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 September 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: None.

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 October 31, 2019, there were 182,774,952 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 528,041 nonvested restricted stock awards outstanding as of October 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	33
Item 3. Quantitative and Qualitative Disclosures about Market Risk	53
Item 4. Controls and Procedures	53
PART II - OTHER INFORMATION
Item 1. Legal Proceedings	54
Item 1A. Risk Factors	55
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 3. Defaults Upon Senior Securities	59
Item 4. Mine Safety Disclosures	60
Item 5. Other Information	60
Item 6. Exhibits	61
Signatures	62

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 Successor Period from February 9, 2018 through September 30, 2018 and Predecessor Period from January 1, 2018 through February 8, 2018.
2019 Period -	The nine months ended September 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, 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 Kingfisher 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 September 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 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;

• 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.

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

1

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; our ability to negotiate a waiver under the KFM Credit Facility and the ability of the KFM lenders to accelerate the repayment of KFM’s borrowings; 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 this Quarterly Report and in our 2018 10-K.

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 or in the 2018 10-K 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. (Debtor-in-possession)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

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

	Successor												Predecessor
	Three Months Ended September 30, 2019			Three Months Ended September 30, 2018			Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Revenue
Oil	$	84,010		$	107,253		$	261,041		$	222,822		$	30,972
Natural gas	10,788			11,959			41,622			25,149			4,276
Natural gas liquids	8,333			13,880			29,800			28,835			4,000
Sales of gathered production	8,387			9,129			28,386			21,926			—
Midstream revenue	5,882			7,802			19,586			17,879			—
Other	2,143			1,011			8,242			3,795			888
Operating revenue	119,543			151,034			388,677			320,406			40,136
Gain (loss) on sale of assets	(106		)	(18		)	1,377			5,058			840
Gain (loss) on derivatives	(379		)	(11,212		)	(11,744		)	(62,442		)	6,663
Total revenue	119,058			139,804			378,310			263,022			47,639
Operating expenses
Lease operating	14,192			16,351			49,250			37,347			4,408
Transportation, processing and marketing	6,179			5,181			17,619			13,936			3,725
Midstream operating	6,621			4,507			19,292			8,407			—
Cost of sales for purchased gathered production	7,656			9,461			26,071			22,172			—
Production taxes	4,673			6,311			15,273			10,332			953
Workovers	783			1,065			1,903			2,643			423
Exploration	40,847			1,029			46,190			10,697			7,003
Depreciation, depletion and amortization	36,999			53,103			112,907			102,716			11,670
Impairment of assets	691,123			—			697,623			—			—
General and administrative	27,992			11,902			84,682			72,110			21,234
Total operating expenses	837,065			108,910			1,070,810			280,360			49,416
Operating income	(718,007		)	30,894			(692,500		)	(17,338		)	(1,777		)
Other income (expense)
Interest expense	(15,145		)	(12,347		)	(47,360		)	(29,570		)	(5,511		)
Interest income	69			357			199			1,727			172
Equity in earnings of unconsolidated subsidiaries	(29		)	—			713			—			—
Reorganization items, net	22,467			—			22,467			—			—
Total other income (expense), net	7,362			(11,990		)	(23,981		)	(27,843		)	(5,339		)
Income (loss) from continuing operations before income taxes	(710,645		)	18,904			(716,481		)	(45,181		)	(7,116		)
Income tax provision (benefit)	—			1,504			—			(6,161		)	—
Income (loss) from continuing operations	(710,645		)	17,400			(716,481		)	(39,020		)	(7,116		)
Loss from discontinued operations, net of tax	—			—			—			—			(7,746		)
Net income (loss)	(710,645		)	17,400			(716,481		)	(39,020		)	$	(14,862	)
Net income (loss) attributable to noncontrolling interests	(368,458		)	10,427			(368,132		)	(26,063		)
Net income (loss) attributable to Alta Mesa Resources, Inc. stockholders	$	(342,187	)	$	6,973		$	(348,349	)	$	(12,957	)
Attributable to Alta Mesa Resources, Inc. stockholders:
Income (loss) per share - basic	$	(1.87	)	$	0.04		$	(1.92	)	$	(0.07	)
Income (loss) per share - diluted	$	(1.87	)	$	0.04		$	(1.92	)	$	(0.08	)

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

3

ALTA MESA RESOURCES, INC. (Debtor-in-possession)

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands, except shares and per share data)

