10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_____________________________________

FORM 10-Q

_____________________________________

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

For the quarterly period ended June 30, 2019

OR

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

For the transition period from ___ to___             

Commission file number: 001-38040

_______________________________________

ALTA MESA RESOURCES, INC.

(Exact name of registrant as specified in its charter)

_______________________________________

Delaware				81-4433840
(State or other jurisdiction of incorporation or organization)				(I.R.S. Employer Identification No.)
15021 Katy Freeway,	Suite 400,	Houston,	Texas	77094
(Address of principal executive offices)				(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per share	AMRQQ	OTC Pink Marketplace
Warrants to purchase one share of Class A Common Stock	AMRWQ	OTC Pink Marketplace

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files.)    Yes  ☒    No   ☐ 

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

Large accelerated filer	☐	Accelerated filer	☐	Non-accelerated filer	☐
Smaller reporting company	☒	Emerging growth company	☐

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

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

As of August 31, 2019, there were 182,755,573 shares of Class A Common Stock and 199,987,976 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 554,294 nonvested restricted stock awards outstanding as of August 31, 2019.

TABLE OF CONTENTS

	Page Number
Glossary	i
Cautionary Statement Regarding Forward-Looking Statements	1
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)	3
Condensed Consolidated Statements of Operations	3
Condensed Consolidated Balance Sheets	4
Condensed Consolidated Statements of Cash Flows	5
Condensed Consolidated Statements of Changes in Stockholders’ Equity	6
Condensed Consolidated Statement of Changes in Partners’ Capital	8
Notes to Condensed Consolidated Financial Statements	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3. Quantitative and Qualitative Disclosures about Market Risk	50
Item 4. Controls and Procedures	51
PART II - OTHER INFORMATION
Item 1. Legal Proceedings	51
Item 1A. Risk Factors	51
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 3. Defaults Upon Senior Securities	56
Item 4. Mine Safety Disclosures	56
Item 5. Other Information	56
Item 6. Exhibits	58
Signatures	59

Glossary of Terms

The definitions and abbreviations set forth below apply to the indicated terms throughout this filing.

Company Specific Terms -
2018 10-K -	Alta Mesa Resources, Inc. Annual Report on Form 10-K for the year ended December 31, 2018.
2018 Period -	The combined Predecessor Period and Successor Period from February 9, 2018 through June 30, 2018 and January 1, 2018 through February 8, 2018.
2019 Period -	The six months ended June 30, 2019.
2024 Notes -	$500 million aggregate principal amount of 7.875% senior unsecured notes maturing December 2024.
Alta Mesa -	Alta Mesa Holdings, LP. This entity conducts our Upstream activities.
Alta Mesa GP -	Alta Mesa Holdings GP, LLC, a majority owned subsidiary of SRII Opco, LP.
Alta Mesa RBL -	Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, as amended. This credit agreement is a reserve based loan or RBL.
Alta Mesa Services -	Alta Mesa Services, LP is a wholly owned subsidiary of Alta Mesa Holdings, LP.
AMH Debtors -	Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP.
ARM -	ARM Energy Management, LLC, a company that marketed our oil and gas production and provided services relating to our derivatives.
Bankruptcy Code -	Chapter 11 of the United States Bankruptcy Code.
Bankruptcy Court -	United States Bankruptcy Court for the Southern District of Texas.
BCE -	BCE-STACK Development LLC, a fund advised by Bayou City Management, LLC.
Business Combination -	The acquisition by Alta Mesa Resources, Inc. of controlling interests in Alta Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, and KFM Midstream, LLC.
Debtors -	Alta Mesa Resources, Inc., Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP.
High Mesa -	High Mesa Holdings, LP, a partnership formed in connection with executing the Business Combination.
HMI -	High Mesa, Inc., the predecessor owner of Alta Mesa Holdings, LP.
KFM -	Kingfisher Midstream, LLC. This entity conducts our Midstream activities.
KFM Credit Facility -	Kingfisher Midstream, LLC amended and restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent.
Midstream -	Reportable business segment representing our midstream activities.
Predecessor Period -	The period from January 1, 2018 through February 8, 2018.
PSU's -	Performance-based restricted stock units issued to employees under the Alta Mesa Resources, Inc. 2018 Long-Term Incentive Plan.
SRII Opco -	SRII Opco, LP is a subsidiary of Alta Mesa Resources, Inc. and direct owner of Alta Mesa Holdings, LP and Kingfisher Midstream, LLC.
Successor Period -	The period from February 9, 2018 through June 30, 2018, and all periods thereafter.
Upstream -	Reportable business segment representing our exploration and production activities.
Oil, Gas and Other Terms -
Basin -	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
bbl -	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to describe volumes of crude oil, condensate or natural gas liquids.
bbld -	Barrels per day.
Bcf -	One billion cubic feet of natural gas.

i

Bcfe -	One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids.
Boe -	One barrel of oil equivalent is determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one bbl of oil or natural gas liquids is commonly used in our business and represents the approximate ratio of energy content between natural gas and oil, and does not represent the price equivalency of natural gas to oil or natural gas liquids.
Boed -	One boe per day.
Btu or British Thermal Unit -	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion -	The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil.
Condensate -	A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Cryogenic -	The process of using extreme cold to separate NGLs from the natural gas stream.
DD&A -	Depreciation, depletion and amortization.
Development costs -	Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas.
Development project -	A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Differential -	An adjustment to the market reference price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole -	A well found to be incapable of producing hydrocarbons in commercial quantities.
Dth -	A dekatherm is a unit of energy used primarily to measure natural gas and is equal to 1,000,000 Btu.
Dthd -	1,000,000 Btu per day.
EBITDA -	Earnings before interest, taxes, depreciation, depletion and amortization.
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.
Enhanced recovery -	The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.
Exploitation -	A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Formation -	A layer of rock which has distinct characteristics that differs from adjacent rock.
Fracing, fracture stimulation technology, hydraulic fracturing -	A well stimulation technique to improve a well’s production by pumping a mixture of fluids into the formation to create hydraulic fractures which intersect existing natural fractures. As part of this technique, sand or other material may also be injected to keep the hydraulic fracture open, so that fluids or natural gases may more easily flow through the formation.
Held by production -	Acreage covered by mineral leases that perpetuates a company’s right to operate a property usually requiring production to be maintained at a minimum economic quantity of production.
Horizontal drilling -	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.
Lease operating expenses -	The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a well. Such expenses include labor, supplies, repairs, utilities, environmental and safety, maintenance, allocated overhead costs, severance taxes, insurance and other expenses incidental to production, but excluding lease acquisition, drilling or completion expenses.

ii

Mbbl -	One thousand barrels of crude oil, condensate, natural gas liquids, or produced water.
Mbbld -	One thousand barrels per day.
MBoe -	One thousand boe.
MBoed -	One thousand boe per day.
Mcf -	One thousand cubic feet of natural gas.
Mcfd -	One thousand cubic feet per day.
Mcfe -	One thousand cubic feet equivalent determined using the ratio of one barrel of oil, condensate or natural gas liquids to six Mcf of natural gas.
Mcfed -	Mcfe per day.
MMBbl -	One million barrels of crude oil, condensate or natural gas liquids.
MMBoe -	One million boe.
MMBtu -	One million British thermal units.
MMBtud -	One million British thermal units per day.
MMcf -	One million cubic feet of natural gas.
MMcfd -	One million cubic feet per day.
MMcfe -	Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMcfed -	MMcfe per day.
Net acres -	The total acres a working interest owner has attributable to a particular number of acres, or a specified tract.
Net production -	Portion of production owned by us after production attributable to royalty and other owners.
NGLs or natural gas liquids -	Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline.
Non-operated working interests -	The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.
NYMEX -	The New York Mercantile Exchange.
Proved properties -	Properties with proved reserves.
Proved reserves -	Quantities of oil and natural gas, which can be estimated with reasonable certainty to be economically producible from known reservoirs, and under existing economic conditions, operating methods and government regulations.
Realized price -	The cash market price less all expected quality, transportation and demand adjustments.
Recompletion -	The process of treating an existing wellbore in an attempt to establish or increase existing production.
Reserves -	Estimated remaining quantities of oil and natural gas anticipated to be economically producible from known accumulations.
Resources -	Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable.
Royalty -	An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage.
SEC -	United States Securities and Exchange Commission.
Service well -	A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, produced water disposal, water supply for injection, observation, or injection for in-situ combustion.
Spacing -	The distance between wells producing from the same reservoir. Spacing in horizontal development plays is often expressed in terms of feet, e.g., 1000 foot spacing, and is often established by regulatory agencies.

iii

STACK -	An oilfield in the eastern portion of the Anadarko Basin; STACK is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area.
Unproved properties -	Properties with no proved reserves.
Wellbore -	The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called a well or borehole.
Working interest -	The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs.
Workover -	Operations on a producing well to restore or increase production.

iv

Cautionary Statement Regarding Forward-Looking Statements

The information in this Quarterly 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, regarding our ability to continue as a going concern, the outcome or timing of our emergence from bankruptcy, strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could”, “should”, “will”, “plan”, “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” in this Quarterly Report, our Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (“Q1 2019 Form 10-Q”) and our Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 10-K”). 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:

• our ability to continue as a going concern;

• the outcome or timing of our emergence from bankruptcy, including limitations placed upon us by the process and our ability to develop, confirm and consummate a plan under Chapter 11 or an alternative restructuring or sale transaction;

• our ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;

• decisions by the KFM Board of Directors regarding making liquidity available to us during bankruptcy proceedings and any impact of those decisions on our ability to maintain compliance with the covenants in the KFM Credit Facility;

• the sufficiency of liquidity to fund our operations and capital expenditures;

• our access to capital, including constraints from the cost and availability of debt and equity financing;

• our ability to comply with, or amend the terms of, the covenants and restrictions imposed by the KFM Credit Facility;

• our ability to execute our stated business strategy;

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

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

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

• our drilling, completion and production technology;

• future oil and gas prices;

• the supply and demand for our production and our midstream services;

• the timing and amount of our future production;

• our hedging strategy and expected results;

• competition and government regulation;

• our ability to obtain permits and governmental approvals;

• expected or anticipated regulatory changes, including to the Oklahoma forced pooling system;

• pending legal and environmental matters;

• our future drilling plans, spacing plans and development pace;

• our marketing of our production;

• our leasehold or business acquisitions;

• our costs of developing our properties;

• 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 and crude oil;

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

• the costs, terms and availability of midstream services;

• our ability to collect receivables from High Mesa, Inc. and its subsidiaries; and

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

1

We caution you that any 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 to confirm and consummate a plan of reorganization; risks attendant to the bankruptcy process, including the effects thereof on our business and on the interests of various constituents, the length of time that we might be required to operate in bankruptcy and the continued availability of operating capital during the pendency of such proceedings; risks associated with third party motions in any bankruptcy case, which may interfere with the ability to confirm and consummate a plan of reorganization; potential adverse effects on our liquidity or results of operations; increased costs to execute the reorganization; effects on the market price of our common stock and on our ability to access the capital markets; commodity price volatility, global economic conditions, including supply and demand levels for oil, gas and NGLs, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, liabilities resulting from litigation or the SEC investigation, difficulties in obtaining necessary approvals and permits, 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 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, cyber-attacks, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties, and the other risks described in Risk Factors in our 2018 10-K and in the 10-Q for the period ended March 31, 2019.

Estimating reserve quantities of oil, natural gas and NGLs is complex, inexact and relies on interpretations of geologic, geophysical, engineering and production data. The extent, quality, reliability and interpretation of these data can vary. The process also requires making a number of economic assumptions, such as sales prices, the relative mix of oil, natural gas and NGLs that will be ultimately produced, drilling and operating costs, capital expenditures, the effect of government regulation, taxes and availability of funds.  Future prices received for production and costs may vary, perhaps significantly, from the assumptions used in our 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 development and related production. Accordingly, reserve estimates may differ significantly from the quantities of oil and gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report, in the 2018 10-K or the 10-Q for the period ended March 31, 2019 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.

2

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

ALTA MESA RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(in thousands, except shares outstanding and per share data)

	Successor												Predecessor
	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Revenue
Oil	$	90,668		$	75,291		$	177,031		$	115,569		$	30,972
Natural gas	12,384			7,980			30,834			13,190			4,276
Natural gas liquids	10,251			10,241			21,467			14,955			4,000
Sales of gathered production	10,439			8,924			19,999			12,797			—
Midstream revenue	6,549			6,817			13,704			10,077			—
Other	3,014			2,229			6,099			2,784			888
Operating revenue	133,305			111,482			269,134			169,372			40,136
Gain (loss) on sale of assets	—			(63		)	1,483			5,076			840
Gain (loss) on derivatives	12,412			(29,219		)	(11,365		)	(51,230		)	6,663
Total revenue	145,717			82,200			259,252			123,218			47,639
Operating expenses
Lease operating	15,114			12,679			35,058			20,996			4,408
Transportation, processing and marketing	6,837			5,396			11,440			8,755			3,725
Midstream operating	6,520			3,313			12,671			3,900			—
Cost of sales for purchased gathered production	8,720			8,902			18,415			12,711			—
Production taxes	5,117			2,606			10,600			4,021			953
Workovers	807			333			1,120			1,578			423
Exploration	3,289			8,083			5,343			9,668			7,003
Depreciation, depletion and amortization	38,009			33,934			75,908			49,613			11,670
Impairment of assets	6,500			—			6,500			—			—
General and administrative	27,172			22,456			56,690			60,208			21,234
Total operating expenses	118,085			97,702			233,745			171,450			49,416
Operating income	27,632			(15,502		)	25,507			(48,232		)	(1,777		)
Other income (expense)
Interest expense	(16,755		)	(11,779		)	(32,215		)	(17,223		)	(5,511		)
Interest income	79			824			130			1,370			172
Equity in earnings of unconsolidated subsidiaries	643			—			742			—			—
Total other income (expense), net	(16,033		)	(10,955		)	(31,343		)	(15,853		)	(5,339		)
Income (loss) from continuing operations before income taxes	11,599			(26,457		)	(5,836		)	(64,085		)	(7,116		)
Income tax provision (benefit)	—			(3,791		)	—			(7,665		)	—
Income (loss) from continuing operations	11,599			(22,666		)	(5,836		)	(56,420		)	(7,116		)
Loss from discontinued operations, net of tax	—			—			—			—			(7,746		)
Net income (loss)	11,599			(22,666		)	(5,836		)	(56,420		)	$	(14,862	)
Net income (loss) attributable to noncontrolling interests	9,354			(16,066		)	326			(36,490		)
Net income (loss) attributable to Alta Mesa Resources, Inc. stockholders	$	2,245		$	(6,600	)	$	(6,162	)	$	(19,930	)
Attributable to Alta Mesa Resources, Inc. stockholders:
Income (loss) per share - basic and diluted	$	0.01		$	(0.04	)	$	(0.03	)	$	(0.12	)
Weighted average shares outstanding - basic	180,742,049			173,345,982			180,505,318			171,908,486
Weighted average shares outstanding - diluted	180,742,049			207,965,929			180,505,318			208,112,707

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

3

ALTA MESA RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands, except shares and per share data)

໿

	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	91,111	$	26,854
Restricted cash	890		1,001
Accounts receivable, net	73,776		87,842
Other receivables	3,635		6,331
Related party receivables, net	2,310		3,341
Prepaid expenses and other	5,575		1,125
Derivatives	4,727		16,423
Total current assets	182,024		142,917
Property and equipment, net
Oil and gas properties, successful efforts method	784,079		763,337
Other property and equipment	470,547		444,269
Total property and equipment, net	1,254,626		1,207,606
Other assets
Operating lease right-of-use assets, net	8,180		—
Equity method investment	1,842		1,100
Deferred financing costs, net	2,836		3,195
Deposits and other long-term assets	41		65
Derivatives	2,508		2,947
Total other assets	15,407		7,307
Total assets	$	1,452,057	$	1,357,830

	June 30, 2019			December 31, 2018
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt	$	1,089,162		$	690,123
Accounts payable and accrued liabilities	109,901			247,439
Advances from non-operators	1,755			5,193
Advances from related party	4,003			9,839
Asset retirement obligations, current portion	44			2,079
Current operating lease liability	1,018			—
Derivatives	840			1,710
Total current liabilities	1,206,723			956,383
Long-term liabilities
Asset retirement obligations, net of current portion	12,442			9,473
Long-term debt, net	—			174,000
Other long-term liabilities	5,096			1,667
Operating lease liabilities, net of current portion	13,962			—
Derivatives	189			180
Total long-term liabilities	31,689			185,320
Total liabilities	1,238,412			1,141,703
Preferred Stock, $0.0001 par value
Class A: 1,000,000 shares authorized; 3 shares issued; 2 outstanding	—			—
Class B: 1,000,000 shares authorized; 1 share issued and outstanding	—			—
Common stock, $0.0001 par value
Class A: 1,200,000,000 shares authorized; 182,636,433 shares issued and outstanding (180,072,227 issued and outstanding at December 31, 2018)	18			18
Class C: 280,000,000 shares authorized; 199,987,976 and 202,169,576 issued and outstanding at June 30, 2019 and December 31, 2018	20			20
Additional paid in capital	1,509,716			1,503,382
Accumulated deficit	(1,538,975		)	(1,532,813		)
Total stockholders’ equity	(29,221		)	(29,393		)
Noncontrolling interests	242,866			245,520
Total equity	213,645			216,127
Total liabilities and stockholders’ equity	$	1,452,057		$	1,357,830

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

4

ALTA MESA RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)

	Successor						Predecessor
	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Cash flows from operating activities:
Net loss	$	(5,836	)	$	(56,420	)	$	(14,862	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	75,908			49,613			12,554
Non-cash lease expense	1,675			—			—
Provision for uncollectible receivables	1,177			—			—
Impairment of assets	6,500			—			5,560
Amortization of deferred financing costs	368			152			171
Amortization of debt premium	(2,462		)	(2,051		)	—
Equity-based compensation expense	3,519			7,729			—
Non-cash exploration expense	388			7,288			4,575
(Gain) loss on derivatives	11,365			51,230			(6,663		)
Cash settlements of derivatives	909			(18,334		)	(2,296		)
Premium paid on derivatives	(1,000		)	—			—
Interest converted into debt	—			—			103
Interest added to notes receivable from affiliate	—			(417		)	(85		)
Deferred tax provision (benefit)	—			(7,665		)	—
Loss on sale of fixed assets	114			63			1,923
Equity in earnings of unconsolidated subsidiaries	(742		)	—			—
Impact on cash from changes in:
Accounts receivable	13,744			(9,143		)	(21,184		)
Other receivables	2,696			996			(662		)
Related party receivables	179			(6,260		)	(117		)
Prepaid expenses and other assets	(4,426		)	8,116			(591		)
Advances from related party	(154		)	(10,371		)	24,116
Settlement of asset retirement obligations	(5,835		)	(806		)	(63		)
Accounts payable, accrued liabilities and other liabilities	(12,123		)	(78,542		)	23,857
Operating lease obligations	(1,376		)	—			—
Cash from operating activities	84,588			(64,822		)	26,336
Cash flows from investing activities:
Capital expenditures	(247,942		)	(340,631		)	(36,695		)
Acquisitions, net of cash acquired	—			(791,819		)	(1,218		)
Proceeds withdrawn from trust account	—			1,042,742			—
Investment in equity affiliate and other, net	—			(6,945		)	—
Cash from investing activities	(247,942		)	(96,653		)	(37,913		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	227,500			80,000			60,000
Repayments of long-term debt	—			(193,565		)	(43,000		)
Deferred financing costs paid	—			(3,670		)	—
Capital distributions	—			—			(68		)
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		)	—
Cash from financing activities	227,500			244,507			16,932
Net increase in cash, cash equivalents and restricted cash	64,146			83,032			5,355
Cash, cash equivalents and restricted cash, beginning of period	27,855			388			4,990
Cash, cash equivalents and restricted cash, end of period	$	92,001		$	83,420		$	10,345

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

5

ALTA MESA RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Successor)

(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
Equity based compensation expense	—		—		—		—			—		—			3,466			—			3,466			—			3,466
Net loss	—		—		—		—			—		—			—			(13,330		)	(13,330		)	(20,424		)	(33,754		)
Balance at March 31, 2018	169,372		17		—		—			213,402		21			1,402,888			(21,444		)	1,381,482			2,038,211			3,419,693
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 expense	—		—		—		—			—		—			4,263			—			4,263			—			4,263
Net loss	—		—		—		—			—		—			—			(6,600		)	(6,600		)	(16,066		)	(22,666		)
Balance at June 30, 2018	179,059		$	18	—		$	—		204,922		$	20		$	1,498,023		$	(28,044	)	$	1,470,017		$	1,939,594		$	3,409,611

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

6

ALTA MESA RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Successor)

(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 January 1, 2019	180,072	$	18	—	$	—	202,170		$	20	$	1,503,382		$	(1,532,813	)	$	(29,393	)	$	245,520		$	216,127
Restricted stock awards vested, net of taxes	338	—		—	—		—		—		67			—			67			(209		)	(142		)
Equity-based compensation expense	—	—		—	—		—		—		2,679			—			2,679			—			2,679
Net loss	—	—		—	—		—		—		—			(8,407		)	(8,407		)	(9,028		)	(17,435		)
Balance at March 31, 2019	180,410	18		—	—		202,170		20		1,506,128			(1,541,220		)	(35,054		)	236,283			201,229
Conversion of commons shares from Class C shares to Class A	2,182	—		—	—		(2,182	)	—		2,756			—			2,756			(2,756		)	—
Restricted stock awards vested, net of taxes	44	—		—	—		—		—		(8		)	—			(8		)	(15		)	(23		)
Equity-based compensation	—	—		—	—		—		—		840			—			840			—			840
Net income	—	—		—	—		—		—		—			2,245			2,245			9,354			11,599
Balance at June 30, 2019	182,636	$	18	—	$	—	199,988		$	20	$	1,509,716		$	(1,538,975	)	$	(29,221	)	$	242,866		$	213,645

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

7

ALTA MESA RESOURCES, INC.

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

(in thousands)

໿

	Predecessor
Balance, December 31, 2017	$	154,445
Distribution of non-STACK oil and gas assets, net of associated liabilities	43,482
Net loss	(14,862		)
Balance, February 8, 2018	$	183,065

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

8

ALTA MESA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Alta Mesa Resources, Inc., together with its consolidated subsidiaries (“we” or “the Company”), is an independent exploration and production company focused on the acquisition, development, exploration and production of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. We also operate in the Midstream segment through Kingfisher Midstream, LLC (“KFM”). KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The KFM midstream assets are integral to our Upstream operations, which we conduct in the same region, and they are 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, exchange, acquisition, purchase, reorganization or similar business combination involving it and one or more businesses. On February 9, 2018 we acquired interests in Alta Mesa, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and KFM through a newly formed subsidiary, SRII Opco, LP (“SRII Opco”) in a transaction referred to as the “Business Combination”, and changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.” As a result of our failure to comply with the continued listing requirements of the NASDAQ Capital Market (“NASDAQ”), trading in our Class A Common Stock and public warrants was suspended on September 24, 2019, and they are now traded over the counter under the trading symbols “AMRQQ” and “AMRWQ,” respectively. 

In connection with the closing of the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and associated liabilities to its prior owner, High Mesa Holdings, LP (“High Mesa”). The non-STACK assets and liabilities are reflected as discontinued operations in the Predecessor portion of our financial statements.

All intercompany transactions and accounts have been eliminated. These interim condensed consolidated financial statements are unaudited, but we believe these statements reflect all adjustments necessary for a fair presentation of the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These financial statements and disclosures have been prepared in accordance with the SEC’s rules for interim financial statements and do not include all the information and disclosures required by generally accepted accounting principles (“GAAP”) for complete financial statements. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three and six months ended June 30, 2019 are not necessarily indicative of the results to be expected for the full year. We have no items of other comprehensive income during any period presented. Certain prior period amounts have been reclassified to conform to the current period presentation. 

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern

We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration a number of factors that were previously disclosed in our 2018 10-K. Most significantly, we have seen significant reductions to our borrowing base under the Alta Mesa RBL in 2019. On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced by $30 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200.0 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $63.0 million.

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If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Company, Alta Mesa, Alta Mesa GP, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services and Oklahoma Energy Acquisitions, LP (the “AMH Debtors” and together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC are not part of the Chapter 11 cases at this time.

On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors were authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral for an initial four week period on the terms and conditions agreed by the AMH Debtors and the lenders under the Alta Mesa RBL and set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain milestones. The ability to have continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.

The Debtors have begun a marketing process to sell their assets, which may also include KFM’s midstream assets. Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions LP, an Alta Mesa subsidiary, and non-Debtors KFM and its subsidiaries can be rejected by the Debtors.

We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the approved cash collateral agreement, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.3 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.

Recently Issued Accounting Standards Applicable to Us

Adopted

Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease, and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019.

Not Yet Adopted

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 we use today. With respect to our trade and notes receivables and certain other financial instruments,

10

we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us no earlier than January 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no earlier than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us no earlier than January 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

NOTE 3 — ADOPTION OF ASU NO. 2016-02, LEASES

ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on our balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method as of January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities totaling $15.4 million each. There was no adjustment to beginning retained earnings.

We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not currently sublease any of our ROU assets, although we may sublease our unused office lease space in the future.

Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred.

Upon adoption, we selected the following practical expedients:

11

Practical expedient package	We did not reassess whether any expired or existing contracts are, or contain, leases.
	We did not reassess the lease classification of any expired or existing leases.
	We did not reassess initial direct costs of any expired or existing leases.
Hindsight practical expedient	We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.
Easement expedient	We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.
Combining lease and non-lease components expedient	We elected to account for lease and non-lease components as a single component.
Short-term lease expedient	We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.

As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At June 30, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.1 years and the weighted-average discount rate applied was 14.3%.

Lease Costs

(in thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	$	828	$	1,675
Variable lease cost	478		849
Short-term lease cost	1,071		3,686
Total lease cost	$	2,377	$	6,210
Reported in:
Lease operating expense	$	1,029	$	3,675
General and administrative expense	1,348		2,535
Total lease cost	$	2,377	$	6,210

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Operating Lease Liability Maturities as of June 30, 2019

Fiscal year	(in thousands)
Remainder of 2019	$	1,528
2020	3,081
2021	3,048
2022	3,108
2023	2,718
Thereafter	12,647
Total lease payments	26,130
Less: imputed interest	(11,150		)
Present value of operating lease liabilities	$	14,980
Current portion of operating lease liabilities	$	1,018
Operating lease liabilities, net of current portion	13,962
Present value of operating lease liabilities	$	14,980

As described further in our 2018 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter.

Right-of-Use Asset Impairment

During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We sought to sublease the unused office space within three buildings but we were unable to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.

We also expect to attempt to reject certain of the leases pursuant to our Bankruptcy filing which could decrease our lease liability if we are successful with the rejection.

