility. As of June 30, 2018, Alta Mesa has no borrowings under the Alta Mesa Credit Facility and has $21.9 million of outstanding letters of credit.

As of June 30, 2018, Alta Mesa was in compliance with the financial ratios specified in the Alta Mesa Credit Facility.

Kingfisher Senior Secured Revolving Credit Facility

Prior to May 30, 2018, Kingfisher was party to a $200 million Revolving credit facility with ABN AMRO Capital USA, LLC, as administrative agent, and certain other financial institutions as lenders ("the prior credit facility"). The prior credit facility was initially entered into on August 8, 2017 and was scheduled to mature in August 2021. The principal amount of borrowings outstanding under the prior credit facility at May 30, 2018 totaled $59.5 million.

Effective May 30, 2018, Kingfisher entered into a $300.0 million amended and restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent and letter of credit issuer, and certain other financial institutions, as lenders (“the Kingfisher Credit Facility”) which replaced the prior credit facility with ABN AMRO. The Kingfisher Credit Facility matures on May 30, 2023.

As of June 30, 2018, there was $63.5 million in borrowings outstanding under the Kingfisher Credit Facility and no outstanding letters of credit. Availability under the Kingfisher Credit Facility will be redetermined each fiscal quarter as the lesser of (1) the $300.0 million commitment under the Kingfisher Credit Facility and (2) the maximum amount that, together with the aggregate amount of all then-outstanding consolidated funded indebtedness (other than indebtedness under the Kingfisher Credit Facility) would result in Kingfisher being in pro forma compliance with all applicable leverage ratios at such time.

Kingfisher was in compliance with the financial ratios specified in the Kingfisher Credit Facility at June 30, 2018.

Senior Unsecured Notes

Alta Mesa has$500 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) 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. As described further in Note 12 of the Notes to Consolidated Financial Statements, Alta Mesa may, from time to time, redeem certain amounts of the outstanding senior notes at specified amounts in relation to the principal balance of the notes redeemed.

As of June 30, 2018, Alta Mesa was in compliance with the indentures governing the senior notes.

Tax Receivable Agreement.  As described further in Note 12 of the Notes to Consolidated Financial Statements, we are party to a 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.

65

As of June 30, 2018, no exchange of SRII Common Units has occurred, which would trigger a payment under the Tax Receivable Agreement, 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.

Cash flow provided by (used in) operating activities

Cash provided by (used in) operating activities was $(76.1) million, $26.5 million and $(6.2) million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Cash-based items of net income (loss) including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense were approximately $35.3 million, $(2.4) million, and $49.2 million for the Successor Period, 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Changes in working capital and other assets and liabilities resulted in a decrease in cash of $111.4 million and $55.4 million for the Successor Period and the 2017 Predecessor Period, respectively.  Changes in working capital and other assets and liabilities during the 2018 Predecessor Period resulted in an increase in cash of approximately $28.9 million.

Cash flow provided by (used in) investing activities

Investing activities used cash of approximately $(85.4) 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 $791.8 million attributable to the Business Combination. During the Successor Period, approximately $340.6 million of cash was used to fund capital expenditures for property, plant and equipment and approximately $4.3 million was paid to our equity method investment.  Cash used for capital expenditures for property and equipment totaled approximately $38.1 million during the 2018 Predecessor Period. During the 2017 Predecessor Period, cash used for capital expenditures for property and equipment totaled approximately $151.8 million and acquisitions totaled $6.3 million.

Cash flow provided by financing activities

Cash provided by financing activities was $244.5 million in the Successor Period.  Proceeds provided by the issuance of Class A common stock related to the forward purchase contract totaled approximately $400.0 million and proceeds from the issuance of long-term debt totaled $80.0 million. This was offset by net cash used of approximately $235.5 million for repayment of the Alta Mesa Credit Facility and Kingfisher prior credit facility borrowings, payments of deferred underwriting compensation, additional deferred financing costs, and repayment of a sponsor note.  Cash provided by financing activities totaled $16.9 million and $162.8 million for the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. The 2018 Predecessor Period included proceeds from the issuance of long-term debt totaling $60.0 million, offset by repayments of long-term debt totaling $43.0 million. The 2017 Predecessor Period included proceeds from the issuance of long-term debt totaling $165.1 million and capital contributions totaling $7.9 million, partially offset by repayments of long-term debt totaling $10.0 million.

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 June 30, 2018 was a net liability of $44.1 million. A 10% increase or decrease in oil, natural gas and natural gas liquids prices with all other factors held constant would result in a decrease or increase, respectively, in the estimated fair value (generally correlated to our estimated future net cash flows from such instruments) of our commodity derivative contracts of approximately $30.0 million (decrease in value) or $33.3 million (increase in value), respectively, as of June 30, 2018.

We are subject to interest rate risk on our variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts.  A 1% increase in interest rates would increase interest expense on Kingfisher’s senior secured credit facility by $0.6 million, based on the balance outstanding at June 30, 2018. As of June 30, 2018, Alta Mesa had no outstanding balance under its senior secured credit facility.   

66

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2018 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

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 June 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

See Part I, Item 1, Note 14—  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 June 30, 2018.

67

ITEM 6. Exhibits

3.1	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).
3.2	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).
3.3	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).
3.4	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).
3.5	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).
4.3	Indenture, dated December 8, 2016, by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp,. the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Alta Mesa Holdings, LP's current report on Form 8-K filed with the SEC on December 8, 2016 (File No. 333-173751).
10.1	Employment Agreement, dated as of April 3, 2018, by and between Alta Mesa Services, LP and Craig W. Collins (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 9, 2018).
10.2	Amended and Restated Credit Agreement among Kingfisher Midstream, LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and LC issuer, and certain financial institutions, as lenders, dated May 30, 2018 (incorporated by reference to Exhibit 10.1 to the Registrants' Current Report on Form 8-K filed with the SEC on May 31, 2018).
10.3*	Form of Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan Restricted Stock Grant Agreement
10.4*	Form of Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan Officer Stock Option Grant Agreement
10.5*	Form of Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan Performance-Based Restricted Stock Unit Grant Agreement

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.

68

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

69