໿

	September 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	69,325	$	26,854
Restricted cash	951		1,001
Accounts receivable, net	66,386		87,842
Other receivables	1,171		6,331
Related party receivables, net	—		3,341
Prepaid expenses and other	9,784		1,125
Derivatives	—		16,423
Total current assets	147,617		142,917
Property and equipment, net
Oil and gas properties, successful efforts method	365,343		763,337
Other property and equipment	166,575		444,269
Total property and equipment, net	531,918		1,207,606
Other assets
Operating lease right-of-use assets, net	7,402		—
Equity method investment	1,813		1,100
Deferred financing costs, net	1,720		3,195
Deposits and other long-term assets	6,597		65
Derivatives	—		2,947
Total other assets	17,532		7,307
Total assets	$	697,067	$	1,357,830

	September 30, 2019			December 31, 2018
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt	$	564,004		$	690,123
Accounts payable and accrued liabilities	61,001			247,439
Advances from non-operators	619			5,193
Advances from related party	2,611			9,839
Asset retirement obligations, current portion	74			2,079
Current operating lease liability	736			—
Derivatives	—			1,710
Total current liabilities	629,045			956,383
Long-term liabilities
Asset retirement obligations, net of current portion	12,868			9,473
Long-term debt, net	—			174,000
Operating lease liabilities, net of current portion	10,781			—
Derivatives	—			180
Other long-term liabilities	6,662			1,667
Total long-term liabilities	30,311			185,320
Liabilities subject to compromise	533,181			—
Total liabilities	1,192,537			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; 182,765,278 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 September 30, 2019 and December 31, 2018	20			20
Additional paid in capital	1,511,330			1,503,382
Accumulated deficit	(1,881,162		)	(1,532,813		)
Total stockholders’ equity	(369,794		)	(29,393		)
Noncontrolling interests	(125,676		)	245,520
Total equity	(495,470		)	216,127
Total liabilities and stockholders’ equity	$	697,067		$	1,357,830

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

4

ALTA MESA RESOURCES, INC. (Debtor-in-possession)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)

	Successor						Predecessor
	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Cash flows from operating activities:
Net loss	$	(716,481	)	$	(39,020	)	$	(14,862	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	112,907			102,716			12,554
Non-cash lease expense	2,343			—			—
Provision for uncollectible receivables	3,449			—			—
Impairment of assets	697,623			—			5,560
Non-cash reorganization items, net	(25,142		)	—			—
Amortization of deferred financing costs	541			339			171
Amortization of debt premium	(3,432		)	(3,281		)	—
Equity-based compensation expense	5,025			8,333			—
Non-cash exploration expense	40,245			7,288			4,575
(Gain) loss on derivatives	11,744			62,442			(6,663		)
Cash settlements of derivatives	7,642			(32,201		)	(2,296		)
Cash paid for derivatives	(1,906		)	—			—
Interest converted into debt	—			—			103
Interest added to notes receivable from affiliate	—			(680		)	(85		)
Deferred tax provision (benefit)	—			(5,378		)	—
Loss on sale of fixed assets	105			81			1,923
Equity in earnings of unconsolidated subsidiaries	(713		)	—			—
Impact on cash from changes in:
Accounts receivable	21,193			(16,225		)	(21,184		)
Other receivables	5,161			972			(662		)
Related party receivables	154			(14,488		)	(117		)
Prepaid expenses and other assets	(15,190		)	8,368			(591		)
Advances from related party	(7,231		)	(30,589		)	24,116
Settlement of asset retirement obligations	(180		)	(1,249		)	(63		)
Accounts payable, accrued liabilities and other liabilities	(6,135		)	(44,922		)	23,857
Operating lease obligations	(2,270		)	—			—
Cash from operating activities	129,452			2,506			26,336
Cash flows from investing activities:
Capital expenditures	(315,894		)	(523,645		)	(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	—			(9,326		)	—
Cash from investing activities	(315,894		)	(282,048		)	(37,913		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	238,500			162,500			60,000
Repayments of long-term debt	(9,496		)	(193,565		)	(43,000		)
Payment of taxes withheld on equity-based compensation awards	(141		)	—			—
Deferred financing costs paid	—			(3,716		)	—
Purchase and retirement of Class A common shares	—			(14,750		)	—
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	228,863			312,211			16,932
Net increase in cash, cash equivalents and restricted cash	42,421			32,669			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	$	70,276		$	33,057		$	10,345

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

5

ALTA MESA RESOURCES, INC. (Debtor-in-possession)