NOTE 4 - EARNINGS (LOSS) PER SHARE

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:

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	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018
	(in thousands, except shares and per share data)
Net income (loss) attributable to AMR Class A common stockholders	$	2,245	$	(6,600	)	$	(6,162	)	$	(19,930	)
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 income (loss) attributable to AMR Class A common stockholders after assumed redemption	$	2,245	$	(8,757	)	$	(6,162	)	$	(24,844	)
Weighted average Class A common shares outstanding (Basic)	180,742,049		173,345,982			180,505,318			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)	180,742,049		207,965,929			180,505,318			208,112,707
Income (loss) per common share attributable to AMR common stockholders:
Basic	$	0.01	$	(0.04	)	$	(0.03	)	$	(0.12	)
Diluted	$	0.01	$	(0.04	)	$	(0.03	)	$	(0.12	)

NOTE 5 — SUPPLEMENTAL CASH FLOW INFORMATION

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	29,513		$	22,996		$	1,145
Cash paid for income taxes, net of refunds	706			1,573			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	634			877			—
Increase (decrease) in accruals or payables for capital expenditures	(127,875		)	(25,798		)	4,896
Increase in withholding tax accruals for share-based compensation	165			—			—
Distribution of non-STACK assets, net of liabilities	—			—			43,482
Equity issued in Business Combination	—			2,067,393			—
Release of common stock from possible redemption	—			966,384			—
Tax effect of redemption of noncontrolling interests in SRII Opco for Class A common shares and other	—			(437)			—

We aggregate cash, cash equivalents and restricted cash in the statements of cash flows.  

໿

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NOTE 6 — RECEIVABLES

Accounts Receivable

(in thousands)	June 30, 2019			December 31, 2018
Production and processing sales and fees	$	41,844		$	51,004
Joint interest billings	20,836			18,147
Pooling interest (1)	11,506			18,786
Allowance for doubtful accounts	(410		)	(95		)
Total accounts receivable, net	$	73,776		$	87,842

_________________

(1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells.  The pooling interest listed above represents unbilled costs for wells where the option remains pending.  Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties.

Related Party Receivables

(in thousands)	June 30, 2019			December 31, 2018
Related party receivables	$	12,197		$	12,375
Allowance for doubtful accounts	(9,887		)	(9,034		)
Related party receivables, net	2,310			3,341
Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Related party receivables, net	$	2,310		$	3,341

Management Services Agreement with High Mesa

(in thousands)	June 30, 2019
High Mesa related party receivable at December 31, 2018	$	10,066
Additions	894
Payments	(1,073		)
High Mesa related party receivable at June 30, 2019	9,887
Allowance for uncollectibility(1)	(9,887		)
Balance at June 30, 2019, net	$	—

_________________

(1) $9.0 million of the allowance was recognized during the 2018 Successor Period.

Our management services agreement with HMI (“the High Mesa Agreement”) was terminated effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the services to a successor service provider. During the transition period, HMI agreed to pay us (i) for all services performed, (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 reimbursable pursuant to the High Mesa Agreement. As of June 30, 2019, and December 31, 2018, approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9

15

million and $9.0 million as of June 30, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation relating to the non-STACK assets. As of June 30, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.

Promissory notes receivable

High Mesa Services, LLC (“HMS”), a subsidiary of HMI, defaulted under the terms of a promissory note with us when it did not pay us on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of June 30, 2019 and December 31, 2018.

In addition, we have a note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount.  HMI disputes its obligations under the note. As of June 30, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.

We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes. As a result of the potential conflict of interest from certain of AMR’s directors who are also controlling holders of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter.

NOTE 7 — PROPERTY AND EQUIPMENT

(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	76,665		$	74,217
Proved oil and gas properties	2,196,605			2,110,346
Accumulated depletion and impairment	(1,489,191		)	(1,421,226		)
Proved oil and gas properties, net	707,414			689,120
Total oil and gas properties, net	784,079			763,337
Other property and equipment
Land	5,600			5,600
Fresh water wells	27,373			27,366
Produced water disposal system	106,467			104,498
Gas processing plant and gathering lines	412,193			380,470
Office furniture, equipment and vehicles	3,755			3,703
Accumulated depreciation and impairment	(84,841		)	(77,368		)
Other property and equipment, net	470,547			444,269
Total property and equipment, net	$	1,254,626		$	1,207,606

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Depletion and Depreciation Expense

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	33,923	$	26,086	$	67,965	$	36,859	$	11,021
Midstream tangible asset depreciation	3,504		2,010		6,724		3,132		—
Other property and equipment depreciation	341		423		749		586		609
Total depletion and depreciation	$	37,768	$	28,519	$	75,438	$	40,577	$	11,630

Impairment

During the three months ended June 30, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment of our long-lived assets. Therefore, we did not conduct further analysis on the recognition of additional impairment.

17

NOTE 8 — DISCONTINUED OPERATIONS (Predecessor)

The results of operations of the non-STACK oil and gas assets and related liabilities distributed to High Mesa immediately prior to the Business Combination and presented as discontinued operations during the Predecessor Period were as follows:

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Revenue
Oil	$	1,617
Natural gas	1,023
Natural gas liquids	236
Other	16
Operating revenue	2,892
Loss on sale of assets	(1,923		)
Total revenue	969
Operating expenses
Lease operating	1,770
Transportation and marketing	83
Production taxes	167
Workovers	127
Depreciation, depletion and amortization	884
Impairment of assets	5,560
General and administrative	21
Total operating expenses	8,612
Other expense
Interest expense	(103		)
Loss from discontinued operations, net of tax	$	(7,746	)

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Total operating cash flows of discontinued operations	$	2,974
Total investing cash flows of discontinued operations	(601		)

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NOTE 9 — DERIVATIVES  

The following summarizes the fair value and classification of our derivatives:

	June 30, 2019
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)
Derivatives, current assets	$	13,855	$	(9,128	)	$	4,727
Derivatives, long-term assets	11,977		(9,469		)	2,508
Total	$	25,832	$	(18,597	)	$	7,235

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)
Derivatives, current liabilities	$	9,968	$	(9,128	)	$	840
Derivatives, long-term liabilities	9,658		(9,469		)	189
Total	$	19,626	$	(18,597	)	$	1,029

	December 31, 2018
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)
Derivatives, current assets	$	22,512	$	(6,089	)	$	16,423
Derivatives, long-term assets	7,910		(4,963		)	2,947
Total	$	30,422	$	(11,052	)	$	19,370

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)
Derivatives, current liabilities	$	7,799	$	(6,089	)	$	1,710
Derivatives, long-term liabilities	5,143		(4,963		)	180
Total	$	12,942	$	(11,052	)	$	1,890

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

	Successor											Predecessor
Derivatives not designated as hedges	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives -
Oil	$	5,134	$	(28,712	)	$	(16,535	)	$	(50,656	)	$	4,796
Natural gas	7,278		(507		)	5,170			(574		)	1,867
Total gain (loss) on derivatives	$	12,412	$	(29,219	)	$	(11,365	)	$	(51,230	)	$	6,663

Other receivables at June 30, 2019 and December 31, 2018 include $1.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the next month.

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We had the following call and put derivatives at June 30, 2019:

OIL

	Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	92,000	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	1,361,600	66.31		75.20		56.50
Long Put Options	1,453,600	53.80		62.00		50.00
Short Put Options	1,453,600	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	1,017,600	63.95		73.80		59.55
Long Put Options	1,566,600	56.81		62.50		50.00
Short Put Options	1,566,600	42.81		50.00		37.50
2021
Collar Contracts
Short Call Options	279,750	63.51		63.75		63.35
Long Put Options	659,850	46.94		55.00		41.00
Short Put Options	279,750	43.00		43.00		43.00

NATURAL GAS

	Volume	Weighted			Range
Settlement Period and Type of Contract	in MMBtu	Average			High			Low
2019
Price Swap Contracts	7,980,000	$	2.67		$	2.72		$	2.64
Basis Swap Contracts	9,680,000	(0.72		)	(0.49		)	(0.93		)
Collar Contracts
Short Call Options	1,525,000	3.19			3.20			3.17
Long Put Options	1,525,000	2.70			2.70			2.70
Short Put Options	1,525,000	2.20			2.20			2.20
2020
Price Swap Contracts	1,284,000	2.54			2.54			2.54
Basis Swap Contracts	910,000	(0.49		)	(0.49		)	(0.50		)
Collar Contracts
Short Call Options	3,874,500	3.19			3.69			2.77
Long Put Options	10,749,500	2.59			3.00			2.50
Short Put Options	9,696,000	2.10			2.50			2.00
2021
Collar Contracts
Short Call Options	540,000	3.25			3.25			3.25
Long Put Options	2,790,000	2.62			2.65			2.50
Short Put Options	2,250,000	2.15			2.15			2.15

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We had the following basis swaps at June 30, 2019:

Total Gas Volumes in MMBtu(1) over Remaining Term	Reference Price 1 (1)	Reference Price 2 (1)	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
7,990,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jul '19	—	Dec '19	(0.70		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
1,230,000	San Juan	NYMEX Henry Hub	Jul '19	—	Oct '19	(0.81		)

________________

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

During September 2019, we closed out all open derivative positions resulting in net proceeds of approximately $4 million, which we applied against our outstanding borrowings under the Alta Mesa RBL.

NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 

໿

(in thousands)	June 30, 2019		December 31, 2018
Accounts payable	$	12,526	$	20,422
Accruals for capital expenditures	22,669		139,904
Revenue and royalties payable	41,304		50,241
Accruals for operating expenses	14,853		21,830
Accrued interest	6,922		2,477
Derivative settlements	743		109
Other	10,884		12,456
Total accrued liabilities	97,375		227,017
Accounts payable and accrued liabilities	$	109,901	$	247,439

NOTE 11 — ASSET RETIREMENT OBLIGATIONS 

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Balance, beginning of period	$	11,552		$	—		$	10,469
Liabilities assumed in Business Combination	—			5,998			—
Liabilities incurred	634			877			—
Liabilities settled	(162		)	(806		)	(63		)
Liabilities transferred in sale of properties	—			(20		)	—
Revisions to estimates	(8		)	665			63
Accretion expense	470			263			40
Balance, end of period	12,486			6,977			10,509
Less: current portion	44			538			33
Long-term portion	$	12,442		$	6,439		$	10,476

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NOTE 12 — DEBT

໿

(in thousands)	June 30, 2019		December 31, 2018
Alta Mesa RBL	$	344,500	$	161,000
KFM Credit Facility	218,000		174,000
2024 Notes	500,000		500,000
Unamortized premium on 2024 Notes	26,662		29,123
Total debt, net	1,089,162		864,123
Less: Current portion	1,089,162		690,123
Long-term debt, net	$	—	$	174,000

Alta Mesa RBL

In April 2019, our borrowing base under the Alta Mesa RBL was reduced from $400.0 million to $370.0 million, leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200.0 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. As indicated in our discussion of going concern, we and the AMH Debtors filed for bankruptcy protection prior to making these payments.

The Alta Mesa RBL has two covenants that are tested quarterly:

• a ratio of Alta Mesa’s current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and

• a ratio of Alta Mesa’s consolidated debt to its consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0. 

Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the Alta Mesa RBL that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the lenders under the Alta Mesa RBL are stayed from taking any action against the AMH Debtors as a result of an event of default.

KFM Credit Facility

The KFM Credit Facility, as amended, provides for an aggregate committed borrowing capacity of $300.0 million.

There are two maintenance covenants under the KFM Credit Facility that are tested quarterly:

• a ratio of KFM’s total debt to its consolidated adjusted EBITDA of not greater than 4.5 to 1.0, (which increases to 4.75 after KFM exceeds consolidated EBITDA of $75.0 million) for any 4 quarter period; and

• a minimum interest coverage ratio of KFM’s adjusted EBITDA to interest expense of not less than 2.5 to 1.0.

The KFM Credit Facility also limits KFM to holding no more than $15.0 million in cash and limits its ability to amend affiliate contracts. Our bankruptcy filing did not constitute an event of default under the KFM Credit Facility.

At August 31, 2019, remaining borrowing capacity under the KFM Credit Facility totaled $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.

22

2024 Notes

We have estimated the fair value of the 2024 Notes to be $193.8 million at June 30, 2019, which is based on their most recent trading values, which is a Level 1 determination.

Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default including acceleration.

Scheduled Maturities of Debt

Fiscal year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	562,500
Thereafter	500,000
	$	1,062,500

Based upon our going concern conclusions and the default associated with Alta Mesa’s bankruptcy filing, we believe that our indebtedness under the Alta Mesa RBL and our 2024 Notes should be reported as current liabilities despite their scheduled maturities shown above. We have reported our Alta Mesa RBL debt and our 2024 Notes as current at June 30, 2019. In addition, based on the factors described under “KFM Credit Facility” above, we have also reported all of our Midstream debt as current at June 30, 2019 despite the scheduled maturities shown above.

NOTE 13 — COMMITMENTS AND CONTINGENCIES 

There have been no material developments during the first six months of 2019 in relation to our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including the matters discussed in our 2018 10-K.

NOTE 14 — SIGNIFICANT CONCENTRATIONS 

During most of the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales were generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality.  In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM.  As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.

ARM has also provided us with strategic advice, execution and reporting services with respect to our derivatives activities.

23

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	25,833	$	90,206	$	119,224	$	131,422	$	28,757
Marketing and management fees paid to ARM	$	519	$	—	$	1,216	$	—	$	—
Fees paid to ARM for services relating to our derivatives	218		209		411		283		66
Total fees paid to ARM	$	737	$	209	$	1,627	$	283	$	66

Receivables from ARM for sales on our behalf were $6.6 million and $43.8 million as of June 30, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

We believe that the loss of any of our customers, or of our marketing agent ARM, would not have a material adverse effect on us because alternative purchasers and marketing firms are readily available. 

NOTE 15 — EQUITY-BASED COMPENSATION (Successor)

Stock compensation expense recognized was as follows:

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Stock options	$	660	$	1,722	$	1,899	$	2,787	$	—
Restricted stock awards	35		1,260		1,468		2,493		—
Performance-based restricted stock units	145		1,281		152		2,449		—
Total compensation expense	$	840	$	4,263	$	3,519	$	7,729	$	—

Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year is based on achievement of annual company-specific performance goals and obligations applicable to each year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest range from 0% to 200% of the target growth applicable to each vesting period. The performance goals set for the 2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted.

The performance targets for the 2019 tranche of performance-based restricted stock units were established in March 2019 and 572,990 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment.

No performance targets have yet been established for the 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established and probability of attainment can be measured.

NOTE 16 — RELATED PARTY TRANSACTIONS 

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $83,000 and $28,000 for the period February 9,

24

2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses.

David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860, $1,017,711 and $28,874 during the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019.

David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $117,962, $297,134, $67,322, for the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense.

Bayou City Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of our working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs related to such joint well.  Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time.  During the Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of June 30, 2019, 61 joint wells have been drilled or spudded. At June 30, 2019 and December 31, 2018, $4.0 million and $9.8 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our condensed consolidated balance sheets. At June 30, 2019, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves.

25

NOTE 17 — BUSINESS SEGMENT INFORMATION

	Three Months Ended June 30, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	90,668		$	—		$	—		$	90,668
Natural gas	12,384			—			—			12,384
Natural gas liquids	10,251			—			—			10,251
Sales of gathered production	—			10,439			—			10,439
Midstream revenue	—			22,112			(15,563		)	6,549
Segment sales revenue	113,303			32,551			(15,563		)	130,291
Other revenue	330			6,693			(4,009		)	3,014
Operating revenue	113,633			39,244			(19,572		)	133,305
Gain on sale of assets	—			—			—			—
Gain (loss) on derivatives	12,412			—			—			12,412
Total revenue	126,045			39,244			(19,572		)	145,717
Operating expenses
Lease operating	19,123			—			(4,009		)	15,114
Transportation, processing and marketing	19,614			2,786			(15,563		)	6,837
Midstream operating	—			6,520			—			6,520
Cost of sales for purchased gathered production	—			8,720			—			8,720
Production taxes	5,117			—			—			5,117
Workovers	412			395			—			807
Exploration	3,289			—			—			3,289
Depreciation, depletion and amortization	34,504			3,505			—			38,009
Impairment of assets	6,500			—			—			6,500
General and administrative	15,723			5,324			6,125			27,172
Total operating expenses	104,282			27,250			(13,447		)	118,085
Operating income	21,763			11,994			(6,125		)	27,632
Other income (expense)
Interest expense	(14,071		)	(2,684		)	—			(16,755		)
Interest income	54			6			19			79
Equity in earnings of unconsolidated subsidiaries	—			643			—			643
Total other income (expense)	(14,017		)	(2,035		)	19			(16,033		)
Income (loss) from continuing operations before income taxes	7,746			9,959			(6,106		)	11,599
Interest expense	14,071			2,684			—			16,755
Depreciation, depletion and amortization	34,504			3,505			—			38,009
Gain on unrealized hedges	(11,868		)	—			—			(11,868		)
Impairment of assets	6,500			—			—			6,500
Equity-based compensation	1,396			(556		)	—			840
Exploration	3,289			—			—			3,289
Severance costs	609			88			—			697
Strategic costs	4,061			—			—			4,061
Adjusted EBITDAX	$	60,308		$	15,680		$	(6,106	)	$	69,882
Equity method investment at period end	$	—		$	1,842		$	—		$	1,842
Capital expenditures	47,061			39,533			—			86,594

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	Three Months Ended June 30, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	75,291		$	—		$	—		$	75,291
Natural gas	7,980			—			—			7,980
Natural gas liquids	10,241			—			—			10,241
Sales of gathered production	—			21,024			(12,100		)	8,924
Midstream revenue	—			15,849			(9,032		)	6,817
Segment sales revenue	93,512			36,873			(21,132		)	109,253
Other revenue	2,229			—			—			2,229
Operating revenue	95,741			36,873			(21,132		)	111,482
Gain on sale of assets	(63		)	—			—			(63		)
Gain (loss) on derivatives	(29,219		)	—			—			(29,219		)
Total revenue	66,459			36,873			(21,132		)	82,200
Operating expenses
Lease operating	12,679			—			—			12,679
Transportation, processing and marketing	11,205			3,223			(9,032		)	5,396
Midstream operating	—			3,313			—			3,313
Cost of sales for purchased gathered production	—			21,002			(12,100		)	8,902
Production taxes	2,606			—			—			2,606
Workovers	333			—			—			333
Exploration	8,083			—			—			8,083
Depreciation, depletion and amortization	26,670			7,264			—			33,934
Impairment of assets	—			—			—			—
General and administrative	17,811			4,140			505			22,456
Total operating expenses	79,387			38,942			(20,627		)	97,702
Operating income	(12,928		)	(2,069		)	(505		)	(15,502		)
Other income (expense)
Interest expense	(10,361		)	(1,418		)	—			(11,779		)
Interest income	820			—			4			824
Total other income (expense)	(9,541		)	(1,418		)	4			(10,955		)
Income (loss) from continuing operations before income taxes	(22,469		)	(3,487		)	(501		)	(26,457		)
Interest expense	10,361			1,418			—			11,779
Depreciation, depletion and amortization	26,670			7,264			—			33,934
Loss on unrealized hedges	14,860			—			—			14,860
Equity-based compensation	3,621			465			177			4,263
Exploration	8,083			—			—			8,083
Business Combination	443			—			—			443
Adjusted EBITDAX	$	41,569		$	5,660		$	(324	)	$	46,905
Capital expenditures	$	189,732		$	17,844		$	—		$	207,576

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	Six Months Ended June 30, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	177,031		$	—		$	—		$	177,031
Natural gas	30,834			—			—			30,834
Natural gas liquids	21,467			—			—			21,467
Sales of gathered production	—			19,999			—			19,999
Midstream revenue	—			44,488			(30,784		)	13,704
Segment sales revenue	229,332			64,487			(30,784		)	263,035
Other revenue	898			14,374			(9,173		)	6,099
Operating revenue	230,230			78,861			(39,957		)	269,134
Gain on sale of assets	1,483			—			—			1,483
Gain (loss) on derivatives	(11,365		)	—			—			(11,365		)
Total revenue	220,348			78,861			(39,957		)	259,252
Operating expenses
Lease operating	44,231			—			(9,173		)	35,058
Transportation, processing and marketing	37,375			4,849			(30,784		)	11,440
Midstream operating	—			12,671			—			12,671
Cost of sales for purchased gathered production	—			18,415			—			18,415
Production taxes	10,600			—			—			10,600
Workovers	609			511			—			1,120
Exploration	5,343			—			—			5,343
Depreciation, depletion and amortization	69,179			6,729			—			75,908
Impairment of assets	6,500			—			—			6,500
General and administrative	36,670			13,387			6,633			56,690
Total operating expenses	210,507			56,562			(33,324		)	233,745
Operating income	9,841			22,299			(6,633		)	25,507
Other income (expense)
Interest expense	(26,901		)	(5,314		)	—			(32,215		)
Interest income	81			10			39			130
Equity in earnings of unconsolidated subsidiaries	—			742			—			742
Total other income (expense)	(26,820		)	(4,562		)	39			(31,343		)
Income (loss) from continuing operations before income taxes	(16,979		)	17,737			(6,594		)	(5,836		)
Interest expense	26,901			5,314			—			32,215
Depreciation, depletion and amortization	69,179			6,729			—			75,908
Loss on unrealized hedges	12,274			—			—			12,274
Impairment of assets	6,500			—			—			6,500
Equity-based compensation	3,057			462			—			3,519
Exploration	5,343			—			—			5,343
Severance costs	4,584			1,984			—			6,568
Strategic costs	4,061			—			—			4,061
Business Combination	10			—			—			10
Adjusted EBITDAX	$	114,930		$	32,226		$	(6,594	)	$	140,562
Equity method investment at period end	$	—		$	1,842		$	—		$	1,842
Capital expenditures	180,138			67,804			—			247,942
Total assets at period end	999,744			458,882			(6,569		)	1,452,057

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	February 9, 2018 Through June 30, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	115,569		$	—		$	—		$	115,569
Natural gas	13,190			—			—			13,190
Natural gas liquids	14,955			—			—			14,955
Sales of gathered production	—			31,634			(18,837		)	12,797
Midstream revenue	—			23,671			(13,594		)	10,077
Segment sales revenue	143,714			55,305			(32,431		)	166,588
Other revenue	2,784			—			—			2,784
Operating revenue	146,498			55,305			(32,431		)	169,372
Gain (loss) on sale of assets	5,076			—			—			5,076
Gain (loss) on derivatives	(51,230		)	—			—			(51,230		)
Total revenue	100,344			55,305			(32,431		)	123,218
Operating expenses
Lease operating	20,996			—			—			20,996
Transportation, processing and marketing	16,788			5,561			(13,594		)	8,755
Midstream operating	—			3,900			—			3,900
Cost of sales for purchased gathered production	—			31,548			(18,837		)	12,711
Production taxes	4,021			—			—			4,021
Workovers	1,578			—			—			1,578
Exploration	9,668			—			—			9,668
Depreciation, depletion and amortization	37,708			11,905			—			49,613
Impairment of assets	—			—			—			—
General and administrative	52,465			6,313			1,430			60,208
Total operating expenses	143,224			59,227			(31,001		)	171,450
Operating income	(42,880		)	(3,922		)	(1,430		)	(48,232		)
Other income (expense)
Interest expense	(15,557		)	(1,666		)	—			(17,223		)
Interest income	1,366			—			4			1,370
Total other income (expense)	(14,191		)	(1,666		)	4			(15,853		)
Income (loss) from continuing operations before income taxes	(57,071		)	(5,588		)	(1,426		)	(64,085		)
Interest expense	15,557			1,666			—			17,223
Depreciation, depletion and amortization	37,708			11,905			—			49,613
Loss on unrealized hedges	32,896			—			—			32,896
Loss on sale of fixed assets	63			—			—			63
Equity-based compensation	6,389			507			833			7,729
Exploration	9,668			—			—			9,668
Business Combination	23,717			—			—			23,717
Adjusted EBITDAX	$	68,927		$	8,490		$	(593	)	$	76,824
Capital expenditures	$	319,042		$	21,589		$	—		$	340,631
Total assets at period end	2,817,714			1,427,792			8,152			4,253,658

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

The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes included elsewhere in this report. 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 impact of the Chapter 11 proceedings on our business, the volatility of oil and gas prices, production timing and volumes, our ability to continue as a going concern, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this Quarterly Report and in the sections titled “Risk Factors” in this Quarterly Report, our Q1 2019 Form 10-Q and in our 2018 10-K, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are an independent exploration and production company focused on the acquisition, development, exploration and production of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. We also operate in the Midstream segment through KFM. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The KFM midstream assets are integral to our Upstream operations, which we conduct in the same region, and they are strategically positioned to provide similar services to other producers in the area.

As of June 30, 2019, we have 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 and southeastern Major counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. After the Business Combination, we conducted development activities using a spacing array of 6 to 10 wells per section and running up to 9 rigs at the peak activity level. In late 2018, our production across the acreage evidenced that the well spacing was not delivering the well level production that we expected. During January 2019, we suspended our development program to allow our new management team to conduct a full operational and economic review. We restarted our development program in March 2019 with a less dense spacing pattern of up to five wells per section. In addition, we have worked to improve our economic returns by reducing well costs, general and administrative expense and other operating expense. We have operated 2 rigs since restarting the program, however, in order to preserve liquidity in anticipation of the bankruptcy filing in September 2019, we have ceased all development activities, unless or until such activities are approved by the Court or until our bankruptcy can be resolved.

We anticipate that the reduced Alta Mesa development attendant to the bankruptcy proceedings could also result in less gathering volumes for KFM, which will adversely impact KFM’s revenue, EBITDA and operating cash flows. During bankruptcy, we will be dependent on liquidity provided by our non-debtor subsidiaries, including KFM, to meet our financial obligations. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.

Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values on the closing date.  This resulted in our financial presentation being separated into two distinct periods, the period before the Business Combination (“Predecessor Period”) and the period after the Business Combination (“Successor Period”). The Company’s financial presentation reflects Alta Mesa as the “Predecessor” for the period January 1, 2018 to February 8, 2018. The Company, including the consolidated results of Alta Mesa and KFM, is the “Successor” for periods since February 9, 2018.

Accordingly, for purposes of explaining our segment results, we have presented the results of our Upstream and Midstream segments for the three months ended June 30, 2019, in comparison to the results for the three months ended June 30, 2018, and

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the results for the six months ended June 30, 2019, in comparison to (i) the results of the Upstream and Midstream segments for the period February 9, 2018 through June 30, 2018, and (ii) the results of Alta Mesa for the Predecessor Period. As KFM was acquired on February 9, 2018, its results are not included in the Predecessor Period.

We distributed our non-STACK oil and gas assets and liabilities to High Mesa in connection with the closing of the Business Combination. We report the non-STACK oil and gas assets and liabilities as discontinued operations during the Predecessor Period.

Outlook, Market Conditions and Commodity Prices

Our revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, gas and NGLs, which are beyond our control.  The success of our business is significantly affected by the price of oil due to its weighting in our production profile. 

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 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, gas and NGL prices significantly decrease, such decreases could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of the borrowing capacity under the Alta Mesa RBL.

Key performance indicators

During 2019, our board of directors has established the following operating measures as key performance indicators for executive management compensation and the Company as a whole:

• Production;

• General and administrative costs (excluding strategic costs);

• Lease operating expense;

• Well drilling and completion costs; and

• Adjusted EBITDA or EBITDAX.

We will focus on measuring our performance against baseline and prior year comparable periods during this and future filings.

The Company’s management believes Adjusted EBITDA for our Midstream segment and Adjusted EBITDAX for our Upstream segment are useful because they allow users to more effectively evaluate our operating performance, compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure and because it highlights trends in our businesses that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDA and Adjusted EBITDAX should not be considered as alternatives to our net income (loss), operating income (loss) or other performance measures derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports.