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
Purchase and retirement of Class A common shares and related sale of SRII Opco Common Units	(3,102	)	—		—		—			—		—			(25,589		)	—			(25,589		)	10,839			(14,750		)
Adjustment to valuation allowance related to prior redemption of noncontrolling interests and Class C common shares for Class A common shares	—		—		—		—			—		—			(468		)	—			(468		)	—			(468		)
Equity-based compensation expense	—		—		—		—			—		—			604			—			604			—			604
Net income	—		—		—		—			—		—			—			6,973			6,973			10,427			17,400
Balance at September 30, 2018	175,957		$	18	—		$	—		204,922		$	20		$	1,472,570		$	(21,071	)	$	1,451,537		$	1,960,860		$	3,412,397

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

6

ALTA MESA RESOURCES, INC. (Debtor-in-possession)

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 shares	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
Restricted stock awards vested, net of taxes	129	—		—	—		—		—		108			—			108			(84		)	24
Equity-based compensation	—	—		—	—		—		—		1,506			—			1,506			—			1,506
Net loss	—	—		—	—		—		—		—			(342,187		)	(342,187		)	(368,458		)	(710,645		)
Balance at September 30, 2019	182,765	$	18	—	$	—	199,988		$	20	$	1,511,330		$	(1,881,162	)	$	(369,794	)	$	(125,676	)	$	(495,470	)

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

7

ALTA MESA RESOURCES, INC. (Debtor-in-possession)

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. (Debtor-in-possession)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Description of Business and Business Combination

Alta Mesa Resources, Inc. (“AMR”), together with its consolidated subsidiaries (“we,” “us,” “our” 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. Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. 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 vital 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.”

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.

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. 

Bankruptcy Accounting

As discussed further in Note 3, on September 11, 2019, AMR, 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 AMR, the “Debtors”) filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Debtors will 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. The condensed consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s condensed consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on the Company’s condensed consolidated balance sheet at September 30, 2019. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. The accompanying condensed consolidated financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the condensed consolidated financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on stockholders’ deficit accounts of any changes that may be made to the Company’s capitalization; or (iv) the effect on operations of any changes that may be made to the Company’s business. While operating as debtor-in-possession under Chapter 11 of the Bankruptcy Code, the Company may sell or otherwise dispose of or liquidate

9

assets or settle liabilities in amounts other than those reflected on its condensed consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications on the Company’s historical condensed consolidated financial statements.

Ability to Continue as a Going Concern

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. In September 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. The Administrative Agent and the lenders have reserved their right to pursue any remedies available to them, including charging the default rate of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral. Although the Administrative Agent and the lenders have not taken any such actions, KFM will not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact AMR’s and KFM’s ability to meet all financial obligations as they come due and KFM’s ability to make distributions to AMR that otherwise may have been permitted. As a result of Alta Mesa’s bankruptcy and the limitations imposed under a Bankruptcy Court approved cash collateral agreement and alleged defaults under the KFM Credit Facility, AMR’s only remaining source of liquidity is through non-debtor subsidiary SRII Opco. At October 31, 2019, SRII Opco had cash on hand of $5.5 million. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.

Basis of Presentation

These financial statements include the consolidated financial positions, results of operations and cash flows of the Company, the AMH Debtors and our non-debtor subsidiaries, which are controlled by us. 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 nine months ended September 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 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, (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses and (iii) provide additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. Based on a tentative decision by the FASB, we expect this standard, including related amendments, will be effective for us beginning January 2023. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

10

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 expect to apply the new standard 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 - CHAPTER 11 PROCEEDINGS

Voluntary Reorganization Under Chapter 11

On September 11, 2019, the Debtors filed the Bankruptcy Petitions for reorganization under the Bankruptcy Code in 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 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.

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, (together the “non-Debtors”) are not in bankruptcy or otherwise part of the Chapter 11 cases at this time.

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Bankruptcy Petitions. Accordingly, although the filing of the Bankruptcy Petitions triggered defaults on the AMH Debtors’ debt obligations, the creditors are stayed from taking any actions against the AMH Debtors as a result of such defaults, subject to certain limited exceptions provided by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the AMH Debtors’ prepetition liabilities are subject to compromise under the Bankruptcy Code.

Initial Orders and Other Filings

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 have been authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The current cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral until November 21, 2019 on the terms and conditions agreed by the AMH Debtors and their creditors (including the lenders under the Alta Mesa RBL) as set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain other milestones related to sale of the Debtor assets. The 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.