Going concern

We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration a number of factors that were previously disclosed in our 2018 10-K. Most significantly, we have seen significant reductions to our borrowing base under the Alta Mesa RBL in 2019. On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced by $30 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause

31

utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $63.0 million.

If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Debtors filed Bankruptcy Petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC are not part of the Chapter 11 cases at this time.

On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors were authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral for an initial four week period on the terms and conditions agreed by the AMH Debtors and the lenders under the Alta Mesa RBL and set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain milestones. The ability to have continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.

The Debtors have begun a marketing process to sell their assets, which may also include KFM’s midstream assets. Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions LP, an Alta Mesa subsidiary, and non-Debtors KFM and its subsidiaries can be rejected by the Debtors.

We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the approved cash collateral agreement, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.3 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.

Delisting from Stock Exchange

As a result of our failure to comply with the continued listing requirements of the NASDAQ, trading in our Class A Common Stock and public warrants was suspended on September 24, 2019, and they are now traded over the counter under the trading symbols “AMRQQ” and “AMRWQ,” respectively.

Derivatives

The objective of our hedging program is to produce, over time, relative revenue stability. However, both settlements and fair value changes in our derivatives can significantly impact our short-term results of operations. During September 2019, we closed out all open derivative positions resulting in net proceeds of approximately $4 million, which we applied against our outstanding borrowings under the Alta Mesa RBL.

Impairments

No long-lived asset impairments were recognized during the six months ended June 30, 2019, except for certain operating lease right-of-use assets described above. However, in late fourth quarter of 2018, the combination of depressed prevailing oil and

32

gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations, along with other factors, resulted in impairment charges of $2.0 billion to our oil and gas properties and $1.2 billion to our Midstream segment goodwill, tangible and intangible assets during the quarter ended December 31, 2018. Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place.

Factors affecting future performance

The primary factors affecting our production levels, which may be interrelated, are current commodity prices, capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, our wells have significant natural production declines. Our development program was established to overcome this natural decline. Sustaining our production levels or our future growth will depend on our ability to continue to develop reserves, including our ability to fund such development. We expect that our ability to add reserves through drilling and other development techniques will be significantly curtailed as a result of our bankruptcy filing, which will have an adverse effect on any revenue growth and, as a result, our cash flow from operations.

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RESULTS OF OPERATIONS

For the Three Months Ended June 30, 2019 (“Second Quarter 2019”) Compared to the Three Months Ended June 30, 2018 (“Second Quarter 2018”).

Upstream Segment Results

Revenue

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

(in thousands, except per unit data)	Second Quarter 2019			Second Quarter 2018
Net production:
Oil (Mbbls)	1,545			1,123
Natural gas (MMcf)	6,283			3,944
NGLs (Mbbls)	819			554
Total (MBoe)	3,411			2,334
Average net daily production volumes:
Oil (Mbblsd)	17.0			12.3
Natural gas (MMcfd)	69.0			43.3
NGLs (Mbblsd)	9.0			6.1
Total (MBoed)	37.5			25.6
Average sales prices:
Oil (per bbl)	$	58.67		$	67.09
Effect of realized derivatives settlements (per bbl)	0.12			(12.80		)
Oil, after hedging (per bbl)	$	58.79		$	54.29
Percentage of unhedged realized oil price to NYMEX oil price	98		%	99		%
Natural gas (per Mcf)	$	1.97		$	2.02
Effect of realized derivatives settlements (per Mcf)	0.06			—
Natural gas, after hedging (per Mcf)	$	2.03		$	2.02
NGLs (per bbl)	$	12.52		$	18.47
Effect of realized derivatives settlements (per bbl)	—			—
NGLs, after hedging (per bbl)	$	12.52		$	18.47
Revenue
Oil sales	$	90,668		$	75,291
Natural gas sales	12,384			7,980
NGL sales	10,251			10,241
Total sales revenue	$	113,303		$	93,512

Oil sales for the Second Quarter 2019 increased due to increased production, partially offset by lower average sales prices before hedging. The increase in production was due to the extensive development program conducted following the Business Combination.

Natural gas sales for the Second Quarter 2019 increased primarily due to increased production as a result of the extensive development program conducted following the Business Combination.

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NGL sales for the Second Quarter 2019 increased modestly due to increased 2019 production, mostly offset by lower average prices. The increase in production volume was primarily due to the impact of our development activities after the Business Combination. 

Derivatives

(in thousands)	Second Quarter 2019		Second Quarter 2018
Gain (loss) on derivatives:
Oil	$	191	$	(14,362	)
Natural gas	353		3
Total realized gains (losses)	544		(14,359		)
Unrealized gains (losses)	11,868		(14,860		)
Total gain (loss) on derivatives	$	12,412	$	(29,219	)

Decreases and increases in future commodity prices during each period compared to futures prices in effect at the time of execution of our outstanding derivatives resulted in the gains and losses recognized, respectively, during each quarter.

Operating Expenses

(in thousands, except per unit data)	Second Quarter 2019		Second Quarter 2018
Operating expenses:
Lease operating	$	19,123	$	12,679
Transportation and marketing	19,614		11,205
Production taxes	5,117		2,606
Workovers	412		333
Exploration	3,289		8,083
Depreciation, depletion and amortization	34,504		26,670
Impairment	6,500		—
General and administrative	15,723		17,811
Total operating expense	$	104,282	$	79,387
Operating expenses per BOE:
Lease operating	$	5.61	$	5.43
Transportation and marketing	5.75		4.80
Production taxes	1.50		1.12
Workovers	0.12		0.14
Depreciation, depletion and amortization	10.12		11.43

Lease operating expense for the Second Quarter 2019 increased due to higher production and the impact of additional costs associated with the sale of our produced water assets to our affiliate KFM in the fourth quarter of 2018.

Transportation and marketing expense for the Second Quarter 2019 increased due to higher volumes. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant. The amount for the Second Quarter 2019 also reflects a more significant expense due to an increase in committed capacity which went unused.

Production taxes for the Second Quarter 2019 increased due to the increase in oil and NGL revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018, for wells in their first 3 years of production.

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(in thousands)	Second Quarter 2019		Second Quarter 2018
Exploration expense:
Geological and geophysical costs	$	366	$	1,139
Other exploration expense, including expired leases	2,909		6,579
ARO settlements in excess of recorded liabilities	14		365
Total exploration expense	$	3,289	$	8,083

Exploration expense during the Second Quarter 2019 decreased compared to the Second Quarter 2018 largely due to $3.7 million of lower expired lease costs.

Depreciation, depletion and amortization was lower on a per BOE basis during the Second Quarter 2019 largely due to the amount of impairment taken on our oil and gas properties during the fourth quarter of 2018, which reduced the depletable base.

During the Second Quarter 2019, we recognized a $6.5 million impairment of our operating lease right-of-use assets.

(in thousands)	Second Quarter 2019		Second Quarter 2018
General and administrative expense:
Employee-related costs	$	6,649	$	6,126
Equity-based compensation	1,396		3,621
Professional fees	126		3,843
Strategic costs	4,061		—
Business Combination	—		443
Severance costs	609		—
Information technology	946		2,146
Operating leases	1,293		995
Provision for uncollectible receivables	298		—
Other	345		637
Total general and administrative expense	$	15,723	$	17,811

General and administrative expenses during the Second Quarter 2019 decreased due mainly to lower costs associated with equity-based compensation expense and information technology costs associated with the change in control. General and administrative expense during the Second Quarter 2019 also included costs for legal and financial advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties.

36

Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:

(in thousands)	Second Quarter 2019			Second Quarter 2018
Income (loss) from continuing operations before income taxes	$	7,746		$	(22,469	)
Interest expense	14,071			10,361
Depreciation, depletion and amortization	34,504			26,670
Exploration	3,289			8,083
Loss (gain) on unrealized hedges	(11,868		)	14,860
Impairment of assets	6,500			—
Equity-based compensation	1,396			3,621
Severance costs	609			—
Strategic costs	4,061			—
Business Combination	—			443
Adjusted EBITDAX	$	60,308		$	41,569

Other (Income) Expense

(in thousands)	Second Quarter 2019			Second Quarter 2018
Alta Mesa RBL	$	5,204		$	—
2024 Notes	9,844			9,844
Bond premium amortization	(1,231		)	(1,231		)
Deferred financing cost amortization	94			80
Other	160			1,668
Total interest expense	14,071			10,361
Interest income	(54		)	(820		)
Total other (income) expense, net	$	14,017		$	9,541

Interest expense for the Second Quarter 2019 increased due primarily to increased levels of borrowings under the Alta Mesa RBL. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.

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Midstream Segment Results

Revenue

(in thousands)	Second Quarter 2019		Second Quarter 2018
Sales of gathered production	$	10,439	$	21,024
Midstream revenue	22,112		15,849
Produced water disposal fees	6,693		—
Total Midstream revenue	$	39,244	$	36,873
KFM gas volumes (MMcf)	12,736		8,704
KFM crude oil volumes (Mbbls)	443		301
KFM produced water gathering volumes (Mbbls)	6,941		—

Sales of gathered production during the Second Quarter 2019 decreased compared to the Second Quarter 2018 due to a decline in volumes from third-party producers that are processed and sold back to the producers.

Midstream revenue during the Second Quarter 2019 increased compared to the Second Quarter 2018 due to increased receipt point volumes and the impact of a second cryogenic processing train being commissioned in mid 2018.

Produced water disposal fees during the Second Quarter 2019 resulted from the acquisition of produced water disposal assets from Alta Mesa during the fourth quarter of 2018.

Operating Expenses

(in thousands)	Second Quarter 2019		Second Quarter 2018
Midstream operating	$	6,520	$	3,313
Cost of sales for purchased gathered production	8,720		21,002
Transportation and processing	2,786		3,223
Workovers	395		—
Depreciation and amortization	3,505		7,264
General and administrative	5,324		4,140
Total operating expenses	$	27,250	$	38,942

Midstream operating expense for the Second Quarter 2019 increased compared to the Second Quarter 2018 due to additional operating expenses for the produced water disposal assets acquired from Alta Mesa during the fourth quarter of 2018 and the impact of higher volumes, which led to higher compressor-related costs.

Cost of sales of purchased gathered production decreased in the Second Quarter 2019 as compared to the Second Quarter 2018, reflective of the sales decline to third parties noted above.

Transportation and processing expense declined in the Second Quarter 2019 as compared to the Second Quarter 2018 as a result of the segment’s cost reduction efforts during the current period.

Depreciation and amortization during the Second Quarter 2018 included $5.3 million of amortization expense related to intangible customer relationship assets that were fully impaired at December 31, 2018. This impact was partially offset by an increase of $1.5 million in depreciation of tangible assets during the Second Quarter 2019 due to capital spending since June 30, 2018, including the purchase of the produced waster disposal assets from Alta Mesa in the fourth quarter of 2018.

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(in thousands)	Second Quarter 2019			Second Quarter 2018
General and administrative expenses:
Employee-related costs	$	3,745		$	2,995
Equity-based compensation	(556		)	465
Professional fees	748			415
Strategic costs	648			5
Severance costs	88			—
Information technology	—			4
Operating leases	55			25
Other	596			231
Total general and administrative expense	$	5,324		$	4,140

General and administrative expense increased during the Second Quarter 2019 as a result of increased headcount and higher legal and financial advisory services associated with financial structuring activities. The departure of our Vice President and Chief Operating Officer - Midstream resulted in recognition during the Second Quarter 2019 of the forfeiture of certain previously expensed equity compensation awards.

Below is a reconciliation of Midstream adjusted EBITDA to income (loss) from continuing operations before income taxes:

(in thousands)	Second Quarter 2019			Second Quarter 2018
Income (loss) from continuing operations before income taxes	$	9,959		$	(3,487	)
Interest expense	2,684			1,418
Depreciation and amortization	3,505			7,264
Impairment of assets	—			—
Equity-based compensation	(556		)	465
Severance costs	88			—
Adjusted Midstream EBITDA	$	15,680		$	5,660

Other (Income) Expense

(in thousands)	Second Quarter 2019			Second Quarter 2018
KFM Credit Facility	$	2,429		$	322
Predecessor revolving credit facility	—			827
Deferred financing cost amortization	154			72
Other	101			197
Total interest expense	2,684			1,418
Interest income	(6		)	—
Equity in earnings of unconsolidated subsidiaries	(643		)	—
Total other (income) expense, net	$	2,035		$	1,418

Interest expense for the Second Quarter 2019 increased primarily due to increased levels of borrowings under the KFM Credit Facility compared to the predecessor credit facility. Deferred financing costs associated with the KFM Credit Facility are being amortized over the facility’s remaining term. Other interest primarily relates to commitment fees.

39

Equity in earnings of unconsolidated subsidiaries represents our share of the net income during the Second Quarter 2019 associated with our 50% ownership in the Cimarron pipeline (“Cimarron”). Our investment in Cimarron is accounted for under the equity method.

40

For the Six Months Ended June 30, 2019 (“2019 Period”) Compared to the Periods February 9, 2018 Through June 30, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor)

The tables included below set forth financial information for the Successor Periods and Predecessor Period, which are distinct reporting periods as a result of the Business Combination.  The Predecessor Period amounts below exclude operating results related to discontinued operations. We refer to the combined Predecessor Period and Successor Period from February 9, 2018 through June 30, 2018 and January 1, 2018 through February 8, 2018 as the “2018 Period”.

Upstream Segment Results

Revenue

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

	Successor						Predecessor
(in thousands, except per unit data)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Net production:
Oil (Mbbl)	3,164			1,774			494
Natural gas (MMcf)	12,114			6,192			1,609
NGLs (Mbbl)	1,614			777			151
Total (MBoe)	6,797			3,583			914
Average net daily production volumes:
Oil (Mbbld)	17.5			12.5			12.7
Natural gas (MMcfd)	66.9			43.6			41.2
NGLs (Mbbld)	8.9			5.5			3.9
Total (MBoed)	37.6			25.2			23.4
Average sales prices:
Oil (per bbl)	$	55.94		$	65.16		$	62.68
Effect of realized derivatives settlements (per bbl)	0.61			(11.01		)	(6.44		)
Oil, after hedging (per bbl)	$	56.55		$	54.15		$	56.24
Percentage of unhedged realized oil price to NYMEX oil price	97		%	99		%	99		%
Natural gas (per Mcf)	$	2.55		$	2.13		$	2.66
Effect of realized derivatives settlements (per Mcf)	(0.08		)	0.09			0.94
Natural gas, after hedging (per Mcf)	$	2.47		$	2.22		$	3.60
NGLs (per bbl)	$	13.30		$	19.25		$	26.41
Effect of realized derivatives settlements (per bbl)	—			—			—
NGLs, after hedging (per bbl)	$	13.30		$	19.25		$	26.41
Revenue
Oil sales	$	177,031		$	115,569		$	30,972
Natural gas sales	30,834			13,190			4,276
NGL sales	21,467			14,955			4,000
Total sales	$	229,332		$	143,714		$	39,248

41

Oil sales for the 2019 Period increased due to increased production, partially offset by lower average sales prices before hedging. The increase in production was due to the extensive development program conducted following the Business Combination.

Natural gas sales for the 2019 Period increased due to both an increase in production as a result of the extensive development program conducted following the Business Combination and higher prevailing market prices.

NGL sales for the 2019 Period increased due to increased production, significantly offset by lower average prices. The increase in production volume was primarily due to the impact of our extensive 2018 development activities following the Business Combination.

Gain (loss) on sale of assets for the 2019 Period included a gain from the sale of seismic data totaling $1.5 million compared to a similar gain of $5.9 million during the 2018 Period.

Derivatives

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives:
Oil	$	1,936		$	(18,892	)	$	(3,819	)
Natural gas	(1,027		)	558			1,523
Total realized gains (losses)	909			(18,334		)	(2,296		)
Unrealized gains (losses)	(12,274		)	(32,896		)	8,959
Total gain (loss) on derivatives	$	(11,365	)	$	(51,230	)	$	6,663

Decreases and increases in future commodity prices during each period compared to futures prices in effect at the time of execution of our outstanding derivatives resulted in the gains and losses recognized, respectively, during each six month period.

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Operating Expenses

	Successor				Predecessor
(in thousands, except per unit data)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Operating expenses:
Lease operating	$	44,231	$	20,996	$	4,408
Transportation and marketing	37,375		16,788		3,725
Production taxes	10,600		4,021		953
Workovers	609		1,578		423
Exploration	5,343		9,668		7,003
Depreciation, depletion and amortization	69,179		37,708		11,670
Impairment of assets	6,500		—		—
General and administrative	36,670		52,465		21,234
Total operating expense	$	210,507	$	143,224	$	49,416
Operating expenses per BOE:
Lease operating	$	6.51	$	5.86	$	4.82
Transportation and marketing	5.50		4.69		4.08
Production taxes	1.56		1.12		1.04
Workovers	0.09		0.44		0.46
Depreciation, depletion and amortization	10.18		10.52		12.77

Lease operating expense for the 2019 Period increased primarily due to higher production and the impact of additional costs associated with the sale of our produced water assets to our affiliate KFM in the fourth quarter of 2018.

Transportation and marketing expense for the 2019 Period increased primarily due to higher volumes. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant.  The 2019 period also reflects a more significant expense due to an increase in committed capacity which went unused.

Production taxes for the 2019 Period increased primarily due to the increase in oil and NGL revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018, for wells in their first 3 years of production. 

Workovers are associated with maintenance and other efforts to increase production. During the 2019 Period, these costs decreased due to minimal workover projects being undertaken.

	Successor				Predecessor
(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Exploration expense:
Geological and geophysical costs	$	678	$	1,590	$	2,440
Other exploration expense, including expired leases	4,604		7,412		4,504
ARO settlements in excess of recorded liabilities	61		666		59
Total exploration expense	$	5,343	$	9,668	$	7,003

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Exploration expense for the 2019 Period decreased primarily due to our cost reduction efforts, including a reduced number of employees in the geology department, and a decrease in expenses relating to expired or expiring leaseholds.

	Successor				Predecessor
(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
General and administrative expense:
Employee-related costs	$	14,957	$	12,646	$	1,032
Equity-based compensation	3,057		6,389		—
Professional fees	3,723		5,083		1,019
Strategic costs	4,061		—		—
Business Combination	10		23,717		17,040
Severance costs	4,584		—		—
Information technology	1,980		2,649		—
Operating leases	2,317		1,486		208
Provision for uncollectible receivables	1,177		—		—
Other	804		495		1,935
Total general and administrative expense	$	36,670	$	52,465	$	21,234

General and administrative expense for the 2019 Period decreased compared to the 2018 Period primarily due to nonrecurring Business Combination costs and other professional fees incurred in the 2018 Period for advisors helping to value and integrate the acquired business. General and administrative expense during the 2019 Period also included costs for legal and financial advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties.

Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Income (loss) from continuing operations before income taxes	$	(16,979	)	$	(57,071	)	$	(7,116	)
Interest expense	26,901			15,557			5,511
Depreciation, depletion and amortization	69,179			37,708			11,670
Exploration	5,343			9,668			7,003
Loss (gain) on unrealized hedges	12,274			32,896			(8,959		)
Loss on sale of property and equipment	—			63			—
Impairment of assets	6,500			—			—
Equity-based compensation	3,057			6,389			—
Severance costs	4,584			—			—
Strategic costs	4,061			—			—
Business Combination	10			23,717			17,040
Adjusted EBITDAX	$	114,930		$	68,927		$	25,149

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Other (Income) Expense

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Alta Mesa RBL	$	8,783		$	252		$	815
2024 Notes	19,688			16,406			3,281
Bond premium amortization	(2,462		)	(2,051		)	—
Deferred financing cost amortization	139			80			171
Other	753			870			1,244
Total interest expense	26,901			15,557			5,511
Interest income	(81		)	(1,366		)	(172		)
Total other (income) expense, net	$	26,820		$	14,191		$	5,339

Interest expense for the 2019 Period increased primarily due to increased levels of borrowing under the Alta Mesa RBL. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.

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Midstream Segment Results

Revenue

(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018
Sales of gathered production	$	19,999	$	31,634
Midstream revenue	44,488		23,671
Produced water disposal fees	14,374		—
Total Midstream revenue	$	78,861	$	55,305
KFM gas volumes (MMcf)	25,100		12,944
KFM crude oil volumes (Mbbls)	1,037		433
KFM produced water gathering volumes (Mbbls)	14,622		—

Sales of gathered production during the 2019 Period decreased compared to the 2018 Period due to a decline in volumes from third-party producers that are processed and sold back to the producers.

Midstream revenue during the 2019 Period increased compared to the 2018 Period due to increased receipt point volumes and the impact of a second cryogenic processing train being commissioned in mid 2018.

Produced water disposal fees during the 2019 Period resulted from the acquisition of produced water disposal assets from Alta Mesa during the fourth quarter of 2018.

Operating Expenses

(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018
Midstream operating	$	12,671	$	3,900
Cost of sales for purchased gathered production	18,415		31,548
Transportation and processing	4,849		5,561
Workovers	511		—
Depreciation and amortization	6,729		11,905
General and administrative	13,387		6,313
Total operating expenses	$	56,562	$	59,227

Midstream operating expense for the 2019 Period increased compared to the 2018 Period due to additional operating expenses for the produced water disposal assets acquired from Alta Mesa during the fourth quarter of 2018 and the impact of higher volumes, which led to higher compressor-related costs.

Cost of sales of purchased gathered production decreased in the 2019 Period as compared to the 2018 Period, reflective of the sales decline to third parties noted above.

Transportation and processing expense declined in the 2019 Period as compared to the 2018 Period as a result of the segment’s cost reduction efforts during the current period.

Depreciation and amortization during the 2018 Period included $8.8 million of amortization expense related to intangible customer relationship assets that were fully impaired at December 31, 2018. This impact was partially offset by an increase of $3.6 million in depreciation of tangible assets during the 2019 Period due to capital spending since June 30, 2018, including the purchase of the produced waster disposal assets from Alta Mesa in the fourth quarter of 2018, and as a result of the increased number of days during the 2019 Period compared to the 2018 Period.

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(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018
General and administrative expenses:
Employee-related costs	$	7,723	$	4,013
Equity-based compensation	462		507
Professional fees	1,197		532
Strategic costs	648		10
Severance costs	1,984		—
Information technology	126		4
Operating leases	218		39
Other	1,029		1,208
Total general and administrative expense	$	13,387	$	6,313

General and administrative expense increased during the 2019 Period as a result of increased headcount and higher legal and financial advisory services associated with financial structuring activities. Following a reassessment of 2019 activity levels, we implemented a reduction in force program during the 2019 Period, which along with the departure of our Vice President and Chief Operating Officer - Midstream, resulted in severance costs during the period.

Below is a reconciliation of Midstream adjusted EBITDA to income (loss) from continuing operations before income taxes:

(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018
Income (loss) from continuing operations before income taxes	$	17,737	$	(5,588	)
Interest expense	5,314		1,666
Depreciation and amortization	6,729		11,905
Equity-based compensation	462		507
Severance costs	1,984		—
Adjusted Midstream EBITDA	$	32,226	$	8,490

Other (Income) Expense

(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018
KFM Credit Facility	$	4,811		$	322
Predecessor revolving credit facility	—			980
Deferred financing cost amortization	229			72
Other	274			292
Total interest expense	5,314			1,666
Interest income	(10		)	—
Equity in earnings of unconsolidated subsidiaries	(742		)	—
Total other (income) expense, net	$	4,562		$	1,666

Interest expense for the 2019 Period increased primarily due to increased levels of borrowings under the KFM Credit Facility compared to the predecessor credit facility. Deferred financing costs associated with the KFM Credit Facility are being amortized over the facility’s remaining term. Other interest primarily relates to commitment fees.

Equity in earnings of unconsolidated subsidiaries represents our share of the net income during the 2019 Period associated with our 50% ownership in the Cimarron pipeline (“Cimarron”). Our investment in Cimarron is accounted for under the equity method.

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LIQUIDITY AND CAPITAL RESOURCES

Our principal requirements for capital during 2019 have been to fund our day-to-day operations, development activities and to satisfy our contractual obligations related to servicing our debt and hedges. During 2019, our main sources of liquidity and capital resources came from operating cash flow and borrowings under the Alta Mesa RBL.

In April 2019, our borrowing base under the Alta Mesa RBL was reduced from $400.0 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $63.0 million.

If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Debtors filed Bankruptcy Petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC are not part of the Chapter 11 cases at this time.

On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors were authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral for an initial four week period on the terms and conditions agreed by the AMH Debtors and the lenders under the Alta Mesa RBL and set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain milestones. The ability to have continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.

We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the approved cash collateral agreement, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.3 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.

During September, we ceased all development activities, other than any that may be prospectively approved by the Court or until our bankruptcy cases can be resolved. The abandonment of planned development activities, particularly with respect to bringing new wells onto production, will likely reduce our production levels, revenue and cash flow, and may result in the expiry of certain leases.

We expect our third quarter 2019 capital incurred to be approximately $44 million, of which $40 million was attributable to the Upstream segment’s 2 rig program we conducted until the time of our bankruptcy filing. Under the terms and conditions of the cash collateral order entered by the Bankruptcy Court and corresponding budget, we are not able to operate any drilling rigs

48

during the fourth quarter of 2019, although we had certain capital spending to finish drilling wells that were in process at the time of our bankruptcy filing. We expect our fourth quarter 2019 capital spending to be substantially less than before the bankruptcy filing.

We anticipate that the reduced Alta Mesa development attendant to the bankruptcy proceedings could also result in less gathering volumes for KFM, which will adversely impact KFM’s revenue, EBITDA and operating cash flows. During bankruptcy, we will be dependent on liquidity provided by our non-debtor subsidiaries, including KFM, to meet our financial obligations. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.

As we execute our business strategy, we will monitor the capital resources available to meet future financial obligations and planned capital expenditures. We cannot provide assurance that operations and other needed capital will be available on acceptable terms, or at all, and our development pace may need to change based on our evolving liquidity profile.

Cash Flow Analysis

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Cash from operating activities	$	84,588		$	(64,822	)	$	26,336
Cash from investing activities	(247,942		)	(96,653		)	(37,913		)
Cash from financing activities	227,500			244,507			16,932
Net increase in cash, cash equivalents and restricted cash	$	64,146		$	83,032		$	5,355

Cash flow from operating activities

During the 2019 Period, cash-based items of net income (loss), including revenue (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense totaled $91.9 million compared to $32.2 million during the 2018 Period, due largely to higher revenues associated with increased production and the lack of costs associated with the Business Combination that were incurred in 2018. Approximately $7.3 million of cash was used to increase working capital during the 2019 Period. During the 2018 Period, cash totaling $70.7 million was used to increase working capital primarily due to increases in trade receivables and amounts due from related parties for administrative services provided, including certain other transactions, and to reduce liabilities arising prior to or as a result of the Business Combination.

Cash flow from investing activities

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Cash provided by (used for)
Capital expenditures	$	(247,942	)	$	(340,631	)	$	(36,695	)
Acquisition of acreage	—			(791,819		)	(1,218		)
Proceeds withdrawn from trust account	—			1,042,742			—
Investment in equity affiliate and other, net	—			(6,945		)	—
Cash from investing activities	$	(247,942	)	$	(96,653	)	$	(37,913	)

49

During the 2019 Period, capital expenditures included $127.9 million for additions to property and equipment that occurred prior to December 31, 2018. Capital spending during 2019 has decreased significantly from 2018 as a result of the reassessment of our current drilling plans due to the results obtained from our 2018 drilling program and our existing liquidity concerns. We ran as many as 9 rigs during the 2018 period.

Cash flow from financing activities

	Successor					Predecessor
(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Cash provided by (used for)
Proceeds from long-term debt borrowings	$	227,500	$	80,000		$	60,000
Repayments of long-term debt	—		(193,565		)	(43,000		)
Capital contributions (distributions), net	—		—			(68		)
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		)	—
Other	—		(3,670		)	—
Cash from financing activities	$	227,500	$	244,507		$	16,932

During the 2019 Period, our outstanding balances owed under the Alta Mesa RBL and KFM Credit Facility increased by $227.5 million from December 31, 2018, largely related to borrowings to fund our capital expenditures, including those expenditures incurred in 2018.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivatives to manage or reduce market risk, but we do not enter into derivatives for speculative purposes. We do not designate derivatives as hedges for accounting purposes.

Commodity Price Risk and Hedges

Our major market risk exposure is to prevailing prices for oil, gas and NGLs, which have historically been volatile. As such, future results are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for gas. We have used derivatives to reduce our exposure to the risks of price changes. Pursuant to our risk management policy, we have engaged in hedging against low prices and price volatility.

The fair value of our oil and gas derivatives and basis swaps at June 30, 2019 was a net asset of $6.2 million. A 10% increase in oil and gas prices (with all other factors held constant) would result in a net liability of $7.7 million at June 30, 2019, and a 10% decrease in oil and gas prices (with all other factors held constant) would result in a net asset of $18.9 million at June 30, 2019. During September 2019, we closed out all open derivative positions resulting in net proceeds of approximately $4 million, which we applied against our outstanding borrowings under the Alta Mesa RBL.

Counterparty and Customer Credit Risk 

Our derivatives expose us to credit risk in the event of nonperformance by counterparties. While we do not require them to post collateral, we do monitor the credit standing of such counterparties, all of which have investment grade ratings, and are lenders under the Alta Mesa RBL.

Our principal ongoing exposures to credit risk are from joint interest receivables and receivables from the sale of our oil and gas production and midstream gathering and processing activities. The inability or failure of our customers to meet their obligations

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to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our purchasers of production, midstream services and other working interest owners is high. Because Alta Mesa filed for bankruptcy protection, KFM’s ability to collect fees from Alta Mesa for midstream services could be impaired. We cannot predict the likelihood, if any, that Alta Mesa’s bankruptcy filing could have on KFM’s operating cash flow.

During most of the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales were generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality.  In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM.  As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.

For the six months ended June 30, 2019, ARM marketed $119.2 million, or 44.3% of our operating revenue for the period.

Joint operations receivables arise from billings to entities that own interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rates

We are subject to interest rate risk under the Alta Mesa RBL and KFM Credit Facility. We currently have no open interest rate derivatives. A 100 basis point increase in interest rates would increase our annual interest expense for both facilities by approximately $5.6 million, based on the balances outstanding at June 30, 2019.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the 2019 Period.  Although the impact of inflation has been insignificant in recent years, it could cause future upward pressure on the cost of oilfield services, equipment and general and administrative expenses. 

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15 and 15d-15 of the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, performed an evaluation of our disclosure controls and procedures. Our controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or

submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

As described further in our 2018 10-K, we concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to existence of material weakness in our internal control over financial reporting (“ICFR”). Apart from the controls and procedures relating to accounting for business combinations, several of the material weaknesses in our ICFR continued to exist during the 2019 Period. These material weaknesses include:

• establishment of formal policies and procedures;

• ineffective monitoring activities that span the Company to ensure that internal controls processes are functioning properly;

• ineffective controls over the financial statement close and disclosure process; and

• over-reliance on and ineffective controls over access to and changes involving critical worksheets.

As noted in our 2018 10-K, KFM was excluded from management’s assessment of internal control over financial reporting as of December 31, 2018 but will be included in our assessment for 2019.

Changes in Internal Control Over Financial Reporting (ICFR)

While we have made progress in multiple areas to improve ICFR, management is continuing to implement the remediation plan described in our 2018 10-K and continues to work to make changes in controls and procedures in a manner consistent with the size, complexity and scale of operations subsequent to the Business Combination.

During the Second Quarter 2019, we have made access changes to payroll, production accounting, and reserves systems to address material weaknesses identified during 2018. Testing to be conducted later in 2019 will determine whether these changes to system access will prove effective in remediating the underlying material weakness.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes cannot be reasonably estimated. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. There have been no significant changes during the 2019 Period to the matters described in Legal Proceedings in our 2018 10-K.

The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including the matters discussed in our 2018 10-K.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. There have been no material changes during the 2019 Period to the risk factors described under Risk Factors in our 2018 10-K, except as described below.

The Debtors are subject to the risks and uncertainties associated with proceedings under Chapter 11 of title 11 of the Bankruptcy Code.

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For the duration of our Chapter 11 proceedings, the Debtors’ operations and their ability to develop and execute their business plans, as well as continuation as a going concern, are subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

• the Debtors’ ability to develop, confirm and consummate a Chapter 11 plan, asset sale or alternative restructuring transaction;

• the Debtors’ ability to obtain court approval with respect to motions filed in Chapter 11 proceedings from time to time;

• the Debtors’ ability to continue utilizing their relationships with their suppliers, service providers, customers, employees and other third parties;

• the Debtors’ ability to maintain contracts that are critical to their operations;

• the Debtors’ ability to execute their business plans;

• the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with the Debtors;

• the Debtors’ ability to access, and maintain access to, sufficient financing for the duration of the Chapter 11 proceedings;

• the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for the Debtors to propose and confirm a Chapter 11 plan, to appoint a Chapter 11 trustee, or to convert the Chapter 11 proceedings to a proceeding under Chapter 7 of the Bankruptcy Code; and

• the actions and decisions of the Debtors’ creditors and other third parties who have interests in these Chapter 11 proceedings that may be inconsistent with the Debtors’ plans.

These risks and uncertainties could affect the Debtors’ business and operations in various ways. For example, negative events associated with our Chapter 11 proceedings could adversely affect the Debtors’ relationships with suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect the operations and financial condition of the Debtors. Also, the Debtors need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit their ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact of events that will occur during these Chapter 11 proceedings that may be inconsistent with the Debtors’ plans.

The AMH Debtors’ cash collateral order and termination events limit the AMH Debtors’ operating flexibility, and the occurrence of any termination event under the cash collateral order could have significant adverse consequences.

The cash collateral order requires the AMH Debtors to adhere to an agreed budget with the secured lenders holding an interest in such cash collateral, and it contains covenants and/or termination events that, among other things, restrict the AMH Debtors’ ability to take specific actions and, in the case of termination events, may be outside of the AMH Debtors’ control. The initial cash collateral order spans four weeks and is subject to renewal for succeeding four week periods that require Bankruptcy Court approval which may not be granted. Additionally, the cash collateral order contains specified milestones and dates by which they must occur relating to a potential sale of all or substantially all of the AMH Debtors’ assets, and/or pursuit of a Chapter 11 plan of reorganization of the AMH Debtors, with which the AMH Debtors must comply. The AMH Debtors’ ability to comply with these timelines may be affected by events and circumstances outside of their control. Non-compliance with the cash collateral order could result in the AMH Debtors losing access to cash collateral and/or foreclosure by the AMH Debtors’ secured lenders on the AMH Debtors’ assets that serve as collateral for their loans, subject to the terms of the cash collateral order.

Operating under Bankruptcy Court protection for a long period of time may harm our business.

A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the Chapter 11 proceedings continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating under Bankruptcy Court protection may also make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 proceedings continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships.

Furthermore, so long as the Chapter 11 proceedings continue, the Debtors will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 proceedings. Although no such financing has been sought to date, the Chapter 11 proceedings may also require the Debtors to seek debtor-in-possession

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financing to fund operations. If the Debtors are unable to obtain such financing on favorable terms or at all, their chances of successfully reorganizing their business may be seriously jeopardized, the likelihood that the Debtors will be required to liquidate their assets may be enhanced, and, as a result, any securities in the Debtors could become further devalued or become worthless. In addition, the AMH Debtors’ access to cash that serves as collateral for Alta Mesa’s secured lenders depends on Alta Mesa’s ability to obtain the consent of such lenders to continued use of cash collateral or entry of a Bankruptcy Court order authorizing such use without consent of the lenders.

Under the cash collateral order, the AMH Debtors are required to suspend most of their capital spending program, which will result in delays in developing our resources and in bringing new production on line. This could adversely impact our operating cash flow.

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, the Debtors’ operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11 proceedings.

The Chapter 11 proceedings create substantial uncertainty regarding certain significant intercompany commercial and other relationships.

The Chapter 11 proceedings create substantial uncertainty regarding certain significant commercial and other relationships among us, the other Debtors and our other subsidiaries, including KFM. These relationships include oil and gas gathering agreements, a produced water gathering and disposal agreement and a tax receivable agreement, among others, which may be subject to review and some of which have been challenged in the Chapter 11 proceedings. On September 12, 2019, an adversary proceeding was commenced by certain of the AMH Debtors against KFM, Oklahoma Produced Water Solutions, LLC, SRII Opco, HMI, Michael E. Ellis, and Harlan H. Chappelle (together, the “Defendants”), alleging, among other things, that the Defendants breached their respective fiduciary duties owed to the AMH Debtors by entering into certain related party transactions and asserting that the gathering agreements are executory contracts. Pursuant to the adversary proceeding complaint, AMH is seeking declaratory judgements that the gathering agreements cannot continue to burden AMH or its estates and can therefore be rejected under the Bankruptcy Code. The Bankruptcy Court has not yet set a schedule to adjudicate the complaint and the outcome is unknown at this time. We are unable to estimate the outcome of such challenges or other claims arising out of the Chapter 11 proceedings, any resulting material losses, obligations or other liabilities or their possible material adverse effect on KFM’s or our other subsidiaries’ business, results of operations and financial condition. The costs of potential liabilities resulting from the Chapter 11 proceedings could have a material and adverse impact on KFM’s business, financial condition, results of operations and cash flows.

The Debtors may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

To emerge successfully from Bankruptcy Court protection as a viable entity, the Debtors must meet certain statutory requirements with respect to adequacy of disclosure for a Chapter 11 plan, solicit and obtain the requisite acceptances of such a plan and fulfill other statutory conditions for confirmation of such a plan, which have not occurred to date. The confirmation process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding a Chapter 11 plan.

The Debtors may not receive the requisite acceptances of constituencies in the Chapter 11 proceedings to confirm a Chapter 11 plan. Even if the requisite acceptances are received, the Bankruptcy Court may not confirm such a plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims or subordinated or senior claims).

If a Chapter 11 plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether the Debtors would be able to reorganize their business and what, if anything, holders of claims against the Debtors would ultimately receive with respect to their claims.

Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant

53

professional fees and other costs in connection with preparation for the Chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 proceedings until we are able to emerge from our Chapter 11 proceedings.

The Debtors’ liquidity, including their ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) their ability to comply with the terms and conditions of any cash collateral order that may be entered by the Bankruptcy Court in connection with the Chapter 11 proceedings, (ii) their ability to maintain adequate cash on hand, (iii) their ability to generate cash flow from operations, (iv) continued access to the liquidity in our non-bankrupt subsidiaries, (v) their ability to develop, confirm and consummate a Chapter 11 plan or other alternative sale or restructuring transaction, and (vi) the cost, duration and outcome of the Chapter 11 proceedings.

In addition, because some of our subsidiaries did not file for bankruptcy protection they may be required to retain professional service providers that are redundant to the Debtors’ advisors. These expanded costs could stress their ability to fund other revenue-generating costs.

As a result of the Chapter 11 proceedings, the Debtors’ financial results may be volatile and may not reflect historical trends.

During the Chapter 11 proceedings, the Debtors expect their financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact their financial results. As a result, the Debtors’ historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. In addition, if the Debtors emerge from Chapter 11, the amounts reported in subsequent periods may materially change relative to historical results, including due to revisions to their operating plans pursuant to a plan of reorganization. The Debtors also may be required to adopt fresh start accounting, in which case their assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities prior to seeking bankruptcy protection. The Debtors’ financial results after the application of fresh start accounting also may be different from historical trends.

The Debtors may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on their financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the terms of the plan of reorganization. Any claims not ultimately discharged through the plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis.

The Debtors’ inability to pay service providers on a timely basis may have an adverse effect on their ability to secure their future services.

The Debtor’s inability to satisfy their obligations to service providers on a timely basis may result in irreparable harm to relationships with them and their willingness to continue to do business with the Debtors in the future under acceptable terms. Certain of the Debtors’ service providers have recently filed, and other service providers in the future may file, liens on the Debtors’ assets in order to collect on debts incurred prior to the bankruptcy filing. In addition, the Debtors as well as KFM and its subsidiaries may be required to make advance payments for services, and some critical and/or uniquely qualified service providers may refuse to continue to do business with us, which would result in material adverse consequences to us.

We may experience increased levels of employee attrition as a result of the Chapter 11 proceedings.

As a result of the Chapter 11 proceedings, we may experience increased levels of employee attrition, and our employees likely will face considerable increase in workload, distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the duration of the Chapter 11 proceedings is limited by restrictions for incentive programs under the Bankruptcy Code and by the cash collateral order. The loss of services of members of our senior management team could impair our ability to execute our

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strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition and results of operations.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

We can provide no assurance as to whether the Debtors will successfully reorganize and emerge from the Chapter 11 proceedings or, if they do successfully reorganize, as to when they would emerge from the Chapter 11 proceedings.

If the Bankruptcy Court finds that it would be in the best interest of the Debtors’ creditors and/or the Debtors best interest, the Bankruptcy Court may convert the anticipated Chapter 11 bankruptcy case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate the Debtors’ assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to the Debtors’ creditors than those provided for in a Chapter 11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a disorderly fashion over a short period of time rather than reorganizing or selling in a controlled manner, (ii) additional administrative expenses that would be incurred in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

Any Chapter 11 plan or other plan of reorganization that the Debtors may implement will be based in large part upon assumptions and analyses developed by the Debtors. If these assumptions and analyses prove to be incorrect, the plan may be unsuccessful in its execution.

Any Chapter 11 plan or other plan of reorganization that the Debtors may implement could affect both their capital structure and the ownership, structure and operation of their businesses and will reflect assumptions and analyses based on their experience and perception of historical trends, current conditions and expected future developments, as well as other factors that they consider appropriate under the circumstances. Whether actual future results and developments will be consistent with these expectations and assumptions depends on a number of factors, including but not limited to (i) the ability to substantially change the Debtors’ capital structure; (ii) the ability to obtain adequate liquidity and financing sources; (iii) the ability to maintain customers’ confidence in the Debtors’ viability as a continuing entity and to attract and retain sufficient business from them; (iv) the ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of these businesses.

In addition, any plan of reorganization will be premised upon financial projections, including with respect to revenues, EBITDA, EBITDAX, capital expenditures, debt service and cash flow. Financial projections are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial projections will not be accurate. In this case, the projections will be even more speculative than normal, because they may involve fundamental changes in the nature of the Debtors’ capital structure. Accordingly, the Debtors expect that their actual financial condition and results of operations will differ, perhaps materially, from what they have anticipated. Consequently, we can provide no assurance that the results or developments contemplated by any plan of reorganization the Debtors may implement will occur or, even if they do occur, that they will have the anticipated effects on the Debtors or their businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

Even if a Chapter 11 plan of reorganization is consummated, the Debtors may not be able to achieve their stated goals and continue as a going concern.

Even if a Chapter 11 plan of reorganization is consummated, the Debtors may continue to face a number of risks, such as deterioration in commodity prices or other changes in economic conditions, changes in the industry, changes in demand for oil and gas and increasing expenses. Some of these risks become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, we cannot guarantee that any Chapter 11 plan of reorganization will achieve the stated goals.

In addition, at the outset of Chapter 11 proceedings, the Bankruptcy Code gives the debtors the exclusive right to propose the plan of reorganization and prohibits creditors, equity security holders and others from proposing a plan. The Debtors currently have the exclusive right to propose a plan of reorganization. If that right is terminated, however, or the exclusivity period

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expires, there could be a material adverse effect on their ability to achieve confirmation of a plan of reorganization in order to achieve their stated goals.

Furthermore, even if the Debtors’ debts are reduced or discharged through a plan of reorganization, they may need to raise additional funds through public or private debt or equity financing or other various means to fund their business after the completion of the Chapter 11 proceedings. The Debtors’ access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

The Debtors’ ability to continue as a going concern is dependent upon their ability to raise additional capital. As a result, they cannot give any assurance of their ability to continue as a going concern, even if a plan of reorganization is confirmed.

For the duration of the Chapter 11 proceedings, Alta Mesa may not be able to enter into commodity derivatives covering estimated future production on favorable terms or at all.

During the Chapter 11 proceedings, Alta Mesa’s ability to enter into new commodity derivatives covering estimated future production will be dependent upon either entering into unsecured hedges or obtaining Bankruptcy Court approval to enter into secured hedges and the willingness for counterparties to transact with us. As a result, Alta Mesa may not be able to enter into additional commodity derivatives covering production in future periods on favorable terms or at all. If Alta Mesa cannot or chooses not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than competitors who engage in hedging arrangements. Alta Mesa’s inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

On September 30, 2019, Alta Mesa Resources, Inc. (the "Company”) and Curtis Emerson agreed upon terms of employment to be the Company’s Vice President and Chief Accounting Officer beginning on or about October 14, 2019. Mr. Emerson will assume the role of the Company’s principal accounting officer.

Prior to joining the Company, Mr. Emerson provided consulting and advisory services through his firm, Overton Partners LLC, founded in January 2018. Since that time Mr. Emerson served as the Interim Controller of Berry Petroleum Corporation through March 2019, provided technical accounting and financial reporting services for Talos Energy, Inc from October 2018 through October 2019 and served as the Interim Chief Financial Officer for Century Natural Resources, LLC from May 2019 through October 2019. Mr. Emerson is a Certified Public Accountant with 20 years of combined public accounting, transaction advisory services, corporate accounting and finance, and financial reporting experience. Prior to founding Overton Partners, LLC, Mr. Emerson worked for Houlihan Lokey as a Vice President in its Transaction Advisory Services group starting in July 2016. Mr. Emerson held several positions, including Chief Financial Officer, from September 2014 until March 2016 for Terra Oilfield Solutions, a solids control and waste management oilfield services company. He was also employed by a start-up company from 2010 to 2014 where he held the position of Vice President and Controller. Mr. Emerson began his career in public accounting with Arthur Andersen followed by KPMG and Ernst & Young, where he held various position of increasing responsibility from 1999 to 2010. The Company has not entered into an employment agreement with Mr. Emerson. The terms of Mr. Emerson’s employment include an annual base salary of $250,000 and participation in the Company’s 2019 annual performance bonus program.

Mr. Emerson will also enter into an indemnification agreement with the Company in the form the Company entered into with certain of its other officers. There are no arrangements or understandings between Mr. Emerson and any other persons pursuant to which he was appointed as an officer of the Company. There are no family relationships between Mr. Emerson and

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any director, executive officer or any person nominated or chosen by the Company to become a director or executive officer. No information is required to be disclosed with respect to Mr. Emerson pursuant to Item 404(a) of Regulation S-K.

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Item 6. Exhibits

Exhibit Number	Description of Exhibit
3.1	Second Amended and Restated Certificate of Incorporation of Alta Mesa Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
3.2	Certificate of Designation of Series A Preferred Stock of Alta Mesa Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
3.3	Certificate of Designation of Series B Preferred Stock of Alta Mesa Resources, Inc. (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 of Alta Mesa Resources, Inc. (incorporated by reference to the Registrant’s Registration Statement on Form S-1 (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	Specimen Class A Common Stock Certificate (incorporated by reference to Exhibit 4.2 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-216409) filed with the SEC on March 2, 2017).
4.2	Specimen Warrant Certificate (incorporated by reference to Exhibit 4.3 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-216409) filed with the SEC on March 2, 2017).
4.3	Warrant Agreement between the Registrant and Continental Stock Transfer & Trust Company, as warrant agent (incorporated by reference to Exhibit 4.4 of the Registrant’s Current Report on Form 8-K filed with the SEC on March 29, 2017).
31.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101*	Interactive data files.

* filed herewith.

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SIGNATURES

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

		ALTA MESA RESOURCES, INC.
		(Registrant)
By	/s/ John C. Regan
	John C. Regan
	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
Dated	September 30, 2019

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EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark P. Castiglione, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Alta Mesa Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of Alta Mesa Resources, Inc. as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Alta Mesa Resources, Inc. and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Alta Mesa Resources, Inc., including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of Alta Mesa Resources, Inc.'s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in Alta Mesa Resources, Inc.’s internal control over financial reporting that occurred during Alta Mesa Resources, Inc.’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Alta Mesa Resources, Inc.’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to Alta Mesa Resources, Inc.’s auditors and the audit committee of Alta Mesa Resources, Inc.’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect Alta Mesa Resources, Inc.’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in Alta Mesa Resources, Inc.’s internal control over financial reporting.

Date: September 30, 2019

/s/ Mark P. Castiglione

Mark P. Castiglione

Chief Executive Officer

Alta Mesa Resources, Inc.

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, John C. Regan, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Alta Mesa Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of Alta Mesa Resources, Inc. as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Alta Mesa Resources, Inc. and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Alta Mesa Resources, Inc., including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of Alta Mesa Resources, Inc.’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in Alta Mesa Resources, Inc.’s internal control over financial reporting that occurred during Alta Mesa Resources, Inc.’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Alta Mesa Resources, Inc.’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to Alta Mesa Resources, Inc.’s auditors and the audit committee of Alta Mesa Resources, Inc.’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect Alta Mesa Resources, Inc.’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in Alta Mesa Resources, Inc.’s internal control over financial reporting.

Date: September 30, 2019

/s/ John C. Regan

John C. Regan

Chief Financial Officer

Alta Mesa Resources, Inc.

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

I, Mark P. Castiglione, Chief Executive Officer of Alta Mesa Resources, Inc. (the "Company"), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

1. The Quarterly Report on Form 10-Q of the Company for the quarter ended June 30, 2019 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: September 30, 2019

/s/ Mark P. Castiglione

Mark P. Castiglione

Chief Executive Officer

Alta Mesa Resources, Inc.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

I, John C. Regan, Chief Financial Officer of Alta Mesa Resources, Inc. (the "Company"), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

1. The Quarterly Report on Form 10-Q of the Company for the quarter ended June 30, 2019 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: September 30, 2019

/s/ John C. Regan

John C. Regan

Chief Financial Officer

Alta Mesa Resources, Inc.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Receivables Receivables (Narrative) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Northwest Gas Processing
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable from related parties, net	$ 1.7	$ 1.7
High Mesa Agreement | Affiliated Entity
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance of note receivable	9.9	10.1
Allowance for uncollectible accounts		9.0
Unamortized premium on 2024 Notes | High Mesa Services LLC
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance of note receivable	$ 11.7	$ 11.7
Debt Instrument, Interest Rate, Stated Percentage	8.00%

XML

Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		5 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss attributable to AMR Class A common stockholders	$ 2,245	$ (6,600)	$ (19,930)	$ (6,162)
Net loss attributable to AMR Class A common stockholders after assumed redemption	$ 9,354	$ (16,066)	$ (36,490)	$ 326
Weighted average Class A common shares outstanding (Basic) (in shares)	180,742,049	173,345,982	171,908,486	180,505,318
Weighted average common shares outstanding (Diluted) (in shares)	180,742,049	207,965,929	208,112,707	180,505,318
Common Class A
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss attributable to AMR Class A common stockholders	$ 2,245	$ (6,600)	$ (19,930)	$ (6,162)
Net loss attributable to noncontrolling interests assumed to be redeemed for Class A Common Stock, net of tax	0	(2,157)	(4,914)	0
Net loss attributable to AMR Class A common stockholders after assumed redemption	$ 2,245	$ (8,757)	$ (24,844)	$ (6,162)
Weighted average Class A common shares outstanding (Basic) (in shares)	180,742,049	173,345,982	171,908,486	180,505,318
Class A shares assumed issued to holders of noncontrolling interests upon redemption (in shares)	0	34,619,947	36,204,221	0
Weighted average common shares outstanding (Diluted) (in shares)	180,742,049	207,965,929	208,112,707	180,505,318
Income (loss) per common share attributable to AMR common stockholders:
Basic (in USD per share)	$ 0.01	$ (0.04)	$ (0.12)	$ (0.03)
Diluted (in USD per share)	$ 0.01	$ (0.04)	$ (0.12)	$ (0.03)