On September 27, 2019, the United States Trustee for the Southern District of Texas appointed an official committee of unsecured creditors. On October 18, 2019, the Debtors filed schedules and statements with the Bankruptcy Court setting forth,

11

among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing. Except as otherwise provided by the Bankruptcy Court, proofs of prepetition claims, including those arising from subsequent rejection of executory contracts and unexpired leases, must be on file by December 9, 2019, or by March 9, 2020, in the case of claims by governmental units. Differences between amounts scheduled by the Debtors and claims by creditors will be evaluated and resolved in connection with the claims resolution process.

The Debtors are in a marketing process to sell their assets along with KFM’s midstream assets. On October 11, 2019, the Bankruptcy Court entered an order approving, among other things, proposed bidding procedures and the dates for an auction, a hearing to approve the sale or sales of assets, and related dates and deadlines. The auction is scheduled to occur on January 8, 2020 and the sale hearing is scheduled to occur on January 10, 2020. Both of the scheduled dates are subject to postponement.

Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that (i) the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions and non-Debtors KFM and its subsidiaries can be rejected by the Debtors, (ii) certain amendments to the crude oil and gas gathering agreements were constructive and actual fraudulent transfers, (iii) the crude oil and gas gathering agreements are subject to rescission as the products of breaches of fiduciary duty, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement is therefore terminated. On October 25, 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFM and Oklahoma Produced Water Solutions, LLC as Defendants. On November 4, 2019, the plaintiff AMH Debtors provided notice of alleged events of default under the crude oil and gas gathering agreements and reserved their rights and remedies, including termination of those agreements. The plaintiff AMH Debtors have also submitted a motion to file a second amended complaint to include these events of default allegations. The litigation is set for trial on December 9, 2019.

Liabilities Subject to Compromise

Liabilities subject to compromise represent the Debtors’ prepetition liabilities that have been allowed or that the Debtors anticipate will be allowed as claims in its Chapter 11 cases. The amounts represent the Debtors’ current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings. The differences between the liabilities the Debtors has estimated and the claims filed, or to be filed, will be evaluated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 proceedings and adjust as necessary.

Following are the components of liabilities subject to compromise included on the condensed consolidated balance sheet:

(in thousands)	September 30, 2019
2024 Notes	$	500,000
Accounts payable and accrued liabilities	21,670
Accrued interest payable on 2024 Notes	9,515
Operating lease liabilities	1,996
Liabilities subject to compromise	$	533,181

Reorganization Items

The Company has incurred and is expected to continue to incur significant costs associated with the bankruptcy. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date and also includes adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.

Following are the components of reorganization items, net included in our Condensed Consolidated Statements of Operations:

12

(in thousands)	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Unamortized deferred financing fees and premiums	$	24,748		$	24,748
Terminated contracts	394			394
Legal and other professional advisory fees	(2,675		)	(2,675		)
Reorganization items, net	$	22,467		$	22,467

Interest Expense

Subject to certain exceptions, under the Bankruptcy Code, the filing of Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to cover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ prepetition liabilities are subject to settlement under the Bankruptcy Code. Although the filing of Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. The Company did not record interest expense on its 2024 Notes for the period September 12, 2019 through September 30, 2019. For that period, the unrecorded contractual interest was approximately $2.0 million.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign or reject certain executory contracts subject to the approval of the Bankruptcy Court and fulfillment of certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a prepetition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to prepetition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtors’ estate for damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with any of the Debtors in this Quarterly Report on Form 10-Q, including where applicable a quantification of the Company’s obligations under any such executory contract or unexpired lease with the applicable Debtor, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto.

On September 26, 2019, the Bankruptcy Court approved our request to reject an office lease extending through November 2023. Pursuant to this rejection, we de-recognized the right-of-use asset and liability, which resulted in a gain of $0.4 million (included in reorganization items, net). In October 2019, an additional lease and other less significant contracts were also rejected by the Bankruptcy Court. Pursuant to this rejection, we reported the corresponding current and long-term lease liability as liabilities subject to compromise at September 30, 2019.

13

Condensed Combined Financial Information of Debtors

Combined Statement of Operations (Unaudited)

(in thousands)	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Revenue
Oil	$	84,010		$	261,041
Natural gas	10,788			41,622
Natural gas liquids	8,333			29,800
Other	302			1,200
Operating revenue	103,433			333,663
Gain on sale of assets	—			1,483
Loss on derivatives	(379		)	(11,744		)
Total revenue	103,054			323,402
Operating expenses
Lease operating	18,071			62,302
Transportation and marketing	17,561			54,936
Production taxes	4,673			15,273
Workovers	757			1,366
Exploration	40,847			46,190
Depreciation, depletion and amortization	33,407			102,586
Impairment of assets	387,721			394,221
General and administrative	19,781			62,869
Total operating expenses	522,818			739,743
Operating income	(419,764		)	(416,341		)
Other income (expenses)
Interest expense	(12,233		)	(39,134		)
Interest income	45			126
Reorganization items, net	22,467			22,467
Total other income (expense), net	10,279			(16,541		)
Loss from continuing operations before income taxes	(409,485		)	(432,882		)
Net loss	$	(409,485	)	$	(432,882	)

14

Combined Balance Sheet (Unaudited)

(in thousands)	September 30, 2019
ASSETS
Current assets
Cash and cash equivalents	$	58,143
Restricted cash	951
Accounts receivable, net	55,666
Other receivables	1,171
Related party receivables, net	17,419
Note receivables from related parties, net	—
Prepaid expenses and other current assets	6,948
Total current assets	140,298
Property and equipment, net
Oil and gas properties, successful efforts method	365,343
Other property and equipment	36,818
Total property and equipment, net	402,161
Other assets
Investment in subsidiary	1,504,147
Operating lease right-of-use assets, net	7,113
Deposits and other long-term assets	6,171
Total other assets	1,517,431
Total assets	$	2,059,890
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	340,004
Accounts payable and accrued liabilities	51,722
Accounts payable - related parties	18,301
Advances from non-operators	619
Advances from related party	2,607
Asset retirement obligations, current portion	74
Current operating lease liability	650
Total current liabilities	413,977
Long-term liabilities
Asset retirement obligations, net of current portion	12,717
Operating lease liabilities, net of current portion	10,569
Total long-term liabilities	23,286
Liabilities subject to compromise	533,181
Total liabilities	970,444
Partners’ capital	1,089,446
Total liabilities and partners’ capital	$	2,059,890

15

Combined Statement of Cash Flows (Unaudited)

(in thousands)	Nine Months Ended September 30, 2019
Cash flows from operating activities:
Net loss	$	(432,882	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	102,586
Non-cash lease expense	2,216
Provision for uncollectible receivables	1,139
Impairment of assets	394,221
Non-cash reorganization items, net	(25,142		)
Amortization of deferred financing costs	195
Amortization of debt premium	(3,432		)
Equity-based compensation expense	4,453
Non-cash exploration expense	40,245
(Gain) loss on derivatives	11,744
Cash settlements of derivatives	7,642
Cash paid for derivatives	(1,906		)
Impact on cash from changes in:
Accounts receivable	12,441
Other receivables	5,097
Related party receivables	3,826
Prepaid expenses and other assets	(12,127		)
Advances from related party	(7,215		)
Settlement of asset retirement obligations	(180		)
Accounts payable, accrued liabilities and other liabilities	8,494
Operating lease obligations	(2,151		)
Cash from operating activities	109,264
Cash flows from investing activities:
Capital expenditures	(243,709		)
Distribution received from subsidiary	691
Cash from investing activities	(243,018		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	183,500
Repayments of long-term debt	(4,496		)
Payment of taxes withheld on equity-based compensation awards	(141		)
Cash from financing activities	178,863
Net increase in cash, cash equivalents and restricted cash	45,109
Cash, cash equivalents and restricted cash, beginning of period	13,985
Cash, cash equivalents and restricted cash, end of period	$	59,094

16

NOTE 4 — IMPAIRMENT OF ASSETS

	Successor								Predecessor
(in thousands)	Three Months Ended September 30, 2019		Three Months Ended September 30, 2018		Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018		January 1, 2018 Through February 8, 2018
Upstream
Impairment of proved properties	$	387,721	$	—	$	387,721	$	—	$	—
Impairment of operating lease right-of-use assets	—		—		6,500		—		—
Total Upstream impairment of assets	387,721		—		394,221		—		—
Midstream
Impairment of property and equipment	303,402		—		303,402		—		—
Total Midstream impairment of assets	303,402		—		303,402		—		—
Total impairment of assets	$	691,123	$	—	$	697,623	$	—	$	—

Impairment of Proved Properties

AMR and the AMH Debtors filed for bankruptcy protection in September 2019. As a result, our ability to incur the levels of spending necessary to continue to develop our properties has been significantly restricted. This has negatively impacted our future drilling plans and our expectations regarding production levels from our properties. As a result, we conducted an assessment of impairment and recognized impairment expense for our proved properties at September 30, 2019. In determining the amount of impairment for our properties, we utilized future expected cash flows from those properties (a Level 3 input), discounted at a market participant rate to estimate fair value.