XML

Business Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		5 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Dec. 31, 2018
Revenue
Operating revenue	$ 133,305	$ 111,482	$ 169,372	$ 269,134
Gain (loss) on sale of assets	0	(63)	5,076	1,483
Gain (loss) on derivatives	12,412	(29,219)	(51,230)	(11,365)
Total revenue	145,717	82,200	123,218	259,252
Operating expenses
Lease operating	15,114	12,679	20,996	35,058
Transportation, processing and marketing	6,837	5,396	8,755	11,440
Midstream operating	6,520	3,313	3,900	12,671
Cost of sales for purchased gathered production	8,720	8,902	12,711	18,415
Production taxes	5,117	2,606	4,021	10,600
Workovers	807	333	1,578	1,120
Exploration	3,289	8,083	9,668	5,343
Depreciation, depletion and amortization	38,009	33,934	49,613	75,908
General and administrative	27,172	22,456	60,208	56,690
Total operating expenses	118,085	97,702	171,450	233,745
Operating income	27,632	(15,502)	(48,232)	25,507
Other income (expense)
Interest expense	(16,755)	(11,779)	(17,223)	(32,215)
Interest income	79	824	1,370	130
Equity in earnings of unconsolidated subsidiaries	643	0	0	742
Total other income (expense), net	(16,033)	(10,955)	(15,853)	(31,343)
Income (loss) from continuing operations before income taxes	11,599	(26,457)	(64,085)	(5,836)
Interest expense	16,755	11,779	17,223	32,215
Depreciation, depletion and amortization	38,009	33,934	49,613	75,908
Equity-based compensation expense	840	4,263	7,729	3,519
Exploration	3,289	8,083	9,668	5,343
Equity method investment at period end	1,842			1,842	$ 1,100
Capital expenditures			340,631	247,942
Total assets at period end	1,452,057			1,452,057	$ 1,357,830
Oil
Revenue
Operating revenue	90,668	75,291	115,569	177,031
Natural gas
Revenue
Operating revenue	12,384	7,980	13,190	30,834
Natural gas liquids
Revenue
Operating revenue	10,251	10,241	14,955	21,467
Sales of gathered production
Revenue
Operating revenue	10,439	8,924	12,797	19,999
Other revenue
Revenue
Operating revenue	3,014	2,229	2,784	6,099
Operating Segments
Revenue
Operating revenue	133,305	111,482	169,372	269,134
Gain (loss) on sale of assets	0	(63)	5,076
Gain (loss) on derivatives	12,412	(29,219)	(51,230)	(11,365)
Total revenue	145,717	82,200	123,218	259,252
Operating expenses
Lease operating	15,114	12,679	20,996	35,058
Transportation, processing and marketing	6,837	5,396	8,755	11,440
Midstream operating	6,520	3,313	3,900	12,671
Cost of sales for purchased gathered production	8,720	8,902	12,711	18,415
Production taxes	5,117	2,606	4,021	10,600
Workovers	807	333	1,578	1,120
Exploration	3,289	8,083	9,668	5,343
Depreciation, depletion and amortization	38,009	33,934	49,613	75,908
Impairment of assets	6,500	0	0	6,500
General and administrative	27,172	22,456	60,208	56,690
Total operating expenses	118,085	97,702	171,450	233,745
Operating income	27,632	(15,502)	(48,232)	25,507
Other income (expense)
Interest expense	(16,755)	(11,779)	(17,223)	(32,215)
Interest income	79	824	1,370	130
Equity in earnings of unconsolidated subsidiaries	643			742
Total other income (expense), net	(16,033)	(10,955)	(15,853)	(31,343)
Income (loss) from continuing operations before income taxes	11,599	(26,457)	(64,085)	(5,836)
Interest expense	16,755	11,779	17,223	32,215
Depreciation, depletion and amortization	38,009	33,934	49,613	75,908
(Gain) loss on unrealized hedges	(11,868)	14,860	32,896	12,274
Gain on sale of assets			63	1,483
Equity-based compensation expense	840	4,263	7,729	3,519
Severance costs	697			6,568
Strategic costs	4,061			4,061
Exploration	3,289	8,083	9,668	5,343
Business Combination related expense		443	23,717	10
Adjusted EBITDAX	69,882	46,905	76,824	140,562
Equity method investment at period end	1,842			1,842
Capital expenditures	86,594	207,576	340,631	247,942
Total assets at period end	1,452,057	4,253,658	4,253,658	1,452,057
Operating Segments | Oil
Revenue
Operating revenue	90,668	75,291	115,569	177,031
Operating Segments | Natural gas
Revenue
Operating revenue	12,384	7,980	13,190	30,834
Operating Segments | Natural gas liquids
Revenue
Operating revenue	10,251	10,241	14,955	21,467
Operating Segments | Sales of gathered production
Revenue
Operating revenue	10,439	8,924	12,797	19,999
Operating Segments | Midstream revenue
Revenue
Operating revenue	6,549	6,817	10,077	13,704
Operating Segments | Segment sales revenue
Revenue
Operating revenue	130,291	109,253	166,588	263,035
Operating Segments | Other revenue
Revenue
Operating revenue	3,014	2,229	2,784	6,099
Operating Segments | Exploration & Production
Revenue
Operating revenue	113,633	95,741	146,498	230,230
Gain (loss) on sale of assets	0	(63)	5,076
Gain (loss) on derivatives	12,412	(29,219)	(51,230)	(11,365)
Total revenue	126,045	66,459	100,344	220,348
Operating expenses
Lease operating	19,123	12,679	20,996	44,231
Transportation, processing and marketing	19,614	11,205	16,788	37,375
Midstream operating	0	0	0	0
Cost of sales for purchased gathered production	0	0	0	0
Production taxes	5,117	2,606	4,021	10,600
Workovers	412	333	1,578	609
Exploration	3,289	8,083	9,668	5,343
Depreciation, depletion and amortization	34,504	26,670	37,708	69,179
Impairment of assets	6,500	0	0	6,500
General and administrative	15,723	17,811	52,465	36,670
Total operating expenses	104,282	79,387	143,224	210,507
Operating income	21,763	(12,928)	(42,880)	9,841
Other income (expense)
Interest expense	(14,071)	(10,361)	(15,557)	(26,901)
Interest income	54	820	1,366	81
Equity in earnings of unconsolidated subsidiaries	0			0
Total other income (expense), net	(14,017)	(9,541)	(14,191)	(26,820)
Income (loss) from continuing operations before income taxes	7,746	(22,469)	(57,071)	(16,979)
Interest expense	14,071	10,361	15,557	26,901
Depreciation, depletion and amortization	34,504	26,670	37,708	69,179
(Gain) loss on unrealized hedges	(11,868)	14,860	32,896	12,274
Gain on sale of assets			63	1,483
Equity-based compensation expense	1,396	3,621	6,389	3,057
Severance costs	609			4,584
Strategic costs	4,061			4,061
Exploration	3,289	8,083	9,668	5,343
Business Combination related expense		443	23,717	10
Adjusted EBITDAX	60,308	41,569	68,927	114,930
Equity method investment at period end	0			0
Capital expenditures	47,061	189,732	319,042	180,138
Total assets at period end	999,744	2,817,714	2,817,714	999,744
Operating Segments | Exploration & Production | Oil
Revenue
Operating revenue	90,668	75,291	115,569	177,031
Operating Segments | Exploration & Production | Natural gas
Revenue
Operating revenue	12,384	7,980	13,190	30,834
Operating Segments | Exploration & Production | Natural gas liquids
Revenue
Operating revenue	10,251	10,241	14,955	21,467
Operating Segments | Exploration & Production | Sales of gathered production
Revenue
Operating revenue	0	0	0	0
Operating Segments | Exploration & Production | Midstream revenue
Revenue
Operating revenue	0	0	0	0
Operating Segments | Exploration & Production | Segment sales revenue
Revenue
Operating revenue	113,303	93,512	143,714	229,332
Operating Segments | Exploration & Production | Other revenue
Revenue
Operating revenue	330	2,229	2,784	898
Operating Segments | Midstream revenue
Revenue
Operating revenue	39,244	36,873	55,305	78,861
Gain (loss) on sale of assets	0	0	0
Gain (loss) on derivatives	0	0	0	0
Total revenue	39,244	36,873	55,305	78,861
Operating expenses
Lease operating	0	0	0	0
Transportation, processing and marketing	2,786	3,223	5,561	4,849
Midstream operating	6,520	3,313	3,900	12,671
Cost of sales for purchased gathered production	8,720	21,002	31,548	18,415
Production taxes	0	0	0	0
Workovers	395	0	0	511
Exploration	0	0	0	0
Depreciation, depletion and amortization	3,505	7,264	11,905	6,729
Impairment of assets	0	0	0	0
General and administrative	5,324	4,140	6,313	13,387
Total operating expenses	27,250	38,942	59,227	56,562
Operating income	11,994	(2,069)	(3,922)	22,299
Other income (expense)
Interest expense	(2,684)	(1,418)	(1,666)	(5,314)
Interest income	6	0	0	10
Equity in earnings of unconsolidated subsidiaries	643			742
Total other income (expense), net	(2,035)	(1,418)	(1,666)	(4,562)
Income (loss) from continuing operations before income taxes	9,959	(3,487)	(5,588)	17,737
Interest expense	2,684	1,418	1,666	5,314
Depreciation, depletion and amortization	3,505	7,264	11,905	6,729
(Gain) loss on unrealized hedges	0	0	0	0
Gain on sale of assets			0	0
Equity-based compensation expense	(556)	465	507	462
Severance costs	88			1,984
Strategic costs	0			0
Exploration	0	0	0	0
Business Combination related expense		0	0	0
Adjusted EBITDAX	15,680	5,660	8,490	32,226
Equity method investment at period end	1,842			1,842
Capital expenditures	39,533	17,844	21,589	67,804
Total assets at period end	458,882	1,427,792	1,427,792	458,882
Operating Segments | Midstream revenue | Oil
Revenue
Operating revenue	0	0	0	0
Operating Segments | Midstream revenue | Natural gas
Revenue
Operating revenue	0	0	0	0
Operating Segments | Midstream revenue | Natural gas liquids
Revenue
Operating revenue	0	0	0	0
Operating Segments | Midstream revenue | Sales of gathered production
Revenue
Operating revenue	10,439	21,024	31,634	19,999
Operating Segments | Midstream revenue | Midstream revenue
Revenue
Operating revenue	22,112	15,849	23,671	44,488
Operating Segments | Midstream revenue | Segment sales revenue
Revenue
Operating revenue	32,551	36,873	55,305	64,487
Operating Segments | Midstream revenue | Other revenue
Revenue
Operating revenue	6,693	0	0	14,374
Eliminations
Revenue
Operating revenue	(19,572)	(21,132)	(32,431)	(39,957)
Gain (loss) on sale of assets	0	0	0
Gain (loss) on derivatives	0	0	0	0
Total revenue	(19,572)	(21,132)	(32,431)	(39,957)
Operating expenses
Lease operating	(4,009)	0	0	(9,173)
Transportation, processing and marketing	(15,563)	(9,032)	(13,594)	(30,784)
Midstream operating	0	0	0	0
Cost of sales for purchased gathered production	0	(12,100)	(18,837)	0
Production taxes	0	0	0	0
Workovers	0	0	0	0
Exploration	0	0	0	0
Depreciation, depletion and amortization	0	0	0	0
Impairment of assets	0	0	0	0
General and administrative	6,125	505	1,430	6,633
Total operating expenses	(13,447)	(20,627)	(31,001)	(33,324)
Operating income	(6,125)	(505)	(1,430)	(6,633)
Other income (expense)
Interest expense	0	0	0	0
Interest income	19	4	4	39
Equity in earnings of unconsolidated subsidiaries	0			0
Total other income (expense), net	19	4	4	39
Income (loss) from continuing operations before income taxes	(6,106)	(501)	(1,426)	(6,594)
Interest expense	0	0	0	0
Depreciation, depletion and amortization	0	0	0	0
(Gain) loss on unrealized hedges	0	0	0	0
Gain on sale of assets			0	0
Equity-based compensation expense	0	177	833	0
Severance costs	0			0
Strategic costs	0			0
Exploration	0	0	0	0
Business Combination related expense		0	0	0
Adjusted EBITDAX	(6,106)	(324)	(593)	(6,594)
Equity method investment at period end	0			0
Capital expenditures	0	0	0	0
Total assets at period end	(6,569)	8,152	8,152	(6,569)
Eliminations | Oil
Revenue
Operating revenue	0	0	0	0
Eliminations | Natural gas
Revenue
Operating revenue	0	0	0	0
Eliminations | Natural gas liquids
Revenue
Operating revenue	0	0	0	0
Eliminations | Sales of gathered production
Revenue
Operating revenue	0	(12,100)	(18,837)	0
Eliminations | Midstream revenue
Revenue
Operating revenue	(15,563)	(9,032)	(13,594)	(30,784)
Eliminations | Segment sales revenue
Revenue
Operating revenue	(15,563)	(21,132)	(32,431)	(30,784)
Eliminations | Other revenue
Revenue
Operating revenue	$ (4,009)	$ 0	$ 0	$ (9,173)

XML

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	1 Months Ended	5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Feb. 08, 2018
Asset Retirement Obligation [Line Items]
Balance, beginning of period		$ 0	$ 11,552
Liabilities assumed in Business Combination		5,998	0
Liabilities incurred		877	634
Liabilities settled		(806)	(162)
Liabilities transferred in sale of properties		(20)	0
Revisions to estimates		665	(8)
Accretion expense		263	470
Balance, end of period		0	$ 11,552	$ 12,486	$ 11,552	$ 6,977	$ 0
Less: current portion				44	2,079	538
Long-term portion				$ 12,442	$ 9,473	$ 6,439
Predecessor
Asset Retirement Obligation [Line Items]
Balance, beginning of period	$ 10,469	10,509
Liabilities assumed in Business Combination	0
Liabilities incurred	0
Liabilities settled	(63)
Liabilities transferred in sale of properties	0
Revisions to estimates	63
Accretion expense	40
Balance, end of period	$ 10,469	$ 10,509					10,509
Less: current portion							33
Long-term portion							$ 10,476

XML

Significant Concentrations (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Dec. 31, 2018
Concentration Risk [Line Items]
Revenues		$ 145,717	$ 82,200	$ 123,218	$ 259,252
AEM
Concentration Risk [Line Items]
Revenues		25,833	90,206	131,422	119,224
Fees paid		218	209	283	411
Total fees paid to ARM		737	209	283	1,627
Accounts receivable		6,600			6,600	$ 43,800
Marketing fees | AEM
Concentration Risk [Line Items]
Fees paid		$ 519	$ 0	$ 0	$ 1,216
Predecessor
Concentration Risk [Line Items]
Revenues	$ 47,639
Predecessor | AEM
Concentration Risk [Line Items]
Revenues	28,757
Fees paid	66
Total fees paid to ARM	66
Predecessor | Marketing fees | AEM
Concentration Risk [Line Items]
Fees paid	$ 0

XML

Equity-Based Compensation (Successor)

6 Months Ended

Jun. 30, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity-Based Compensation (Successor)

EQUITY-BASED COMPENSATION (Successor)

Stock compensation expense recognized was as follows:

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Stock options	$	660	$	1,722	$	1,899	$	2,787	$	—
Restricted stock awards	35		1,260		1,468		2,493		—
Performance-based restricted stock units	145		1,281		152		2,449		—
Total compensation expense	$	840	$	4,263	$	3,519	$	7,729	$	—

Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year is based on achievement of annual company-specific performance goals and obligations applicable to each year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest range from 0% to 200% of the target growth applicable to each vesting period. The performance goals set for the 2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted.

The performance targets for the 2019 tranche of performance-based restricted stock units were established in March 2019 and 572,990 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment.

No performance targets have yet been established for the 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established and probability of attainment can be measured.

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Adoption of ASU No. 2016-02, Leases (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Schedule of Practical Expedients

Upon adoption, we selected the following practical expedients:

Practical expedient package	We did not reassess whether any expired or existing contracts are, or contain, leases.
	We did not reassess the lease classification of any expired or existing leases.
	We did not reassess initial direct costs of any expired or existing leases.
Hindsight practical expedient	We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.
Easement expedient	We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.
Combining lease and non-lease components expedient	We elected to account for lease and non-lease components as a single component.
Short-term lease expedient	We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.

Lease Cost

Lease Costs

(in thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	$	828	$	1,675
Variable lease cost	478		849
Short-term lease cost	1,071		3,686
Total lease cost	$	2,377	$	6,210
Reported in:
Lease operating expense	$	1,029	$	3,675
General and administrative expense	1,348		2,535
Total lease cost	$	2,377	$	6,210

Maturities of Operating Lease Liabilities

Operating Lease Liability Maturities as of June 30, 2019

Fiscal year	(in thousands)
Remainder of 2019	$	1,528
2020	3,081
2021	3,048
2022	3,108
2023	2,718
Thereafter	12,647
Total lease payments	26,130
Less: imputed interest	(11,150		)
Present value of operating lease liabilities	$	14,980
Current portion of operating lease liabilities	$	1,018
Operating lease liabilities, net of current portion	13,962
Present value of operating lease liabilities	$	14,980

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS 

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Balance, beginning of period	$	11,552		$	—		$	10,469
Liabilities assumed in Business Combination	—			5,998			—
Liabilities incurred	634			877			—
Liabilities settled	(162		)	(806		)	(63		)
Liabilities transferred in sale of properties	—			(20		)	—
Revisions to estimates	(8		)	665			63
Accretion expense	470			263			40
Balance, end of period	12,486			6,977			10,509
Less: current portion	44			538			33
Long-term portion	$	12,442		$	6,439		$	10,476

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Adoption of ASU No. 2016-02, Leases

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Adoption of ASU No. 2016-02, Leases

ADOPTION OF ASU NO. 2016-02, LEASES

ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on our balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method as of January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities totaling $15.4 million each. There was no adjustment to beginning retained earnings.

We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not currently sublease any of our ROU assets, although we may sublease our unused office lease space in the future.

Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred.

Upon adoption, we selected the following practical expedients:

Practical expedient package	We did not reassess whether any expired or existing contracts are, or contain, leases.
	We did not reassess the lease classification of any expired or existing leases.
	We did not reassess initial direct costs of any expired or existing leases.
Hindsight practical expedient	We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.
Easement expedient	We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.
Combining lease and non-lease components expedient	We elected to account for lease and non-lease components as a single component.
Short-term lease expedient	We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.

As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At June 30, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.1 years and the weighted-average discount rate applied was 14.3%.

Lease Costs

(in thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	$	828	$	1,675
Variable lease cost	478		849
Short-term lease cost	1,071		3,686
Total lease cost	$	2,377	$	6,210
Reported in:
Lease operating expense	$	1,029	$	3,675
General and administrative expense	1,348		2,535
Total lease cost	$	2,377	$	6,210

Operating Lease Liability Maturities as of June 30, 2019

Fiscal year	(in thousands)
Remainder of 2019	$	1,528
2020	3,081
2021	3,048
2022	3,108
2023	2,718
Thereafter	12,647
Total lease payments	26,130
Less: imputed interest	(11,150		)
Present value of operating lease liabilities	$	14,980
Current portion of operating lease liabilities	$	1,018
Operating lease liabilities, net of current portion	13,962
Present value of operating lease liabilities	$	14,980

As described further in our 2018 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter.

Right-of-Use Asset Impairment

During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We sought to sublease the unused office space within three buildings but we were unable to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.

We also expect to attempt to reject certain of the leases pursuant to our Bankruptcy filing which could decrease our lease liability if we are successful with the rejection.

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Property And Equipment

6 Months Ended

Jun. 30, 2019

Property, Plant and Equipment [Abstract]

Property And Equipment

PROPERTY AND EQUIPMENT

(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	76,665		$	74,217
Proved oil and gas properties	2,196,605			2,110,346
Accumulated depletion and impairment	(1,489,191		)	(1,421,226		)
Proved oil and gas properties, net	707,414			689,120
Total oil and gas properties, net	784,079			763,337
Other property and equipment
Land	5,600			5,600
Fresh water wells	27,373			27,366
Produced water disposal system	106,467			104,498
Gas processing plant and gathering lines	412,193			380,470
Office furniture, equipment and vehicles	3,755			3,703
Accumulated depreciation and impairment	(84,841		)	(77,368		)
Other property and equipment, net	470,547			444,269
Total property and equipment, net	$	1,254,626		$	1,207,606

Depletion and Depreciation Expense

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	33,923	$	26,086	$	67,965	$	36,859	$	11,021
Midstream tangible asset depreciation	3,504		2,010		6,724		3,132		—
Other property and equipment depreciation	341		423		749		586		609
Total depletion and depreciation	$	37,768	$	28,519	$	75,438	$	40,577	$	11,630

Impairment

During the three months ended June 30, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment of our long-lived assets. Therefore, we did not conduct further analysis on the recognition of additional impairment.

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Description of Business and Basis of Presentation

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business and Basis of Presentation

DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Alta Mesa Resources, Inc., together with its consolidated subsidiaries (“we” or “the Company”), is an independent exploration and production company focused on the acquisition, development, exploration and production of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. We also operate in the Midstream segment through Kingfisher Midstream, LLC (“KFM”). KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The KFM midstream assets are integral to our Upstream operations, which we conduct in the same region, and they are 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, exchange, acquisition, purchase, reorganization or similar business combination involving it and one or more businesses. On February 9, 2018 we acquired interests in Alta Mesa, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and KFM through a newly formed subsidiary, SRII Opco, LP (“SRII Opco”) in a transaction referred to as the “Business Combination”, and changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.” As a result of our failure to comply with the continued listing requirements of the NASDAQ Capital Market (“NASDAQ”), trading in our Class A Common Stock and public warrants was suspended on September 24, 2019, and they are now traded over the counter under the trading symbols “AMRQQ” and “AMRWQ,” respectively. 

In connection with the closing of the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and associated liabilities to its prior owner, High Mesa Holdings, LP (“High Mesa”). The non-STACK assets and liabilities are reflected as discontinued operations in the Predecessor portion of our financial statements.

All intercompany transactions and accounts have been eliminated. These interim condensed consolidated financial statements are unaudited, but we believe these statements reflect all adjustments necessary for a fair presentation of the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These financial statements and disclosures have been prepared in accordance with the SEC’s rules for interim financial statements and do not include all the information and disclosures required by generally accepted accounting principles (“GAAP”) for complete financial statements. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three and six months ended June 30, 2019 are not necessarily indicative of the results to be expected for the full year. We have no items of other comprehensive income during any period presented. Certain prior period amounts have been reclassified to conform to the current period presentation.

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Condensed Consolidated Balance Sheets (Unaudited) Condensed Consolidated Balance Sheet (Unaudited) Parenthetical - $ / shares	Jun. 30, 2019	Dec. 31, 2018
Preferred Stock (USD per share)	$ 0.0001	$ 0.0001
Preferred Class A
Preferred Stock, shares authorized (in shares)	1,000,000	1,000,000
Preferred Stock, shares issued (in shares)	3	3
Preferred Stock, shares outstanding (in shares)	2	2
Preferred Class B
Preferred Stock, shares authorized (in shares)	1,000,000	1,000,000
Preferred Stock, shares issued (in shares)	1	1
Preferred Stock, shares outstanding (in shares)	1	1
Common Stock par value (in dollars per share)	$ 0.0001	$ 0.0001
Common Class A
Common Stock, shares authorized (in shares)	1,200,000,000	1,200,000,000
Common Stock, shares issued (in shares)	182,636,433	180,072,227
Common Stock, shares outstanding (in shares)	182,636,433	180,072,227
Common Class C
Common Stock, shares authorized (in shares)	280,000,000	280,000,000
Common Stock, shares issued (in shares)	199,987,976	202,169,576
Common Stock, shares outstanding (in shares)	199,987,976	202,169,576

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Equity-Based Compensation (Successor) (Tables)

6 Months Ended

Jun. 30, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock compensation expense recognized

Stock compensation expense recognized was as follows:

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Stock options	$	660	$	1,722	$	1,899	$	2,787	$	—
Restricted stock awards	35		1,260		1,468		2,493		—
Performance-based restricted stock units	145		1,281		152		2,449		—
Total compensation expense	$	840	$	4,263	$	3,519	$	7,729	$	—

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Accounts Payable And Accrued Liabilities (Tables)

6 Months Ended

Jun. 30, 2019

Payables and Accruals [Abstract]

Detail Of Accounts Payable And Accrued Liabilities

(in thousands)	June 30, 2019		December 31, 2018
Accounts payable	$	12,526	$	20,422
Accruals for capital expenditures	22,669		139,904
Revenue and royalties payable	41,304		50,241
Accruals for operating expenses	14,853		21,830
Accrued interest	6,922		2,477
Derivative settlements	743		109
Other	10,884		12,456
Total accrued liabilities	97,375		227,017
Accounts payable and accrued liabilities	$	109,901	$	247,439

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Discontinued Operations (Total Operating And Investing Cash Flows Of Discontinued Operations) (Details) - Predecessor - Weeks Island Field, Louisiana - Disposed of by Sale $ in Thousands	1 Months Ended
	Feb. 08, 2018 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total operating cash flows of discontinued operations	$ 2,974
Total investing cash flows of discontinued operations	$ (601)

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Derivatives (Oil Derivative Contracts) (Details) - Oil Derivative Contracts	6 Months Ended
	Jun. 30, 2019 $ / bbl bbl
Price Swap Contracts | 2019
Derivative [Line Items]
Volume in Bbls | bbl	92,000
Weighted Average Swap Price (USD per unit)	63.03
Price Swap Contracts | 2019 | High
Derivative [Line Items]
Swap Price (USD per unit)	63.03
Price Swap Contracts | 2019 | Low
Derivative [Line Items]
Swap Price (USD per unit)	63.03
Short Call Options | 2019
Derivative [Line Items]
Volume in Bbls | bbl	1,361,600
Weighted Average Option Price (USD per unit)	66.31
Short Call Options | 2019 | High
Derivative [Line Items]
Option Price (USD per unit)	75.20
Short Call Options | 2019 | Low
Derivative [Line Items]
Option Price (USD per unit)	56.50
Short Call Options | 2020
Derivative [Line Items]
Volume in Bbls | bbl	1,017,600
Weighted Average Option Price (USD per unit)	63.95
Short Call Options | 2020 | High
Derivative [Line Items]
Option Price (USD per unit)	73.80
Short Call Options | 2020 | Low
Derivative [Line Items]
Option Price (USD per unit)	59.55
Short Call Options | 2021
Derivative [Line Items]
Volume in Bbls | bbl	279,750
Weighted Average Option Price (USD per unit)	63.51
Short Call Options | 2021 | High
Derivative [Line Items]
Option Price (USD per unit)	63.75
Short Call Options | 2021 | Low
Derivative [Line Items]
Option Price (USD per unit)	63.35
Long Put Options | 2019
Derivative [Line Items]
Volume in Bbls | bbl	1,453,600
Weighted Average Option Price (USD per unit)	53.80
Long Put Options | 2019 | High
Derivative [Line Items]
Option Price (USD per unit)	62.00
Long Put Options | 2019 | Low
Derivative [Line Items]
Option Price (USD per unit)	50.00
Long Put Options | 2020
Derivative [Line Items]
Volume in Bbls | bbl	1,566,600
Weighted Average Option Price (USD per unit)	56.81
Long Put Options | 2020 | High
Derivative [Line Items]
Option Price (USD per unit)	62.50
Long Put Options | 2020 | Low
Derivative [Line Items]
Option Price (USD per unit)	50.00
Long Put Options | 2021
Derivative [Line Items]
Volume in Bbls | bbl	659,850
Weighted Average Option Price (USD per unit)	46.94
Long Put Options | 2021 | High
Derivative [Line Items]
Option Price (USD per unit)	55.00
Long Put Options | 2021 | Low
Derivative [Line Items]
Option Price (USD per unit)	41.00
Short Put Options | 2019
Derivative [Line Items]
Volume in Bbls | bbl	1,453,600
Weighted Average Option Price (USD per unit)	42.72
Short Put Options | 2019 | High
Derivative [Line Items]
Option Price (USD per unit)	52.00
Short Put Options | 2019 | Low
Derivative [Line Items]
Option Price (USD per unit)	37.50
Short Put Options | 2020
Derivative [Line Items]
Volume in Bbls | bbl	1,566,600
Weighted Average Option Price (USD per unit)	42.81
Short Put Options | 2020 | High
Derivative [Line Items]
Option Price (USD per unit)	50.00
Short Put Options | 2020 | Low
Derivative [Line Items]
Option Price (USD per unit)	37.50
Short Put Options | 2021
Derivative [Line Items]
Volume in Bbls | bbl	279,750
Weighted Average Option Price (USD per unit)	43.00
Short Put Options | 2021 | High
Derivative [Line Items]
Option Price (USD per unit)	43.00
Short Put Options | 2021 | Low
Derivative [Line Items]
Option Price (USD per unit)	43.00

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Earnings (Loss) Per Share

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Earnings (Loss) Per Share

EARNINGS (LOSS) PER SHARE

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:

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018
	(in thousands, except shares and per share data)
Net income (loss) attributable to AMR Class A common stockholders	$	2,245	$	(6,600	)	$	(6,162	)	$	(19,930	)
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 income (loss) attributable to AMR Class A common stockholders after assumed redemption	$	2,245	$	(8,757	)	$	(6,162	)	$	(24,844	)
Weighted average Class A common shares outstanding (Basic)	180,742,049		173,345,982			180,505,318			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)	180,742,049		207,965,929			180,505,318			208,112,707
Income (loss) per common share attributable to AMR common stockholders:
Basic	$	0.01	$	(0.04	)	$	(0.03	)	$	(0.12	)
Diluted	$	0.01	$	(0.04	)	$	(0.03	)	$	(0.12	)

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Discontinued Operations

6 Months Ended

Jun. 30, 2019

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

DISCONTINUED OPERATIONS (Predecessor)

The results of operations of the non-STACK oil and gas assets and related liabilities distributed to High Mesa immediately prior to the Business Combination and presented as discontinued operations during the Predecessor Period were as follows:

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Revenue
Oil	$	1,617
Natural gas	1,023
Natural gas liquids	236
Other	16
Operating revenue	2,892
Loss on sale of assets	(1,923		)
Total revenue	969
Operating expenses
Lease operating	1,770
Transportation and marketing	83
Production taxes	167
Workovers	127
Depreciation, depletion and amortization	884
Impairment of assets	5,560
General and administrative	21
Total operating expenses	8,612
Other expense
Interest expense	(103		)
Loss from discontinued operations, net of tax	$	(7,746	)

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Total operating cash flows of discontinued operations	$	2,974
Total investing cash flows of discontinued operations	(601		)

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Debt

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Debt

DEBT

໿

(in thousands)	June 30, 2019		December 31, 2018
Alta Mesa RBL	$	344,500	$	161,000
KFM Credit Facility	218,000		174,000
2024 Notes	500,000		500,000
Unamortized premium on 2024 Notes	26,662		29,123
Total debt, net	1,089,162		864,123
Less: Current portion	1,089,162		690,123
Long-term debt, net	$	—	$	174,000

Alta Mesa RBL

In April 2019, our borrowing base under the Alta Mesa RBL was reduced from $400.0 million to $370.0 million, leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200.0 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. As indicated in our discussion of going concern, we and the AMH Debtors filed for bankruptcy protection prior to making these payments.