Impairment of Operating Lease Right-of-Use Assets

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.

Impairment of Midstream Property and Equipment

The majority of the oil, gas and produced water volumes gathered and processed by our Midstream segment arise from our Upstream segment. Due to the factors mentioned above, the volumes gathered and processed by our Midstream segment are expected to decline, resulting in reduced throughput and value of our Midstream assets. Accordingly, we conducted an assessment of impairment and recognized impairment expense for our Midstream property and equipment at September 30, 2019. In determining the amount of impairment for our Midstream property and equipment, we utilized future expected cash flows from those assets (a Level 3 input), discounted at a market participant rate to estimate fair value.

NOTE 5 — 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

17

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 September 30, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.3 years and the weighted-average discount rate applied was 14.5%.

Lease Costs

(in thousands)	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost	$	668	$	2,343
Variable lease cost	210		1,059
Short-term lease cost	422		4,072
Total lease cost	$	1,300	$	7,474
Reported in:
Lease operating expense	$	378	$	4,016
General and administrative expense	922		3,458
Total lease cost	$	1,300	$	7,474

18

Remaining Operating Lease Liability Payments as of September 30, 2019

Fiscal year	(in thousands)
Remainder of 2019	$	649
2020	2,614
2021	2,581
2022	2,713
2023	2,718
Thereafter	12,647
Total lease payments	23,922
Less: imputed interest	(10,409		)
Less: reclassification to liabilities subject to compromise	(1,996		)
Present value of operating lease liabilities not subject to compromise	$	11,517
Current portion of operating lease liabilities	$	736
Operating lease liabilities, net of current portion	10,781
Present value of operating lease liabilities not subject to compromise	$	11,517

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.

NOTE 6 - 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:

19

	Three Months Ended September 30, 2019			Three Months Ended September 30, 2018		Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018
	(in thousands, except shares and per share data)
Net income (loss) attributable to AMR Class A common stockholders	$	(342,187	)	$	6,973	$	(348,349	)	$	(12,957	)
Effect of dilutive Class C securities:
Net loss attributable to noncontrolling interests assumed to be redeemed for Class A Common Stock, net of tax	—			4,869		—			(5,227		)
Net income (loss) attributable to AMR Class A common stockholders after assumed redemption	$	(342,187	)	$	11,842	$	(348,349	)	$	(18,184	)
Weighted average Class A common shares outstanding (Basic)	182,716,273			178,078,132		181,250,401			174,364,715
Effect of dilutive securities:
Class A shares assumed issued to holders of noncontrolling interests upon redemption	—			132,428,358		—			59,006,903
Restricted stock and stock options	—			31,342		—			—
Weighted average common shares outstanding (Diluted)	182,716,273			310,537,832		181,250,401			233,371,618
Income (loss) per common share attributable to AMR common stockholders:
Basic	$	(1.87	)	$	0.04	$	(1.92	)	$	(0.07	)
Diluted	$	(1.87	)	$	0.04	$	(1.92	)	$	(0.08	)

NOTE 7 — SUPPLEMENTAL CASH FLOW INFORMATION

	Successor						Predecessor
(in thousands)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	35,866		$	24,950		$	1,145
Cash paid for income taxes, net of refunds	706			1,573			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	831			4,652			—
Increase (decrease) in accruals or payables for capital expenditures	(147,756		)	41,069			4,896
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	—			(905		)	—
Increase in accounts receivable for sale of assets	—			(524		)	—

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

໿

NOTE 8 — RECEIVABLES

Accounts Receivable

(in thousands)	September 30, 2019			December 31, 2018
Production and processing sales and fees	$	40,348		$	51,004
Joint interest billings	17,411			18,147
Pooling interest (1)	8,974			18,786
Allowance for doubtful accounts	(347		)	(95		)
Total accounts receivable, net	$	66,386		$	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)	September 30, 2019			December 31, 2018
Related party receivables	$	12,135		$	12,375
Allowance for doubtful accounts	(12,135		)	(9,034		)
Related party receivables, net	—			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	$	—		$	3,341

20

At December 31, 2018, we had a receivable of $2.3 million from KFM’s former owner, KFM Holdco, LLC (“KFM Holdco”), relating to transaction costs paid on KFM Holdco’s behalf before the Business Combination. During the third quarter 2019, we fully reserved this receivable based upon our assessment regarding collectibility. We have filed suit against KFM Holdco to seek payment for this receivable.

Management Services Agreement with High Mesa

(in thousands)	September 30, 2019
High Mesa related party receivable at December 31, 2018	$	10,066
Additions	832
Payments	(1,073		)
High Mesa related party receivable at September 30, 2019	9,825
Allowance for uncollectibility(1)	(9,825		)
Balance at September 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 September 30, 2019, and December 31, 2018, approximately $9.8 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 $9.8 million and $9.0 million as of September 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 September 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 September 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 September 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.

21

NOTE 9 — PROPERTY AND EQUIPMENT

(in thousands)	September 30, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	816,858		$	816,282
Accumulated impairment of unproved properties	(782,287		)	(742,065		)
Unproved properties, net	34,571			74,217
Proved oil and gas properties	2,240,337			2,110,346
Accumulated depletion and impairment	(1,909,565		)	(1,421,226		)
Proved oil and gas properties, net	330,772			689,120
Total oil and gas properties, net	365,343			763,337
Other property and equipment
Land	5,600			5,600
Fresh water wells	27,373			27,366
Produced water disposal system	108,422			104,498
Gas processing plant and gathering lines	413,793			380,470
Office furniture, equipment and vehicles	3,687			3,703
Accumulated depreciation and impairment	(392,300		)	(77,368		)
Other property and equipment, net	166,575			444,269
Total property and equipment, net	$	531,918		$	1,207,606

During the third quarter, we recognized a charge of $11.2 million as exploration expense to reduce unproved properties for third and fourth quarter 2019 expirations of leased acreage. As a significant portion of these expirations were located in Major County, we determined that, given limited availability of development capital, our intent was to continue to let leased acreage in Major County expire in the normal course, thus abandoning development of Major County.  As such, we recorded an additional charge as exploration expense for all remaining acreage in Major County totaling $28.8 million. 

Depletion and Depreciation Expense

	Successor								Predecessor
(in thousands)	Three Months Ended September 30, 2019		Three Months Ended September 30, 2018		Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	32,652	$	44,593	$	100,617	$	81,452	$	11,021
Midstream depreciation	3,589		2,099		10,313		5,231		—
Other property and equipment depreciation	508		1,030		1,257		1,616		609
Total depletion and depreciation	$	36,749	$	47,722	$	112,187	$	88,299	$	11,630

22

NOTE 10 — 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		)

23

NOTE 11 — DERIVATIVES  

During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts for net proceeds of approximately $4.0 million. Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL. As of September 30, 2019, we held no open derivative positions.

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

	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 our statements of operations (in thousands):

	Successor												Predecessor
Derivatives not designated as hedges	Three Months Ended September 30, 2019			Three Months Ended September 30, 2018			Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives -
Oil	$	522		$	(12,339	)	$	(16,013	)	$	(62,995	)	$	4,796
Natural gas	(901		)	1,127			4,269			553			1,867
Total gain (loss) on derivatives	$	(379	)	$	(11,212	)	$	(11,744	)	$	(62,442	)	$	6,663

Other receivables at December 31, 2018 included $1.3 million of derivative positions settled in January 2019.

24

NOTE 12 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 

໿

(in thousands)	September 30, 2019			December 31, 2018
Accounts payable	$	22,406		$	20,422
Accruals for capital expenditures	4,879			139,904
Revenue and royalties payable	28,417			50,241
Accruals for operating expenses	18,324			21,830
Accrued interest	16,512			2,477
Derivative settlements	511			109
Other	1,137			12,456
Total accrued liabilities	69,780			227,017
Less: liabilities subject to compromise	(31,185		)	—
Accounts payable and accrued liabilities	$	61,001		$	247,439

NOTE 13 — ASSET RETIREMENT OBLIGATIONS 

	Successor						Predecessor
(in thousands)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 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	831			1,689			—
Liabilities settled	(180		)	(1,249		)	(63		)
Liabilities transferred in sale of properties	—			(20		)	—
Revisions to estimates	19			3,562			63
Accretion expense	720			489			40
Balance, end of period	12,942			10,469			10,509
Less: current portion	74			1,300			33
Long-term portion	$	12,868		$	9,169		$	10,476

NOTE 14 — DEBT

໿

(in thousands)	September 30, 2019			December 31, 2018
Alta Mesa RBL	$	340,004		$	161,000
KFM Credit Facility	224,000			174,000
2024 Notes	500,000			500,000
Unamortized premium on 2024 Notes	—			29,123
Total debt, net	1,064,004			864,123
Less: liabilities subject to compromise	(500,000		)	—
Less: current portion	(564,004		)	(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 no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their

25

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 above, AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments.