The Alta Mesa RBL has two covenants that are tested quarterly:

• a ratio of Alta Mesa’s current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and

• a ratio of Alta Mesa’s consolidated debt to its consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0. 

Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the Alta Mesa RBL that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the lenders under the Alta Mesa RBL are stayed from taking any action against the AMH Debtors as a result of an event of default.

KFM Credit Facility

The KFM Credit Facility, as amended, provides for an aggregate committed borrowing capacity of $300.0 million.

There are two maintenance covenants under the KFM Credit Facility that are tested quarterly:

• a ratio of KFM’s total debt to its consolidated adjusted EBITDA of not greater than 4.5 to 1.0, (which increases to 4.75 after KFM exceeds consolidated EBITDA of $75.0 million) for any 4 quarter period; and

• a minimum interest coverage ratio of KFM’s adjusted EBITDA to interest expense of not less than 2.5 to 1.0.

The KFM Credit Facility also limits KFM to holding no more than $15.0 million in cash and limits its ability to amend affiliate contracts. Our bankruptcy filing did not constitute an event of default under the KFM Credit Facility.

At August 31, 2019, remaining borrowing capacity under the KFM Credit Facility totaled $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.

2024 Notes

We have estimated the fair value of the 2024 Notes to be $193.8 million at June 30, 2019, which is based on their most recent trading values, which is a Level 1 determination.

Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default including acceleration.

Scheduled Maturities of Debt

Fiscal year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	562,500
Thereafter	500,000
	$	1,062,500

Based upon our going concern conclusions and the default associated with Alta Mesa’s bankruptcy filing, we believe that our indebtedness under the Alta Mesa RBL and our 2024 Notes should be reported as current liabilities despite their scheduled maturities shown above. We have reported our Alta Mesa RBL debt and our 2024 Notes as current at June 30, 2019. In addition, based on the factors described under “KFM Credit Facility” above, we have also reported all of our Midstream debt as current at June 30, 2019 despite the scheduled maturities shown above.

XML

Condensed Consolidated Statements Of Cash Flows (Unaudited) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended	12 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Dec. 31, 2018
Net income (loss)		$ 11,599	$ (22,666)	$ (56,420)	$ (5,836)
Cash flows from operating activities:
Net loss		2,245	(6,600)	(19,930)	(6,162)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization				49,613	75,908
Non-cash lease expense				0	1,675
Provision for uncollectible receivables				0	1,177
Impairment of assets				0	6,500
Amortization of deferred financing costs				152	368
Amortization of debt premium				(2,051)	(2,462)
Equity-based compensation expense		840	4,263	7,729	3,519
Non-cash exploration expense				7,288	388
(Gain) loss on derivatives		(12,412)	29,219	51,230	11,365
Cash settlements of derivatives				18,334	(909)
Premium paid on derivatives				0	(1,000)
Interest converted into debt				0	0
Interest added to notes receivable from affiliate				(417)	0
Deferred tax provision (benefit)				(7,665)	0
Loss on sale of fixed assets				63	114
Equity in earnings of unconsolidated subsidiaries		(643)	0	0	(742)
Impact on cash from changes in:
Accounts receivable				(9,143)	13,744
Other receivables				996	2,696
Related party receivables				(6,260)	179
Prepaid expenses and other assets				8,116	(4,426)
Advances from related party				(10,371)	(154)
Settlement of asset retirement obligations				(806)	(5,835)
Accounts payable, accrued liabilities and other liabilities				(78,542)	(12,123)
Operating lease obligations				0	(1,376)
Cash from operating activities				(64,822)	84,588
Cash flows from investing activities:
Capital expenditures				(340,631)	(247,942)
Acquisitions, net of cash acquired				(791,819)	0
Proceeds withdrawn from trust account				1,042,742	0
Investment in equity affiliate and other, net				(6,945)	0
Cash from investing activities				(96,653)	(247,942)
Cash flows from financing activities:
Proceeds from long-term debt borrowings				80,000	227,500
Repayments of long-term debt				(193,565)	0
Deferred financing costs paid				(3,670)	0
Capital distributions				0	0
Proceeds from issuance of Class A shares				400,000	0
Repayment of sponsor note				(2,000)	0
Repayment of deferred underwriting compensation				(36,225)	0
Redemption of Class A common shares				(33)	0
Cash from financing activities				244,507	227,500
Net increase in cash, cash equivalents and restricted cash				83,032	64,146
Cash, cash equivalents and restricted cash, beginning of period				388	27,855
Cash, cash equivalents and restricted cash, end of period	$ 388	$ 92,001	$ 83,420	83,420	$ 92,001	$ 27,855
Predecessor
Net income (loss)	(14,862)
Cash flows from operating activities:
Net loss	(14,862)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	12,554
Non-cash lease expense	0
Provision for uncollectible receivables	0
Impairment of assets	5,560
Amortization of deferred financing costs	171
Amortization of debt premium	0
Equity-based compensation expense	0
Non-cash exploration expense	4,575
(Gain) loss on derivatives	(6,663)
Cash settlements of derivatives	2,296
Premium paid on derivatives	0
Interest converted into debt	103
Interest added to notes receivable from affiliate	(85)
Deferred tax provision (benefit)	0
Loss on sale of fixed assets	1,923
Equity in earnings of unconsolidated subsidiaries	0
Impact on cash from changes in:
Accounts receivable	(21,184)
Other receivables	(662)
Related party receivables	(117)
Prepaid expenses and other assets	(591)
Advances from related party	24,116
Settlement of asset retirement obligations	(63)
Accounts payable, accrued liabilities and other liabilities	23,857
Operating lease obligations	0
Cash from operating activities	26,336
Cash flows from investing activities:
Capital expenditures	(36,695)
Acquisitions, net of cash acquired	(1,218)
Proceeds withdrawn from trust account	0
Investment in equity affiliate and other, net	0
Cash from investing activities	(37,913)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	60,000
Repayments of long-term debt	(43,000)
Deferred financing costs paid	0
Capital distributions	(68)
Proceeds from issuance of Class A shares	0
Repayment of sponsor note	0
Repayment of deferred underwriting compensation	0
Redemption of Class A common shares	0
Cash from financing activities	16,932
Net increase in cash, cash equivalents and restricted cash						5,355
Cash, cash equivalents and restricted cash, beginning of period	4,990			$ 10,345		$ 4,990
Cash, cash equivalents and restricted cash, end of period	$ 10,345

XML

Significant Concentrations (Tables)

6 Months Ended

Jun. 30, 2019

Significant Concentrations [Abstract]

Schedule of Significant Concentrations

ARM has also provided us with strategic advice, execution and reporting services with respect to our derivatives activities.

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	25,833	$	90,206	$	119,224	$	131,422	$	28,757
Marketing and management fees paid to ARM	$	519	$	—	$	1,216	$	—	$	—
Fees paid to ARM for services relating to our derivatives	218		209		411		283		66
Total fees paid to ARM	$	737	$	209	$	1,627	$	283	$	66

XML

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2019	Aug. 31, 2019
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	001-38040
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	81-4433840
Entity Address, Address Line One	15021 Katy Freeway,
Entity Address, Address Line Two	Suite 400,
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77094
City Area Code	281
Local Phone Number	530-0991
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Registrant Name	Alta Mesa Resources, Inc. /DE
Entity Central Index Key	0001690769
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Common Class A
Entity Information [Line Items]
Title of 12(b) Security	Class A Common Stock, par value $0.0001 per share
Trading Symbol	AMRQQ
Entity Common Stock, Shares Outstanding (in shares)		182,755,573
Warrants
Entity Information [Line Items]
Title of 12(b) Security	Warrants to purchase one share of Class A Common Stock
Trading Symbol	AMRWQ
Common Class C
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding (in shares)		199,987,976

XML

Derivatives (Tables)

6 Months Ended

Jun. 30, 2019

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The following summarizes the fair value and classification of our derivatives:

	June 30, 2019
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)
Derivatives, current assets	$	13,855	$	(9,128	)	$	4,727
Derivatives, long-term assets	11,977		(9,469		)	2,508
Total	$	25,832	$	(18,597	)	$	7,235

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)
Derivatives, current liabilities	$	9,968	$	(9,128	)	$	840
Derivatives, long-term liabilities	9,658		(9,469		)	189
Total	$	19,626	$	(18,597	)	$	1,029

	December 31, 2018
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)
Derivatives, current assets	$	22,512	$	(6,089	)	$	16,423
Derivatives, long-term assets	7,910		(4,963		)	2,947
Total	$	30,422	$	(11,052	)	$	19,370

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)
Derivatives, current liabilities	$	7,799	$	(6,089	)	$	1,710
Derivatives, long-term liabilities	5,143		(4,963		)	180
Total	$	12,942	$	(11,052	)	$	1,890

Effect Of Derivative Instruments In The Consolidated Statements Of Operations

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

	Successor											Predecessor
Derivatives not designated as hedges	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives -
Oil	$	5,134	$	(28,712	)	$	(16,535	)	$	(50,656	)	$	4,796
Natural gas	7,278		(507		)	5,170			(574		)	1,867
Total gain (loss) on derivatives	$	12,412	$	(29,219	)	$	(11,365	)	$	(51,230	)	$	6,663

Oil Derivative Contracts

Derivative [Line Items]

Open Derivative Contracts

	Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	92,000	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	1,361,600	66.31		75.20		56.50
Long Put Options	1,453,600	53.80		62.00		50.00
Short Put Options	1,453,600	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	1,017,600	63.95		73.80		59.55
Long Put Options	1,566,600	56.81		62.50		50.00
Short Put Options	1,566,600	42.81		50.00		37.50
2021
Collar Contracts
Short Call Options	279,750	63.51		63.75		63.35
Long Put Options	659,850	46.94		55.00		41.00
Short Put Options	279,750	43.00		43.00		43.00

Natural Gas Derivative Contract

Derivative [Line Items]

Open Derivative Contracts

	Volume	Weighted			Range
Settlement Period and Type of Contract	in MMBtu	Average			High			Low
2019
Price Swap Contracts	7,980,000	$	2.67		$	2.72		$	2.64
Basis Swap Contracts	9,680,000	(0.72		)	(0.49		)	(0.93		)
Collar Contracts
Short Call Options	1,525,000	3.19			3.20			3.17
Long Put Options	1,525,000	2.70			2.70			2.70
Short Put Options	1,525,000	2.20			2.20			2.20
2020
Price Swap Contracts	1,284,000	2.54			2.54			2.54
Basis Swap Contracts	910,000	(0.49		)	(0.49		)	(0.50		)
Collar Contracts
Short Call Options	3,874,500	3.19			3.69			2.77
Long Put Options	10,749,500	2.59			3.00			2.50
Short Put Options	9,696,000	2.10			2.50			2.00
2021
Collar Contracts
Short Call Options	540,000	3.25			3.25			3.25
Long Put Options	2,790,000	2.62			2.65			2.50
Short Put Options	2,250,000	2.15			2.15			2.15

Basis Swap Derivative Contract

Derivative [Line Items]

Natural Gas Basis Swap Contracts

We had the following basis swaps at June 30, 2019:

Total Gas Volumes in MMBtu(1) over Remaining Term	Reference Price 1 (1)	Reference Price 2 (1)	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
7,990,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jul '19	—	Dec '19	(0.70		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
1,230,000	San Juan	NYMEX Henry Hub	Jul '19	—	Oct '19	(0.81		)

________________

(1)

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

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Summary Of Significant Accounting Policies

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern

We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration a number of factors that were previously disclosed in our 2018 10-K. Most significantly, we have seen significant reductions to our borrowing base under the Alta Mesa RBL in 2019. On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced by $30 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200.0 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $63.0 million.

If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Company, Alta Mesa, Alta Mesa GP, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services and Oklahoma Energy Acquisitions, LP (the “AMH Debtors” and together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC are not part of the Chapter 11 cases at this time.

On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors were authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral for an initial four week period on the terms and conditions agreed by the AMH Debtors and the lenders under the Alta Mesa RBL and set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain milestones. The ability to have continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.

The Debtors have begun a marketing process to sell their assets, which may also include KFM’s midstream assets. Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions LP, an Alta Mesa subsidiary, and non-Debtors KFM and its subsidiaries can be rejected by the Debtors.

We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the approved cash collateral agreement, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.3 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.

Recently Issued Accounting Standards Applicable to Us

Adopted

Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease, and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019.

Not Yet Adopted

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 we use today. With respect to our trade and notes receivables and certain other financial instruments,

we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us no earlier than January 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no earlier than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us no earlier than January 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

XML

Derivatives (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Gross fair value of assets	$ 25,832	$ 30,422
Gross liabilities offset against assets in the Balance Sheet	(18,597)	(11,052)
Net fair value of assets presented in the Balance Sheet	7,235	19,370
Gross fair value of liabilities	19,626	12,942
Gross assets offset against liabilities in the Balance Sheet	(18,597)	(11,052)
Net fair value of liabilities presented in the Balance Sheet	1,029	1,890
Derivatives, current assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	13,855	22,512
Gross liabilities offset against assets in the Balance Sheet	(9,128)	(6,089)
Net fair value of assets presented in the Balance Sheet	4,727	16,423
Derivatives, long-term assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	11,977	7,910
Gross liabilities offset against assets in the Balance Sheet	(9,469)	(4,963)
Net fair value of assets presented in the Balance Sheet	2,508	2,947
Derivatives, current liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	9,968	7,799
Gross assets offset against liabilities in the Balance Sheet	(9,128)	(6,089)
Net fair value of liabilities presented in the Balance Sheet	840	1,710
Derivatives, long-term liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	9,658	5,143
Gross assets offset against liabilities in the Balance Sheet	(9,469)	(4,963)
Net fair value of liabilities presented in the Balance Sheet	$ 189	$ 180

XML

Derivatives (Natural Gas Derivative Contracts) (Details) - Natural Gas Derivative Contract	6 Months Ended
	Jun. 30, 2019 MMBTU $ / MMBTU
2019 | Price Swap Contracts
Derivative [Line Items]
Volume in MMbtu | MMBTU	7,980,000
Weighted Average Swap Price (USD per unit)	2.67
2019 | Price Swap Contracts | High
Derivative [Line Items]
Swap Price (USD per unit)	2.72
2019 | Price Swap Contracts | Low
Derivative [Line Items]
Swap Price (USD per unit)	2.64
2019 | Basis Swap Contracts
Derivative [Line Items]
Volume in MMbtu | MMBTU	9,680,000
Weighted Average Swap Price (USD per unit)	(0.72)
2019 | Basis Swap Contracts | High
Derivative [Line Items]
Swap Price (USD per unit)	(0.49)
2019 | Basis Swap Contracts | Low
Derivative [Line Items]
Swap Price (USD per unit)	(0.93)
2019 | Short Call Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,525,000
Weighted Average Option Price (USD per unit)	3.19
2019 | Short Call Options | High
Derivative [Line Items]
Option Price (USD per unit)	3.20
2019 | Short Call Options | Low
Derivative [Line Items]
Option Price (USD per unit)	3.17
2019 | Long Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,525,000
Weighted Average Option Price (USD per unit)	2.70
2019 | Long Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.70
2019 | Long Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.70
2019 | Short Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,525,000
Weighted Average Option Price (USD per unit)	2.20
2019 | Short Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.20
2019 | Short Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.20
2020 | Price Swap Contracts
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,284,000
Weighted Average Swap Price (USD per unit)	2.54
2020 | Price Swap Contracts | High
Derivative [Line Items]
Swap Price (USD per unit)	2.54
2020 | Price Swap Contracts | Low
Derivative [Line Items]
Swap Price (USD per unit)	2.54
2020 | Basis Swap Contracts
Derivative [Line Items]
Volume in MMbtu | MMBTU	910,000
Weighted Average Swap Price (USD per unit)	(0.49)
2020 | Basis Swap Contracts | High
Derivative [Line Items]
Swap Price (USD per unit)	(0.49)
2020 | Basis Swap Contracts | Low
Derivative [Line Items]
Swap Price (USD per unit)	(0.50)
2020 | Short Call Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	3,874,500
Weighted Average Option Price (USD per unit)	3.19
2020 | Short Call Options | High
Derivative [Line Items]
Option Price (USD per unit)	3.69
2020 | Short Call Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.77
2020 | Long Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	10,749,500
Weighted Average Option Price (USD per unit)	2.59
2020 | Long Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	3.00
2020 | Long Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.50
2020 | Short Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	9,696,000
Weighted Average Option Price (USD per unit)	2.10
2020 | Short Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.50
2020 | Short Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.00
2021 | Short Call Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	540,000
Weighted Average Option Price (USD per unit)	3.25
2021 | Short Call Options | High
Derivative [Line Items]
Option Price (USD per unit)	3.25
2021 | Short Call Options | Low
Derivative [Line Items]
Option Price (USD per unit)	3.25
2021 | Long Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	2,790,000
Weighted Average Option Price (USD per unit)	2.62
2021 | Long Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.65
2021 | Long Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.50
2021 | Short Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	2,250,000
Weighted Average Option Price (USD per unit)	2.15
2021 | Short Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.15
2021 | Short Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.15

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Receivables (Schedule of Related Party Receivables) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Receivables [Abstract]
Related party receivables	$ 12,197	$ 12,375
Allowance for doubtful accounts	(9,887)	(9,034)
Related party receivables, net	2,310	3,341
Notes receivable from related parties	13,403	13,403
Allowance for doubtful accounts	(13,403)	(13,403)
Notes receivable from related parties, net	0	0
Related party receivables, net	$ 2,310	$ 3,341

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Adoption of ASU No. 2016-02, Leases (Operating Lease Liability Maturities) (Details) $ in Thousands	Jun. 30, 2019 USD ($)
Leases [Abstract]
Remainder of 2019	$ 1,528
2020	3,081
2021	3,048
2022	3,108
2023	2,718
Thereafter	12,647
Total lease payments	26,130
Less: imputed interest	(11,150)
Present value of operating lease liability	14,980
Current portion of operating lease liabilities	1,018
Operating lease liabilities, net of current portion	13,962
Operating lease liability recognized	$ 14,980

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Debt (Schedule of Long-Term Debt, Net) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Total debt, net	$ 1,089,162	$ 864,123
(in thousands)	1,089,162	690,123
Long-term debt, net	0	174,000
2024 Notes
Debt Instrument [Line Items]
2024 Notes	500,000	500,000
Unamortized premium on 2024 Notes
Debt Instrument [Line Items]
Unamortized premium on 2024 Notes	26,662	29,123
KFM Credit Facility
Debt Instrument [Line Items]
Alta Mesa RBL	218,000	174,000
Alta Mesa RBL | Alta Mesa RBL
Debt Instrument [Line Items]
Alta Mesa RBL	$ 344,500	$ 161,000

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Equity-Based Compensation (Successor) (Stock Compensation Expense) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense		$ 840	$ 4,263	$ 7,729	$ 3,519
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense		660	1,722	2,787	1,899
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense		35	1,260	2,493	1,468
Performance-based restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense		$ 145	$ 1,281	$ 2,449	$ 152
Predecessor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	$ 0
Predecessor | Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	0
Predecessor | Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	0
Predecessor | Performance-based restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	$ 0

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Related Party Transactions

6 Months Ended

Jun. 30, 2019

Related Party Transactions [Abstract]

Related Party Transactions

NOTE 16 — RELATED PARTY TRANSACTIONS 

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $83,000 and $28,000 for the period February 9,

2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses.

David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860, $1,017,711 and $28,874 during the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019.

David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $117,962, $297,134, $67,322, for the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense.

Bayou City Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of our working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs related to such joint well.  Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time.  During the Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of June 30, 2019, 61 joint wells have been drilled or spudded. At June 30, 2019 and December 31, 2018, $4.0 million and $9.8 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our condensed consolidated balance sheets. At June 30, 2019, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves.

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Earnings (Loss) Per Share (Tables)

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

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:

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018
	(in thousands, except shares and per share data)
Net income (loss) attributable to AMR Class A common stockholders	$	2,245	$	(6,600	)	$	(6,162	)	$	(19,930	)
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 income (loss) attributable to AMR Class A common stockholders after assumed redemption	$	2,245	$	(8,757	)	$	(6,162	)	$	(24,844	)
Weighted average Class A common shares outstanding (Basic)	180,742,049		173,345,982			180,505,318			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)	180,742,049		207,965,929			180,505,318			208,112,707
Income (loss) per common share attributable to AMR common stockholders:
Basic	$	0.01	$	(0.04	)	$	(0.03	)	$	(0.12	)
Diluted	$	0.01	$	(0.04	)	$	(0.03	)	$	(0.12	)

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Summary Of Changes In Asset Retirement Obligations

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Balance, beginning of period	$	11,552		$	—		$	10,469
Liabilities assumed in Business Combination	—			5,998			—
Liabilities incurred	634			877			—
Liabilities settled	(162		)	(806		)	(63		)
Liabilities transferred in sale of properties	—			(20		)	—
Revisions to estimates	(8		)	665			63
Accretion expense	470			263			40
Balance, end of period	12,486			6,977			10,509
Less: current portion	44			538			33
Long-term portion	$	12,442		$	6,439		$	10,476

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Condensed Consolidated Statements Of Changes In Partners' Capital (Unaudited) $ in Thousands	USD ($)
BALANCE, BEGINNING (Predecessor) at Dec. 31, 2017	$ 154,445
Distribution of non-STACK oil and gas assets, net of associated liabilities, and Contributions | Predecessor	43,482
Net loss | Predecessor	(14,862)
BALANCE, ENDING (Predecessor) at Feb. 08, 2018	183,065
BALANCE, BEGINNING at Dec. 31, 2018	245,520
Net loss	(6,162)
BALANCE, ENDING at Jun. 30, 2019	$ 242,866

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Property And Equipment (Tables)

6 Months Ended

Jun. 30, 2019

Property, Plant and Equipment [Abstract]

Summary Of Property And Equipment

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	33,923	$	26,086	$	67,965	$	36,859	$	11,021
Midstream tangible asset depreciation	3,504		2,010		6,724		3,132		—
Other property and equipment depreciation	341		423		749		586		609
Total depletion and depreciation	$	37,768	$	28,519	$	75,438	$	40,577	$	11,630

(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	76,665		$	74,217
Proved oil and gas properties	2,196,605			2,110,346
Accumulated depletion and impairment	(1,489,191		)	(1,421,226		)
Proved oil and gas properties, net	707,414			689,120
Total oil and gas properties, net	784,079			763,337
Other property and equipment
Land	5,600			5,600
Fresh water wells	27,373			27,366
Produced water disposal system	106,467			104,498
Gas processing plant and gathering lines	412,193			380,470
Office furniture, equipment and vehicles	3,755			3,703
Accumulated depreciation and impairment	(84,841		)	(77,368		)
Other property and equipment, net	470,547			444,269
Total property and equipment, net	$	1,254,626		$	1,207,606

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Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 91,111	$ 26,854
Restricted cash	890	1,001
Accounts receivable, net	73,776	87,842
Other receivables	3,635	6,331
Related party receivables, net	2,310	3,341
Prepaid expenses and other	5,575	1,125
Derivatives	4,727	16,423
Total current assets	182,024	142,917
Property and equipment, net
Oil and gas properties, successful efforts method	784,079	763,337
Other property and equipment	470,547	444,269
Total property and equipment, net	1,254,626	1,207,606
Other assets
Operating lease right-of-use assets, net	8,180
Equity method investment	1,842	1,100
Deferred financing costs, net	2,836	3,195
Deposits and other long-term assets	41	65
Derivatives	2,508	2,947
Total other assets	15,407	7,307
Total assets	1,452,057	1,357,830
Current liabilities
Current portion of debt	1,089,162	690,123
Accounts payable and accrued liabilities	109,901	247,439
Advances from non-operators	1,755	5,193
Advances from related party	4,003	9,839
Asset retirement obligations, current portion	44	2,079
Current operating lease liability	1,018
Derivatives	840	1,710
Total current liabilities	1,206,723	956,383
Long-term liabilities
Asset retirement obligations, net of current portion	12,442	9,473
Long-term debt, net	0	174,000
Other long-term liabilities	5,096	1,667
Operating lease liabilities, net of current portion	13,962
Derivatives	189	180
Total long-term liabilities	31,689	185,320
Total liabilities	1,238,412	1,141,703
Additional paid in capital	1,509,716	1,503,382
Accumulated deficit	(1,538,975)	(1,532,813)
Total stockholders’ equity	(29,221)	(29,393)
Noncontrolling interests	242,866	245,520
Total equity	213,645	216,127
Total liabilities and stockholders’ equity	1,452,057	1,357,830
Preferred Class A
Long-term liabilities
Preferred Stock, $0.0001 par value	0	0
Preferred Class B
Long-term liabilities
Preferred Stock, $0.0001 par value	0	0
Common Class A
Long-term liabilities
Common stock, $0.0001 par value	18	18
Common Class C
Long-term liabilities
Common stock, $0.0001 par value	$ 20	$ 20

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Business Segment Information (Tables)

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

Schedule of Results of Reportable Segments

	Three Months Ended June 30, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	90,668		$	—		$	—		$	90,668
Natural gas	12,384			—			—			12,384
Natural gas liquids	10,251			—			—			10,251
Sales of gathered production	—			10,439			—			10,439
Midstream revenue	—			22,112			(15,563		)	6,549
Segment sales revenue	113,303			32,551			(15,563		)	130,291
Other revenue	330			6,693			(4,009		)	3,014
Operating revenue	113,633			39,244			(19,572		)	133,305
Gain on sale of assets	—			—			—			—
Gain (loss) on derivatives	12,412			—			—			12,412
Total revenue	126,045			39,244			(19,572		)	145,717
Operating expenses
Lease operating	19,123			—			(4,009		)	15,114
Transportation, processing and marketing	19,614			2,786			(15,563		)	6,837
Midstream operating	—			6,520			—			6,520
Cost of sales for purchased gathered production	—			8,720			—			8,720
Production taxes	5,117			—			—			5,117
Workovers	412			395			—			807
Exploration	3,289			—			—			3,289
Depreciation, depletion and amortization	34,504			3,505			—			38,009
Impairment of assets	6,500			—			—			6,500
General and administrative	15,723			5,324			6,125			27,172
Total operating expenses	104,282			27,250			(13,447		)	118,085
Operating income	21,763			11,994			(6,125		)	27,632
Other income (expense)
Interest expense	(14,071		)	(2,684		)	—			(16,755		)
Interest income	54			6			19			79
Equity in earnings of unconsolidated subsidiaries	—			643			—			643
Total other income (expense)	(14,017		)	(2,035		)	19			(16,033		)
Income (loss) from continuing operations before income taxes	7,746			9,959			(6,106		)	11,599
Interest expense	14,071			2,684			—			16,755
Depreciation, depletion and amortization	34,504			3,505			—			38,009
Gain on unrealized hedges	(11,868		)	—			—			(11,868		)
Impairment of assets	6,500			—			—			6,500
Equity-based compensation	1,396			(556		)	—			840
Exploration	3,289			—			—			3,289
Severance costs	609			88			—			697
Strategic costs	4,061			—			—			4,061
Adjusted EBITDAX	$	60,308		$	15,680		$	(6,106	)	$	69,882
Equity method investment at period end	$	—		$	1,842		$	—		$	1,842
Capital expenditures	47,061			39,533			—			86,594

	Three Months Ended June 30, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	75,291		$	—		$	—		$	75,291
Natural gas	7,980			—			—			7,980
Natural gas liquids	10,241			—			—			10,241
Sales of gathered production	—			21,024			(12,100		)	8,924
Midstream revenue	—			15,849			(9,032		)	6,817
Segment sales revenue	93,512			36,873			(21,132		)	109,253
Other revenue	2,229			—			—			2,229
Operating revenue	95,741			36,873			(21,132		)	111,482
Gain on sale of assets	(63		)	—			—			(63		)
Gain (loss) on derivatives	(29,219		)	—			—			(29,219		)
Total revenue	66,459			36,873			(21,132		)	82,200
Operating expenses
Lease operating	12,679			—			—			12,679
Transportation, processing and marketing	11,205			3,223			(9,032		)	5,396
Midstream operating	—			3,313			—			3,313
Cost of sales for purchased gathered production	—			21,002			(12,100		)	8,902
Production taxes	2,606			—			—			2,606
Workovers	333			—			—			333
Exploration	8,083			—			—			8,083
Depreciation, depletion and amortization	26,670			7,264			—			33,934
Impairment of assets	—			—			—			—
General and administrative	17,811			4,140			505			22,456
Total operating expenses	79,387			38,942			(20,627		)	97,702
Operating income	(12,928		)	(2,069		)	(505		)	(15,502		)
Other income (expense)
Interest expense	(10,361		)	(1,418		)	—			(11,779		)
Interest income	820			—			4			824
Total other income (expense)	(9,541		)	(1,418		)	4			(10,955		)
Income (loss) from continuing operations before income taxes	(22,469		)	(3,487		)	(501		)	(26,457		)
Interest expense	10,361			1,418			—			11,779
Depreciation, depletion and amortization	26,670			7,264			—			33,934
Loss on unrealized hedges	14,860			—			—			14,860
Equity-based compensation	3,621			465			177			4,263
Exploration	8,083			—			—			8,083
Business Combination	443			—			—			443
Adjusted EBITDAX	$	41,569		$	5,660		$	(324	)	$	46,905
Capital expenditures	$	189,732		$	17,844		$	—		$	207,576

	Six Months Ended June 30, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	177,031		$	—		$	—		$	177,031
Natural gas	30,834			—			—			30,834
Natural gas liquids	21,467			—			—			21,467
Sales of gathered production	—			19,999			—			19,999
Midstream revenue	—			44,488			(30,784		)	13,704
Segment sales revenue	229,332			64,487			(30,784		)	263,035
Other revenue	898			14,374			(9,173		)	6,099
Operating revenue	230,230			78,861			(39,957		)	269,134
Gain on sale of assets	1,483			—			—			1,483
Gain (loss) on derivatives	(11,365		)	—			—			(11,365		)
Total revenue	220,348			78,861			(39,957		)	259,252
Operating expenses
Lease operating	44,231			—			(9,173		)	35,058
Transportation, processing and marketing	37,375			4,849			(30,784		)	11,440
Midstream operating	—			12,671			—			12,671
Cost of sales for purchased gathered production	—			18,415			—			18,415
Production taxes	10,600			—			—			10,600
Workovers	609			511			—			1,120
Exploration	5,343			—			—			5,343
Depreciation, depletion and amortization	69,179			6,729			—			75,908
Impairment of assets	6,500			—			—			6,500
General and administrative	36,670			13,387			6,633			56,690
Total operating expenses	210,507			56,562			(33,324		)	233,745
Operating income	9,841			22,299			(6,633		)	25,507
Other income (expense)
Interest expense	(26,901		)	(5,314		)	—			(32,215		)
Interest income	81			10			39			130
Equity in earnings of unconsolidated subsidiaries	—			742			—			742
Total other income (expense)	(26,820		)	(4,562		)	39			(31,343		)
Income (loss) from continuing operations before income taxes	(16,979		)	17,737			(6,594		)	(5,836		)
Interest expense	26,901			5,314			—			32,215
Depreciation, depletion and amortization	69,179			6,729			—			75,908
Loss on unrealized hedges	12,274			—			—			12,274
Impairment of assets	6,500			—			—			6,500
Equity-based compensation	3,057			462			—			3,519
Exploration	5,343			—			—			5,343
Severance costs	4,584			1,984			—			6,568
Strategic costs	4,061			—			—			4,061
Business Combination	10			—			—			10
Adjusted EBITDAX	$	114,930		$	32,226		$	(6,594	)	$	140,562
Equity method investment at period end	$	—		$	1,842		$	—		$	1,842
Capital expenditures	180,138			67,804			—			247,942
Total assets at period end	999,744			458,882			(6,569		)	1,452,057

	February 9, 2018 Through June 30, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	115,569		$	—		$	—		$	115,569
Natural gas	13,190			—			—			13,190
Natural gas liquids	14,955			—			—			14,955
Sales of gathered production	—			31,634			(18,837		)	12,797
Midstream revenue	—			23,671			(13,594		)	10,077
Segment sales revenue	143,714			55,305			(32,431		)	166,588
Other revenue	2,784			—			—			2,784
Operating revenue	146,498			55,305			(32,431		)	169,372
Gain (loss) on sale of assets	5,076			—			—			5,076
Gain (loss) on derivatives	(51,230		)	—			—			(51,230		)
Total revenue	100,344			55,305			(32,431		)	123,218
Operating expenses
Lease operating	20,996			—			—			20,996
Transportation, processing and marketing	16,788			5,561			(13,594		)	8,755
Midstream operating	—			3,900			—			3,900
Cost of sales for purchased gathered production	—			31,548			(18,837		)	12,711
Production taxes	4,021			—			—			4,021
Workovers	1,578			—			—			1,578
Exploration	9,668			—			—			9,668
Depreciation, depletion and amortization	37,708			11,905			—			49,613
Impairment of assets	—			—			—			—
General and administrative	52,465			6,313			1,430			60,208
Total operating expenses	143,224			59,227			(31,001		)	171,450
Operating income	(42,880		)	(3,922		)	(1,430		)	(48,232		)
Other income (expense)
Interest expense	(15,557		)	(1,666		)	—			(17,223		)
Interest income	1,366			—			4			1,370
Total other income (expense)	(14,191		)	(1,666		)	4			(15,853		)
Income (loss) from continuing operations before income taxes	(57,071		)	(5,588		)	(1,426		)	(64,085		)
Interest expense	15,557			1,666			—			17,223
Depreciation, depletion and amortization	37,708			11,905			—			49,613
Loss on unrealized hedges	32,896			—			—			32,896
Loss on sale of fixed assets	63			—			—			63
Equity-based compensation	6,389			507			833			7,729
Exploration	9,668			—			—			9,668
Business Combination	23,717			—			—			23,717
Adjusted EBITDAX	$	68,927		$	8,490		$	(593	)	$	76,824
Capital expenditures	$	319,042		$	21,589		$	—		$	340,631
Total assets at period end	2,817,714			1,427,792			8,152			4,253,658

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Receivables

6 Months Ended

Jun. 30, 2019

Receivables [Abstract]

Receivables

RECEIVABLES

Accounts Receivable

(in thousands)	June 30, 2019			December 31, 2018
Production and processing sales and fees	$	41,844		$	51,004
Joint interest billings	20,836			18,147
Pooling interest (1)	11,506			18,786
Allowance for doubtful accounts	(410		)	(95		)
Total accounts receivable, net	$	73,776		$	87,842

_________________

(1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells.  The pooling interest listed above represents unbilled costs for wells where the option remains pending.  Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties.

Related Party Receivables

(in thousands)	June 30, 2019			December 31, 2018
Related party receivables	$	12,197		$	12,375
Allowance for doubtful accounts	(9,887		)	(9,034		)
Related party receivables, net	2,310			3,341
Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Related party receivables, net	$	2,310		$	3,341

Management Services Agreement with High Mesa

(in thousands)	June 30, 2019
High Mesa related party receivable at December 31, 2018	$	10,066
Additions	894
Payments	(1,073		)
High Mesa related party receivable at June 30, 2019	9,887
Allowance for uncollectibility(1)	(9,887		)
Balance at June 30, 2019, net	$	—

_________________

(1) $9.0 million of the allowance was recognized during the 2018 Successor Period.

Our management services agreement with HMI (“the High Mesa Agreement”) was terminated effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the services to a successor service provider. During the transition period, HMI agreed to pay us (i) for all services performed, (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 reimbursable pursuant to the High Mesa Agreement. As of June 30, 2019, and December 31, 2018, approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9

million and $9.0 million as of June 30, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation relating to the non-STACK assets. As of June 30, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.

Promissory notes receivable

High Mesa Services, LLC (“HMS”), a subsidiary of HMI, defaulted under the terms of a promissory note with us when it did not pay us on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of June 30, 2019 and December 31, 2018.

In addition, we have a note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount.  HMI disputes its obligations under the note. As of June 30, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.

We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes. As a result of the potential conflict of interest from certain of AMR’s directors who are also controlling holders of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter.

XML

Accounts Payable And Accrued Liabilities

6 Months Ended

Jun. 30, 2019

Payables and Accruals [Abstract]

Accounts Payable And Accrued Liabilities

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 

໿

(in thousands)	June 30, 2019		December 31, 2018
Accounts payable	$	12,526	$	20,422
Accruals for capital expenditures	22,669		139,904
Revenue and royalties payable	41,304		50,241
Accruals for operating expenses	14,853		21,830
Accrued interest	6,922		2,477
Derivative settlements	743		109
Other	10,884		12,456
Total accrued liabilities	97,375		227,017
Accounts payable and accrued liabilities	$	109,901	$	247,439

XML

Accounts Payable And Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Accounts payable	$ 12,526	$ 20,422
Accruals for capital expenditures	22,669	139,904
Revenue and royalties payable	41,304	50,241
Accruals for operating expenses	14,853	21,830
Accrued interest	6,922	2,477
Derivative settlements	743	109
Other	10,884	12,456
Total accrued liabilities	97,375	227,017
Accounts payable and accrued liabilities	$ 109,901	$ 247,439

XML

Discontinued Operations (Schedule Of Operations And Other Items Reclassified In Discontinued Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2018	Jun. 30, 2019
Operating expenses
Interest expense		$ 0	$ 0
Predecessor
Operating expenses
Interest expense	$ (103)
Predecessor | Weeks Island Field, Louisiana | Non Stack Assets | Disposed of by Sale
Revenue
Oil	1,617
Natural gas	1,023
Natural gas liquids	236
Other	16
Operating revenue	2,892
Loss on sale of assets	(1,923)
Total revenue	969
Operating expenses
Lease operating	1,770
Transportation and marketing	83
Production taxes	167
Workovers	127
Depreciation, depletion and amortization	884
Impairment of assets	5,560
General and administrative	21
Total operating expenses	8,612
Interest expense	(103)
Loss from discontinued operations, net of tax	$ (7,746)

XML

Derivatives (Additional Information) (Details) - USD ($) $ in Millions	1 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Dec. 31, 2018
Contracts To be Settled January 2019
Derivative [Line Items]
Derivative contracts		$ 1.4	$ 1.3
Alta Mesa RBL | Subsequent Event
Derivative [Line Items]
Gain applied towards outstanding debt	$ 4.0

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Debt (Summary Of Future Maturities Of Long-Term Debt) (Details) $ in Thousands	Jun. 30, 2019 USD ($)
Summary of future maturities of long-term debt
2019	$ 0
2020	0
2021	0
2022	0
2023	562,500
Thereafter	500,000
Total long-term debt	$ 1,062,500

XML

Related Party Transactions (Details)			2 Months Ended	3 Months Ended	5 Months Ended	6 Months Ended	12 Months Ended
	Feb. 08, 2018 USD ($)	Dec. 31, 2016	Mar. 31, 2018 USD ($)	Jun. 30, 2019 USD ($) well	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) well	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jan. 13, 2016 well
Related Party Transaction [Line Items]
Advances from related party				$ 4,003,000		$ 4,003,000	$ 9,839,000
BCE
Related Party Transaction [Line Items]
Advances from related party				4,000,000.0		4,000,000.0	9,800,000
Land consulting services | Vice President | David Murrell, VP of Land and Business Development
Related Party Transaction [Line Items]
Total fees paid to ARM			$ 83,000
Land consulting services | Predecessor | Vice President | David Murrell, VP of Land and Business Development
Related Party Transaction [Line Items]
Total fees paid to ARM	$ 28,000
Compensation to related party | Vice President | David Mcclure Vp of Facilities and Infrastructure
Related Party Transaction [Line Items]
Total compensation			$ 1,017,711	768,860
Compensation to related party | Landman | David Pepper, Landman And Cousin Of VP Of Land And Business Development
Related Party Transaction [Line Items]
Total compensation					$ 297,134	117,962	67,322
Compensation to related party | Predecessor | Vice President | David Mcclure Vp of Facilities and Infrastructure
Related Party Transaction [Line Items]
Total compensation							$ 28,874
Joint Development Agreement
Related Party Transaction [Line Items]
Number of wells to be drilled in three tranches | well									60
Number of additional wells to be drilled | well									20
Reduced interest (percent)		12.50%
Internal rate of return		25.00%
Joint Development Agreement | BCE
Related Party Transaction [Line Items]
Percent committed to fund		100.00%
Drilling and completion costs (maximum)								$ 3,200,000
Working interest received (percent)		80.00%
Reduced interest (percent)		20.00%
Internal rate of return		15.00%
Advances from related party				$ 39,500,000		$ 39,500,000
Number of wells drilled | well				61		61

XML

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands		1 Months Ended	5 Months Ended	6 Months Ended
	Feb. 08, 2018	Feb. 08, 2018	Jun. 30, 2018	Jun. 30, 2019
Supplemental cash flow information:
Cash paid for interest			$ 22,996	$ 29,513
Cash paid for income taxes, net of refunds			1,573	706
Non-cash investing and financing activities:
Increase in asset retirement obligations			877	634
Increase (decrease) in accruals or payables for capital expenditures			(25,798)	(127,875)
Increase in withholding tax accruals for share-based compensation			0	165
Distribution of non-STACK assets, net of liabilities			0	0
Equity issued in Business Combination			2,067,393	0
Release of common stock from possible redemption	$ 996,384		966,384	0
Tax effect of redemption of noncontrolling interests in SRII Opco for Class A common shares and other			$ (437)	$ 0
Predecessor
Supplemental cash flow information:
Cash paid for interest		$ 1,145
Cash paid for income taxes, net of refunds		0
Non-cash investing and financing activities:
Increase in asset retirement obligations		0
Increase (decrease) in accruals or payables for capital expenditures		4,896
Increase in withholding tax accruals for share-based compensation		0
Distribution of non-STACK assets, net of liabilities		43,482
Equity issued in Business Combination		0
Release of common stock from possible redemption		0
Tax effect of redemption of noncontrolling interests in SRII Opco for Class A common shares and other		$ 0

XML

Adoption of ASU No. 2016-02, Leases (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		5 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, right of use asset recognized	$ 8,180			$ 8,180
Weighted-average remaining lease term (in years)	8 years 1 month 6 days			8 years 1 month 6 days
Weighted-average discount rate	14.30%			14.30%
Lease payment under ASC 840, due 2019						$ 2,800
Lease payment under ASC 840, due 2020						2,900
Lease payment under ASC 840, due 2021						2,900
Lease payment under ASC 840, due 2022						3,100
Lease payment under ASC 840, due 2023						3,000
Lease payment under ASC 840, due thereafter						$ 12,200
Impairment loss	$ 6,500	$ 0	$ 0	$ 6,500
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, right of use asset recognized					$ 15,400

XML

Receivables (Management Services Agreement with High Mesa) (Details) - USD ($) $ in Thousands	2 Months Ended	5 Months Ended	6 Months Ended
	Mar. 31, 2018	Jun. 30, 2018	Jun. 30, 2019	Dec. 31, 2018
Allowance for Doubtful Accounts Receivable [Roll Forward]
Related party receivables, beginning of period			$ 12,375
Related party receivables, end of period			12,197
Allowance for uncollectibility			(9,887)	$ (9,034)
Related party receivables, net			2,310	$ 3,341
Provision for uncollectible receivables		$ 0	1,177
High Mesa Agreement
Allowance for Doubtful Accounts Receivable [Roll Forward]
Related party receivables, beginning of period			10,066
Additions			894
Payments			(1,073)
Related party receivables, end of period			9,887
Allowance for uncollectibility			(9,887)
Related party receivables, net			$ 0
Provision for uncollectible receivables	$ 9,900

XML

Receivables (Tables)

6 Months Ended

Jun. 30, 2019

Receivables [Abstract]

Schedule of Accounts Receivable

Management Services Agreement with High Mesa

(in thousands)	June 30, 2019
High Mesa related party receivable at December 31, 2018	$	10,066
Additions	894
Payments	(1,073		)
High Mesa related party receivable at June 30, 2019	9,887
Allowance for uncollectibility(1)	(9,887		)
Balance at June 30, 2019, net	$	—

_________________

(1)

$9.0 million of the allowance was recognized during the 2018 Successor Period.

Accounts Receivable

(in thousands)	June 30, 2019			December 31, 2018
Production and processing sales and fees	$	41,844		$	51,004
Joint interest billings	20,836			18,147
Pooling interest (1)	11,506			18,786
Allowance for doubtful accounts	(410		)	(95		)
Total accounts receivable, net	$	73,776		$	87,842

_________________

(1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells.  The pooling interest listed above represents unbilled costs for wells where the option remains pending.  Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties.

Related Party Receivables

(in thousands)	June 30, 2019			December 31, 2018
Related party receivables	$	12,197		$	12,375
Allowance for doubtful accounts	(9,887		)	(9,034		)
Related party receivables, net	2,310			3,341
Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Related party receivables, net	$	2,310		$	3,341

XML

Significant Concentrations

6 Months Ended

Jun. 30, 2019

Significant Concentrations [Abstract]

Significant Concentrations

SIGNIFICANT CONCENTRATIONS 

During most of the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales were generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality.  In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM.  As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.

ARM has also provided us with strategic advice, execution and reporting services with respect to our derivatives activities.

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	25,833	$	90,206	$	119,224	$	131,422	$	28,757
Marketing and management fees paid to ARM	$	519	$	—	$	1,216	$	—	$	—
Fees paid to ARM for services relating to our derivatives	218		209		411		283		66
Total fees paid to ARM	$	737	$	209	$	1,627	$	283	$	66

Receivables from ARM for sales on our behalf were $6.6 million and $43.8 million as of June 30, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

We believe that the loss of any of our customers, or of our marketing agent ARM, would not have a material adverse effect on us because alternative purchasers and marketing firms are readily available.

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Summary Of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Going Concern

Going Concern

We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration a number of factors that were previously disclosed in our 2018 10-K. Most significantly, we have seen significant reductions to our borrowing base under the Alta Mesa RBL in 2019. On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced by $30 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200.0 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $63.0 million.

If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Company, Alta Mesa, Alta Mesa GP, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services and Oklahoma Energy Acquisitions, LP (the “AMH Debtors” and together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC are not part of the Chapter 11 cases at this time.

On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors were authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral for an initial four week period on the terms and conditions agreed by the AMH Debtors and the lenders under the Alta Mesa RBL and set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain milestones. The ability to have continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.

The Debtors have begun a marketing process to sell their assets, which may also include KFM’s midstream assets. Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions LP, an Alta Mesa subsidiary, and non-Debtors KFM and its subsidiaries can be rejected by the Debtors.

We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the approved cash collateral agreement, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.3 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.

Recently Issued and Applicable Accounting Standards

Recently Issued Accounting Standards Applicable to Us

Adopted

Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease, and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019.

Not Yet Adopted

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 we use today. With respect to our trade and notes receivables and certain other financial instruments,

we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us no earlier than January 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no earlier than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us no earlier than January 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

XML

Label	Element	Value
Stock Issued For Initial Public Offering, Value	amr_StockIssuedForInitialPublicOfferingValue	$ 400,000,000
Noncontrolling Interest, Period Increase (Decrease)	us-gaap_MinorityInterestPeriodIncreaseDecrease	2,058,635,000
Noncontrolling Interest, Increase (Decrease) From Redemptions	amr_NoncontrollingInterestIncreaseDecreaseFromRedemptions	(33,000)
Parent [Member]
Stock Issued For Initial Public Offering, Value	amr_StockIssuedForInitialPublicOfferingValue	400,000,000
Reclassifications of Temporary to Permanent Equity	us-gaap_ReclassificationsOfTemporaryToPermanentEquity	996,384,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	1,391,346,000
Noncontrolling Interest, Increase (Decrease) From Redemptions	amr_NoncontrollingInterestIncreaseDecreaseFromRedemptions	(33,000)
Noncontrolling Interest [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	2,058,635,000
Noncontrolling Interest, Period Increase (Decrease)	us-gaap_MinorityInterestPeriodIncreaseDecrease	2,058,635,000
Additional Paid-in Capital [Member]
Stock Issued During Period, Value, New Issues	us-gaap_StockIssuedDuringPeriodValueNewIssues	(21,000)
Stock Issued For Initial Public Offering, Value	amr_StockIssuedForInitialPublicOfferingValue	399,996,000
Reclassifications of Temporary to Permanent Equity	us-gaap_ReclassificationsOfTemporaryToPermanentEquity	996,374,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	1,399,422,000
Noncontrolling Interest, Increase (Decrease) From Redemptions	amr_NoncontrollingInterestIncreaseDecreaseFromRedemptions	(33,000)
Retained Earnings [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	$ (8,114,000)
Common Class B [Member] | Common Stock [Member]
Stock Issued During Period, Shares, Conversion of Convertible Securities	us-gaap_StockIssuedDuringPeriodSharesConversionOfConvertibleSecurities	25,875,000
Stock Issued During Period, Value, Conversion of Convertible Securities	us-gaap_StockIssuedDuringPeriodValueConversionOfConvertibleSecurities	$ (3,000)
Common Class C [Member] | Common Stock [Member]
Stock Issued During Period, Value, New Issues	us-gaap_StockIssuedDuringPeriodValueNewIssues	21,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	$ 21,000
Stock Issued During Period, Shares, New Issues	us-gaap_StockIssuedDuringPeriodSharesNewIssues	213,402,000
Shares, Outstanding	us-gaap_SharesOutstanding	213,402,000
Common Class A [Member] | Common Stock [Member]
Stock Issued For Initial Public Offering, Value	amr_StockIssuedForInitialPublicOfferingValue	$ 4,000
Stock Issued During Period, Shares, Conversion of Convertible Securities	us-gaap_StockIssuedDuringPeriodSharesConversionOfConvertibleSecurities	25,875,000
Reclassifications of Temporary to Permanent Equity	us-gaap_ReclassificationsOfTemporaryToPermanentEquity	$ 10,000
Reclassifications Of Temporary To Permanent Equity, Shares	amr_ReclassificationsOfTemporaryToPermanentEquityShares	99,638,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	$ 17,000
Stock Issued During Period, Value, Conversion of Convertible Securities	us-gaap_StockIssuedDuringPeriodValueConversionOfConvertibleSecurities	$ 3,000
Stock Issued For Initial Public Offering, Shares	amr_StockIssuedForInitialPublicOfferingShares	40,000,000
Stock Issued During Period, Shares, Conversion of Units	us-gaap_StockIssuedDuringPeriodSharesConversionOfUnits	(3,000)
Shares, Outstanding	us-gaap_SharesOutstanding	169,372,000

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Debt (Narrative) (Details)	3 Months Ended	6 Months Ended
	Mar. 31, 2019 USD ($)	Jun. 30, 2019 USD ($)	Aug. 31, 2019 USD ($)	Apr. 01, 2019 USD ($)
Alta Mesa Credit Facility
Debt Instrument [Line Items]
Current borrowing capacity	$ 400,000,000.0			$ 370,000,000.0
Monthly payments	$ 32,500,000
Debt covenant, current ratio, minimum required		1.0
Maximum leverage ratio		4.0
Kingfisher Credit Facility
Debt Instrument [Line Items]
Debt covenant, maximum leverage ratio, scenario one		4.5
Debt covenant, maximum leverage ratio, scenario two		4.75
Debt covenant, consolidated EBITDA threshold		$ 75,000,000.0
Debt covenant, minimum interest coverage ratio		2.5
Remaining borrowing capacity		$ 74,000,000.0
Amendment To KFM Credit Facility
Debt Instrument [Line Items]
Credit facility amount		15,000,000.0
Alta Mesa RBL | 2024 Notes
Debt Instrument [Line Items]
Fair value of notes		193,800,000
Kingfisher | Kingfisher Credit Facility
Debt Instrument [Line Items]
Credit facility amount		$ 300,000.0
Subsequent Event | Alta Mesa Credit Facility
Debt Instrument [Line Items]
Credit facility amount			$ 200,000,000.0
Amount exceeding borrowing base			$ 162,400,000

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Equity-Based Compensation (Successor) (Narrative) (Details) - Performance-based restricted stock units - $ / shares	6 Months Ended	11 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Awards deemed granted (in shares)	572,990
Fair value of tranche granted (in USD per share)	$ 0.27
Tranche one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		20.00%
Tranche two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		30.00%
Tranche three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		50.00%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned		0.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned		200.00%

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Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Unproved properties	$ 76,665	$ 74,217
Proved oil and gas properties	2,196,605	2,110,346
Accumulated depletion and impairment	(1,489,191)	(1,421,226)
Proved oil and gas properties, net	707,414	689,120
Total oil and gas properties, net	784,079	763,337
Land	5,600	5,600
Fresh water wells	27,373	27,366
Produced water disposal system	106,467	104,498
Gas processing plant and gathering lines	412,193	380,470
Office furniture, equipment and vehicles	3,755	3,703
Accumulated depreciation and impairment	(84,841)	(77,368)
Other property and equipment, net	470,547	444,269
Total property and equipment, net	$ 1,254,626	$ 1,207,606

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Receivables (Schedule of Accounts Receivable) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Receivables [Abstract]
Production and processing sales and fees	$ 41,844	$ 51,004
Joint interest billings	20,836	18,147
Pooling interest	11,506	18,786
Allowance for doubtful accounts	(410)	(95)
Total accounts receivable, net	$ 73,776	$ 87,842

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Adoption of ASU No. 2016-02, Leases (Lease Costs) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 828	$ 1,675
Variable lease cost	478	849
Short-term lease cost	1,071	3,686
Total lease cost	2,377	6,210
Lease operating expense
Lessee, Lease, Description [Line Items]
Total lease cost	1,029	3,675
General and administrative
Lessee, Lease, Description [Line Items]
Total lease cost	$ 1,348	$ 2,535

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Commitments And Contingencies	6 Months Ended
	Jun. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES There have been no material developments during the first six months of 2019 in relation to our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including the matters discussed in our 2018 10-K.

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Business Segment Information

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

Business Segment Information

BUSINESS SEGMENT INFORMATION

	Three Months Ended June 30, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	90,668		$	—		$	—		$	90,668
Natural gas	12,384			—			—			12,384
Natural gas liquids	10,251			—			—			10,251
Sales of gathered production	—			10,439			—			10,439
Midstream revenue	—			22,112			(15,563		)	6,549
Segment sales revenue	113,303			32,551			(15,563		)	130,291
Other revenue	330			6,693			(4,009		)	3,014
Operating revenue	113,633			39,244			(19,572		)	133,305
Gain on sale of assets	—			—			—			—
Gain (loss) on derivatives	12,412			—			—			12,412
Total revenue	126,045			39,244			(19,572		)	145,717
Operating expenses
Lease operating	19,123			—			(4,009		)	15,114
Transportation, processing and marketing	19,614			2,786			(15,563		)	6,837
Midstream operating	—			6,520			—			6,520
Cost of sales for purchased gathered production	—			8,720			—			8,720
Production taxes	5,117			—			—			5,117
Workovers	412			395			—			807
Exploration	3,289			—			—			3,289
Depreciation, depletion and amortization	34,504			3,505			—			38,009
Impairment of assets	6,500			—			—			6,500
General and administrative	15,723			5,324			6,125			27,172
Total operating expenses	104,282			27,250			(13,447		)	118,085
Operating income	21,763			11,994			(6,125		)	27,632
Other income (expense)
Interest expense	(14,071		)	(2,684		)	—			(16,755		)
Interest income	54			6			19			79
Equity in earnings of unconsolidated subsidiaries	—			643			—			643
Total other income (expense)	(14,017		)	(2,035		)	19			(16,033		)
Income (loss) from continuing operations before income taxes	7,746			9,959			(6,106		)	11,599
Interest expense	14,071			2,684			—			16,755
Depreciation, depletion and amortization	34,504			3,505			—			38,009
Gain on unrealized hedges	(11,868		)	—			—			(11,868		)
Impairment of assets	6,500			—			—			6,500
Equity-based compensation	1,396			(556		)	—			840
Exploration	3,289			—			—			3,289
Severance costs	609			88			—			697
Strategic costs	4,061			—			—			4,061
Adjusted EBITDAX	$	60,308		$	15,680		$	(6,106	)	$	69,882
Equity method investment at period end	$	—		$	1,842		$	—		$	1,842
Capital expenditures	47,061			39,533			—			86,594

	Three Months Ended June 30, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	75,291		$	—		$	—		$	75,291
Natural gas	7,980			—			—			7,980
Natural gas liquids	10,241			—			—			10,241
Sales of gathered production	—			21,024			(12,100		)	8,924
Midstream revenue	—			15,849			(9,032		)	6,817
Segment sales revenue	93,512			36,873			(21,132		)	109,253
Other revenue	2,229			—			—			2,229
Operating revenue	95,741			36,873			(21,132		)	111,482
Gain on sale of assets	(63		)	—			—			(63		)
Gain (loss) on derivatives	(29,219		)	—			—			(29,219		)
Total revenue	66,459			36,873			(21,132		)	82,200
Operating expenses
Lease operating	12,679			—			—			12,679
Transportation, processing and marketing	11,205			3,223			(9,032		)	5,396
Midstream operating	—			3,313			—			3,313
Cost of sales for purchased gathered production	—			21,002			(12,100		)	8,902
Production taxes	2,606			—			—			2,606
Workovers	333			—			—			333
Exploration	8,083			—			—			8,083
Depreciation, depletion and amortization	26,670			7,264			—			33,934
Impairment of assets	—			—			—			—
General and administrative	17,811			4,140			505			22,456
Total operating expenses	79,387			38,942			(20,627		)	97,702
Operating income	(12,928		)	(2,069		)	(505		)	(15,502		)
Other income (expense)
Interest expense	(10,361		)	(1,418		)	—			(11,779		)
Interest income	820			—			4			824
Total other income (expense)	(9,541		)	(1,418		)	4			(10,955		)
Income (loss) from continuing operations before income taxes	(22,469		)	(3,487		)	(501		)	(26,457		)
Interest expense	10,361			1,418			—			11,779
Depreciation, depletion and amortization	26,670			7,264			—			33,934
Loss on unrealized hedges	14,860			—			—			14,860
Equity-based compensation	3,621			465			177			4,263
Exploration	8,083			—			—			8,083
Business Combination	443			—			—			443
Adjusted EBITDAX	$	41,569		$	5,660		$	(324	)	$	46,905
Capital expenditures	$	189,732		$	17,844		$	—		$	207,576

	Six Months Ended June 30, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	177,031		$	—		$	—		$	177,031
Natural gas	30,834			—			—			30,834
Natural gas liquids	21,467			—			—			21,467
Sales of gathered production	—			19,999			—			19,999
Midstream revenue	—			44,488			(30,784		)	13,704
Segment sales revenue	229,332			64,487			(30,784		)	263,035
Other revenue	898			14,374			(9,173		)	6,099
Operating revenue	230,230			78,861			(39,957		)	269,134
Gain on sale of assets	1,483			—			—			1,483
Gain (loss) on derivatives	(11,365		)	—			—			(11,365		)
Total revenue	220,348			78,861			(39,957		)	259,252
Operating expenses
Lease operating	44,231			—			(9,173		)	35,058
Transportation, processing and marketing	37,375			4,849			(30,784		)	11,440
Midstream operating	—			12,671			—			12,671
Cost of sales for purchased gathered production	—			18,415			—			18,415
Production taxes	10,600			—			—			10,600
Workovers	609			511			—			1,120
Exploration	5,343			—			—			5,343
Depreciation, depletion and amortization	69,179			6,729			—			75,908
Impairment of assets	6,500			—			—			6,500
General and administrative	36,670			13,387			6,633			56,690
Total operating expenses	210,507			56,562			(33,324		)	233,745
Operating income	9,841			22,299			(6,633		)	25,507
Other income (expense)
Interest expense	(26,901		)	(5,314		)	—			(32,215		)
Interest income	81			10			39			130
Equity in earnings of unconsolidated subsidiaries	—			742			—			742
Total other income (expense)	(26,820		)	(4,562		)	39			(31,343		)
Income (loss) from continuing operations before income taxes	(16,979		)	17,737			(6,594		)	(5,836		)
Interest expense	26,901			5,314			—			32,215
Depreciation, depletion and amortization	69,179			6,729			—			75,908
Loss on unrealized hedges	12,274			—			—			12,274
Impairment of assets	6,500			—			—			6,500
Equity-based compensation	3,057			462			—			3,519
Exploration	5,343			—			—			5,343
Severance costs	4,584			1,984			—			6,568
Strategic costs	4,061			—			—			4,061
Business Combination	10			—			—			10
Adjusted EBITDAX	$	114,930		$	32,226		$	(6,594	)	$	140,562
Equity method investment at period end	$	—		$	1,842		$	—		$	1,842
Capital expenditures	180,138			67,804			—			247,942
Total assets at period end	999,744			458,882			(6,569		)	1,452,057

	February 9, 2018 Through June 30, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	115,569		$	—		$	—		$	115,569
Natural gas	13,190			—			—			13,190
Natural gas liquids	14,955			—			—			14,955
Sales of gathered production	—			31,634			(18,837		)	12,797
Midstream revenue	—			23,671			(13,594		)	10,077
Segment sales revenue	143,714			55,305			(32,431		)	166,588
Other revenue	2,784			—			—			2,784
Operating revenue	146,498			55,305			(32,431		)	169,372
Gain (loss) on sale of assets	5,076			—			—			5,076
Gain (loss) on derivatives	(51,230		)	—			—			(51,230		)
Total revenue	100,344			55,305			(32,431		)	123,218
Operating expenses
Lease operating	20,996			—			—			20,996
Transportation, processing and marketing	16,788			5,561			(13,594		)	8,755
Midstream operating	—			3,900			—			3,900
Cost of sales for purchased gathered production	—			31,548			(18,837		)	12,711
Production taxes	4,021			—			—			4,021
Workovers	1,578			—			—			1,578
Exploration	9,668			—			—			9,668
Depreciation, depletion and amortization	37,708			11,905			—			49,613
Impairment of assets	—			—			—			—
General and administrative	52,465			6,313			1,430			60,208
Total operating expenses	143,224			59,227			(31,001		)	171,450
Operating income	(42,880		)	(3,922		)	(1,430		)	(48,232		)
Other income (expense)
Interest expense	(15,557		)	(1,666		)	—			(17,223		)
Interest income	1,366			—			4			1,370
Total other income (expense)	(14,191		)	(1,666		)	4			(15,853		)
Income (loss) from continuing operations before income taxes	(57,071		)	(5,588		)	(1,426		)	(64,085		)
Interest expense	15,557			1,666			—			17,223
Depreciation, depletion and amortization	37,708			11,905			—			49,613
Loss on unrealized hedges	32,896			—			—			32,896
Loss on sale of fixed assets	63			—			—			63
Equity-based compensation	6,389			507			833			7,729
Exploration	9,668			—			—			9,668
Business Combination	23,717			—			—			23,717
Adjusted EBITDAX	$	68,927		$	8,490		$	(593	)	$	76,824
Capital expenditures	$	319,042		$	21,589		$	—		$	340,631
Total assets at period end	2,817,714			1,427,792			8,152			4,253,658

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2019

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosures To The Consolidated Statements Of Cash Flows

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	29,513		$	22,996		$	1,145
Cash paid for income taxes, net of refunds	706			1,573			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	634			877			—
Increase (decrease) in accruals or payables for capital expenditures	(127,875		)	(25,798		)	4,896
Increase in withholding tax accruals for share-based compensation	165			—			—
Distribution of non-STACK assets, net of liabilities	—			—			43,482
Equity issued in Business Combination	—			2,067,393			—
Release of common stock from possible redemption	—			966,384			—
Tax effect of redemption of noncontrolling interests in SRII Opco for Class A common shares and other	—			(437)			—

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Summary Of Significant Accounting Policies (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Aug. 31, 2019	Apr. 01, 2019
Alta Mesa Credit Facility
Summary Of Significant Accounting Policies [Line Items]
Reduction in borrowing base	$ 30,000,000
Current borrowing capacity	400,000,000.0		$ 370,000,000.0
Monthly payments	$ 32,500,000
Subsequent Event | Alta Mesa Credit Facility
Summary Of Significant Accounting Policies [Line Items]
Credit facility amount		$ 200,000,000.0
Amount exceeding borrowing base		162,400,000
Subsequent Event | Upstream
Summary Of Significant Accounting Policies [Line Items]
Cash		63,000,000.0
Subsequent Event | SRII Opco
Summary Of Significant Accounting Policies [Line Items]
Cash		5,700,000
Subsequent Event | Kingfisher
Summary Of Significant Accounting Policies [Line Items]
Cash		$ 13,300,000

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Debt (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Long-Term Debt, Net And Notes Payable To Founder

(in thousands)	June 30, 2019		December 31, 2018
Alta Mesa RBL	$	344,500	$	161,000
KFM Credit Facility	218,000		174,000
2024 Notes	500,000		500,000
Unamortized premium on 2024 Notes	26,662		29,123
Total debt, net	1,089,162		864,123
Less: Current portion	1,089,162		690,123
Long-term debt, net	$	—	$	174,000

Summary Of Future Maturities Of Long-Term Debt

Fiscal year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	562,500
Thereafter	500,000
	$	1,062,500

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Condensed Consolidated Statement Of Changes In Stockholders' Equity (Unaudited) (Successor) - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock Common Class A	Common Stock Common Class B	Common Stock Common Class C	Paid-In Capital	Accumulated Deficit	Total Stockholders' Equity	Noncontrolling Interests
Balance (in shares) at Feb. 08, 2018		3,862	25,875
Balance at Feb. 08, 2018	$ (5,005)		$ 3		$ 3,106	$ (8,114)	$ (5,005)
Equity-based compensation expense	3,466				3,466		3,466
Net loss	(33,754)					(13,330)	(13,330)	$ (20,424)
Balance (in shares) at Mar. 31, 2018		169,372		213,402
Balance at Mar. 31, 2018	3,419,693	$ 17		$ 21	1,402,888	(21,444)	1,381,482	2,038,211
Balance (in shares) at Feb. 08, 2018		3,862	25,875
Balance at Feb. 08, 2018	(5,005)		$ 3		3,106	(8,114)	(5,005)
Class A common shares released from possible redemption	966,384
Balance (in shares) at Jun. 30, 2018		179,059		204,922
Balance at Jun. 30, 2018	3,409,611	$ 18		$ 20	1,498,023	(28,044)	1,470,017	1,939,594
Balance (in shares) at Mar. 31, 2018		169,372		213,402
Balance at Mar. 31, 2018	3,419,693	$ 17		$ 21	1,402,888	(21,444)	1,381,482	2,038,211
Class C common shares issued in connection with the closing of the Business Combination (in shares)				1,109
Noncontrolling interest in SRII Opco issued in the Business Combination	8,758							8,758
Class A common shares redeemed (in shares)		9,589		9,589
Class A common shares redeemed	(437)	$ 1		$ (1)	90,872		90,872	(91,309)
Restricted stock awards vested, net of taxes (in shares)		98
Equity-based compensation expense	4,263				4,263		4,263
Net loss	(22,666)					(6,600)	(6,600)	(16,066)
Balance (in shares) at Jun. 30, 2018		179,059		204,922
Balance at Jun. 30, 2018	3,409,611	$ 18		$ 20	1,498,023	(28,044)	1,470,017	1,939,594
Balance (in shares) at Dec. 31, 2018		180,072		202,170
Balance at Dec. 31, 2018	216,127	$ 18		$ 20	1,503,382	(1,532,813)	(29,393)	245,520
Restricted stock awards vested, net of taxes (in shares)		338
Restricted stock awards vested, net of taxes	(142)				67		67	(209)
Equity-based compensation expense	2,679				2,679		2,679
Net loss	(17,435)					(8,407)	(8,407)	(9,028)
Balance (in shares) at Mar. 31, 2019		180,410		202,170
Balance at Mar. 31, 2019	201,229	$ 18		$ 20	1,506,128	(1,541,220)	(35,054)	236,283
Balance (in shares) at Dec. 31, 2018		180,072		202,170
Balance at Dec. 31, 2018	216,127	$ 18		$ 20	1,503,382	(1,532,813)	(29,393)	245,520
Class A common shares released from possible redemption	0
Balance (in shares) at Jun. 30, 2019		182,636		199,988
Balance at Jun. 30, 2019	213,645	$ 18		$ 20	1,509,716	(1,538,975)	(29,221)	242,866
Balance (in shares) at Mar. 31, 2019		180,410		202,170
Balance at Mar. 31, 2019	201,229	$ 18		$ 20	1,506,128	(1,541,220)	(35,054)	236,283
Conversion of common shares from Class B to Class A at closing of Business Combination (in shares)		2,182		2,182
Conversion of common shares from Class B to Class A at closing of Business Combination					2,756		2,756	(2,756)
Restricted stock awards vested, net of taxes (in shares)		44
Restricted stock awards vested, net of taxes	(23)				(8)		(8)	(15)
Equity-based compensation expense	840				840		840
Net loss	11,599					2,245	2,245	9,354
Balance (in shares) at Jun. 30, 2019		182,636		199,988
Balance at Jun. 30, 2019	$ 213,645	$ 18		$ 20	$ 1,509,716	$ (1,538,975)	$ (29,221)	$ 242,866

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Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2019

Disposed of by Sale

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule Of Discontinued Operations

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Revenue
Oil	$	1,617
Natural gas	1,023
Natural gas liquids	236
Other	16
Operating revenue	2,892
Loss on sale of assets	(1,923		)
Total revenue	969
Operating expenses
Lease operating	1,770
Transportation and marketing	83
Production taxes	167
Workovers	127
Depreciation, depletion and amortization	884
Impairment of assets	5,560
General and administrative	21
Total operating expenses	8,612
Other expense
Interest expense	(103		)
Loss from discontinued operations, net of tax	$	(7,746	)

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Total operating cash flows of discontinued operations	$	2,974
Total investing cash flows of discontinued operations	(601		)

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Condensed Consolidated Statements Of Operations (Unaudited) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019
Revenue
Operating revenue		$ 133,305	$ 111,482	$ 169,372	$ 269,134
Gain (loss) on sale of assets		0	(63)	5,076	1,483
Gain (loss) on derivatives		12,412	(29,219)	(51,230)	(11,365)
Total revenue		145,717	82,200	123,218	259,252
Operating expenses
Lease operating		15,114	12,679	20,996	35,058
Transportation, processing and marketing		6,837	5,396	8,755	11,440
Midstream operating		6,520	3,313	3,900	12,671
Cost of sales for purchased gathered production		8,720	8,902	12,711	18,415
Production taxes		5,117	2,606	4,021	10,600
Workovers		807	333	1,578	1,120
Exploration		3,289	8,083	9,668	5,343
Depreciation, depletion and amortization		38,009	33,934	49,613	75,908
Impairment of assets		6,500	0	0	6,500
General and administrative		27,172	22,456	60,208	56,690
Total operating expenses		118,085	97,702	171,450	233,745
Operating income		27,632	(15,502)	(48,232)	25,507
Other income (expense)
Interest expense		(16,755)	(11,779)	(17,223)	(32,215)
Interest income		79	824	1,370	130
Equity in earnings of unconsolidated subsidiaries		643	0	0	742
Total other income (expense), net		(16,033)	(10,955)	(15,853)	(31,343)
Income (loss) from continuing operations before income taxes		11,599	(26,457)	(64,085)	(5,836)
Income tax provision (benefit)		0	(3,791)	(7,665)	0
Income (loss) from continuing operations		11,599	(22,666)	(56,420)	(5,836)
Loss from discontinued operations, net of tax		0	0	0	0
Net income (loss)		11,599	(22,666)	(56,420)	(5,836)
Net income (loss) attributable to noncontrolling interests		9,354	(16,066)	(36,490)	326
Net income (loss) attributable to Alta Mesa Resources, Inc. stockholders		$ 2,245	$ (6,600)	$ (19,930)	$ (6,162)
Income (loss) per share - basic and diluted (in USD per share)		$ 0.01	$ (0.04)	$ (0.12)	$ (0.03)
Weighted average shares outstanding - basic (in shares)		180,742,049	173,345,982	171,908,486	180,505,318
Weighted average shares outstanding - diluted (in shares)		180,742,049	207,965,929	208,112,707	180,505,318
Oil
Revenue
Operating revenue		$ 90,668	$ 75,291	$ 115,569	$ 177,031
Natural gas
Revenue
Operating revenue		12,384	7,980	13,190	30,834
Natural gas liquids
Revenue
Operating revenue		10,251	10,241	14,955	21,467
Sales of gathered production
Revenue
Operating revenue		10,439	8,924	12,797	19,999
Midstream revenue
Revenue
Operating revenue		6,549	6,817	10,077	13,704
Other
Revenue
Operating revenue		$ 3,014	$ 2,229	$ 2,784	$ 6,099
Predecessor
Revenue
Operating revenue	$ 40,136
Gain (loss) on sale of assets	840
Gain (loss) on derivatives	6,663
Total revenue	47,639
Operating expenses
Lease operating	4,408
Transportation, processing and marketing	3,725
Midstream operating	0
Cost of sales for purchased gathered production	0
Production taxes	953
Workovers	423
Exploration	7,003
Depreciation, depletion and amortization	11,670
Impairment of assets	0
General and administrative	21,234
Total operating expenses	49,416
Operating income	(1,777)
Other income (expense)
Interest expense	(5,511)
Interest income	172
Equity in earnings of unconsolidated subsidiaries	0
Total other income (expense), net	(5,339)
Income (loss) from continuing operations before income taxes	(7,116)
Income tax provision (benefit)	0
Income (loss) from continuing operations	(7,116)
Loss from discontinued operations, net of tax	(7,746)
Net income (loss)	(14,862)
Net income (loss) attributable to Alta Mesa Resources, Inc. stockholders	(14,862)
Predecessor | Oil
Revenue
Operating revenue	30,972
Predecessor | Natural gas
Revenue
Operating revenue	4,276
Predecessor | Natural gas liquids
Revenue
Operating revenue	4,000
Predecessor | Sales of gathered production
Revenue
Operating revenue	0
Predecessor | Midstream revenue
Revenue
Operating revenue	0
Predecessor | Other
Revenue
Operating revenue	$ 888

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2019

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	29,513		$	22,996		$	1,145
Cash paid for income taxes, net of refunds	706			1,573			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	634			877			—
Increase (decrease) in accruals or payables for capital expenditures	(127,875		)	(25,798		)	4,896
Increase in withholding tax accruals for share-based compensation	165			—			—
Distribution of non-STACK assets, net of liabilities	—			—			43,482
Equity issued in Business Combination	—			2,067,393			—
Release of common stock from possible redemption	—			966,384			—
Tax effect of redemption of noncontrolling interests in SRII Opco for Class A common shares and other	—			(437)			—

We aggregate cash, cash equivalents and restricted cash in the statements of cash flows.  

໿

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Derivatives

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVES  

The following summarizes the fair value and classification of our derivatives:

	June 30, 2019
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)
Derivatives, current assets	$	13,855	$	(9,128	)	$	4,727
Derivatives, long-term assets	11,977		(9,469		)	2,508
Total	$	25,832	$	(18,597	)	$	7,235

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)
Derivatives, current liabilities	$	9,968	$	(9,128	)	$	840
Derivatives, long-term liabilities	9,658		(9,469		)	189
Total	$	19,626	$	(18,597	)	$	1,029

	December 31, 2018
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)
Derivatives, current assets	$	22,512	$	(6,089	)	$	16,423
Derivatives, long-term assets	7,910		(4,963		)	2,947
Total	$	30,422	$	(11,052	)	$	19,370

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)
Derivatives, current liabilities	$	7,799	$	(6,089	)	$	1,710
Derivatives, long-term liabilities	5,143		(4,963		)	180
Total	$	12,942	$	(11,052	)	$	1,890

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

	Successor											Predecessor
Derivatives not designated as hedges	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives -
Oil	$	5,134	$	(28,712	)	$	(16,535	)	$	(50,656	)	$	4,796
Natural gas	7,278		(507		)	5,170			(574		)	1,867
Total gain (loss) on derivatives	$	12,412	$	(29,219	)	$	(11,365	)	$	(51,230	)	$	6,663

Other receivables at June 30, 2019 and December 31, 2018 include $1.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the next month.

We had the following call and put derivatives at June 30, 2019:

OIL

	Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	92,000	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	1,361,600	66.31		75.20		56.50
Long Put Options	1,453,600	53.80		62.00		50.00
Short Put Options	1,453,600	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	1,017,600	63.95		73.80		59.55
Long Put Options	1,566,600	56.81		62.50		50.00
Short Put Options	1,566,600	42.81		50.00		37.50
2021
Collar Contracts
Short Call Options	279,750	63.51		63.75		63.35
Long Put Options	659,850	46.94		55.00		41.00
Short Put Options	279,750	43.00		43.00		43.00

NATURAL GAS

	Volume	Weighted			Range
Settlement Period and Type of Contract	in MMBtu	Average			High			Low
2019
Price Swap Contracts	7,980,000	$	2.67		$	2.72		$	2.64
Basis Swap Contracts	9,680,000	(0.72		)	(0.49		)	(0.93		)
Collar Contracts
Short Call Options	1,525,000	3.19			3.20			3.17
Long Put Options	1,525,000	2.70			2.70			2.70
Short Put Options	1,525,000	2.20			2.20			2.20
2020
Price Swap Contracts	1,284,000	2.54			2.54			2.54
Basis Swap Contracts	910,000	(0.49		)	(0.49		)	(0.50		)
Collar Contracts
Short Call Options	3,874,500	3.19			3.69			2.77
Long Put Options	10,749,500	2.59			3.00			2.50
Short Put Options	9,696,000	2.10			2.50			2.00
2021
Collar Contracts
Short Call Options	540,000	3.25			3.25			3.25
Long Put Options	2,790,000	2.62			2.65			2.50
Short Put Options	2,250,000	2.15			2.15			2.15

We had the following basis swaps at June 30, 2019:

Total Gas Volumes in MMBtu(1) over Remaining Term	Reference Price 1 (1)	Reference Price 2 (1)	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
7,990,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jul '19	—	Dec '19	(0.70		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
1,230,000	San Juan	NYMEX Henry Hub	Jul '19	—	Oct '19	(0.81		)

________________

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

During September 2019, we closed out all open derivative positions resulting in net proceeds of approximately $4 million, which we applied against our outstanding borrowings under the Alta Mesa RBL.

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Property And Equipment (Depreciation and Depletion Expense) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019
Property, Plant and Equipment [Line Items]
Oil and gas properties depletion		$ 33,923	$ 26,086	$ 36,859	$ 67,965
Midstream tangible asset depreciation		3,504	2,010	3,132	6,724
Other property and equipment depreciation		341	423	586	749
Total depletion and depreciation		$ 37,768	$ 28,519	$ 40,577	$ 75,438
Predecessor
Property, Plant and Equipment [Line Items]
Oil and gas properties depletion	$ 11,021
Midstream tangible asset depreciation	0
Other property and equipment depreciation	609
Total depletion and depreciation	$ 11,630

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Derivatives (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		$ 12,412	$ (29,219)	$ (51,230)	$ (11,365)
Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	$ 6,663
Derivatives Not Designated As Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		12,412	(29,219)	(51,230)	(11,365)
Derivatives Not Designated As Hedging | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		5,134	(28,712)	(50,656)	(16,535)
Derivatives Not Designated As Hedging | Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		$ 7,278	$ (507)	$ (574)	$ 5,170
Derivatives Not Designated As Hedging | Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	6,663
Derivatives Not Designated As Hedging | Predecessor | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	4,796
Derivatives Not Designated As Hedging | Predecessor | Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	$ 1,867

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Derivatives (Basis Swap Derivative Contracts) (Details) - Natural Gas Basis Swap Derivative Contracts	6 Months Ended
	Jun. 30, 2019 MMBTU $ / MMBTU
Jul 19 - Dec 19
Derivative [Line Items]
Volume in MMbtu | MMBTU	460,000
Weighted average spread | $ / MMBTU	(0.93)
Jan 19 - Dec 19
Derivative [Line Items]
Volume in MMbtu | MMBTU	7,990,000
Weighted average spread | $ / MMBTU	(0.70)
Jan 20 - Mar 20
Derivative [Line Items]
Volume in MMbtu | MMBTU	910,000
Weighted average spread | $ / MMBTU	(0.49)
Jan 19 - Oct 19
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,230,000
Weighted average spread | $ / MMBTU	(0.81)