The Alta Mesa RBL has two covenants that were 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.

In September 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. The Administrative Agent and the lenders have reserved their right to pursue any remedies available to them, including charging the default rate of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral. Although the Administrative Agent and the lenders have not taken any such actions, KFM will not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact AMR’s and KFM’s ability to meet all financial obligations as they come due and KFM’s ability to make distributions to AMR that otherwise may have been permitted. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings. At October 31, 2019, undrawn borrowing capacity under the KFM Credit Facility totaled $76.0 million.

2024 Notes

We have estimated the fair value of the 2024 Notes to be $85.7 million at September 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)
2023	$	564,004
2024	500,000
	$	1,064,004

26

Based upon our going concern conclusions, the default associated with Alta Mesa’s bankruptcy filing and KFM’s projected covenant violations, we believe that all of our indebtedness should be reported as current liabilities despite their scheduled maturities shown above.

NOTE 15 — COMMITMENTS AND CONTINGENCIES 

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

At December 31, 2018, Alta Mesa had an $18.3 million letter of credit issued to provide financial assurance for a multi-year obligation. During 2019, this letter of credit was reduced by $2.4 million in the ordinary course. In November 2019, the transportation company demanded full payment of $15.9 million for non-payment of $0.5 million in prepetition claims. This amount was paid by the administrative agent of the Alta Mesa RBL, but we believe the claims arising under the transportation contract were stayed by Alta Mesa’s bankruptcy filing. A demand letter has been sent to the transportation company to return the excess payment above the prepetition claims. It is unclear if or when this matter will be resolved.

NOTE 16 — 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 September 30, 2019		Three Months Ended September 30, 2018		Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	7,643	$	114,109	$	117,003	$	234,850	$	28,757
Marketing and management fees paid to ARM	$	272	$	—	$	1,483	$	—	$	—
Fees paid to ARM for services relating to our derivatives	56		216		467		499		66
Total fees paid to ARM	$	328	$	216	$	1,950	$	499	$	66

Receivables from ARM for sales on our behalf were $5.4 million and $43.8 million as of September 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 17 — EQUITY-BASED COMPENSATION (Successor)

Stock compensation expense recognized was as follows:

	Successor									Predecessor
(in thousands)	Three Months Ended September 30, 2019		Three Months Ended September 30, 2018			Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018		January 1, 2018 Through February 8, 2018
Stock options	$	859	$	1,782		$	2,758	$	4,569	$	—
Restricted stock awards	600		1,271			2,068		3,764		—
Performance-based restricted stock units	47		(2,449		)	199		—		—
Total compensation expense	$	1,506	$	604		$	5,025	$	8,333	$	—

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

27

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 units issued in each tranche. 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 and our assessment of the probability of attainment of the established metrics.

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 18 — 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 $132,000 and $28,000 for the period February 9, 2018 through September 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 approximately $769,000, $1,089,000 and $29,000 during the nine months ended September 30, 2019, the period February 9, 2018 through September 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 approximately $242,000, $264,000, 67,000, for the nine months ended September 30, 2019, the period February 9, 2018 through September 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 September 30, 2019, 61 joint wells have been drilled or spudded. At September 30, 2019 and December 31, 2018, $2.6 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 September 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.

28

NOTE 19 — BUSINESS SEGMENT INFORMATION

	Three Months Ended September 30, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	84,010		$	—		$	—		$	84,010
Natural gas	10,788			—			—			10,788
Natural gas liquids	8,333			—			—			8,333
Sales of gathered production	—			8,387			—			8,387
Midstream revenue	—			20,326			(14,444		)	5,882
Segment sales revenue	103,131			28,713			(14,444		)	117,400
Other revenue	302			5,720			(3,879		)	2,143
Operating revenue	103,433			34,433			(18,323		)	119,543
Loss on sale of assets	—			(106		)	—			(106		)
Loss on derivatives	(379		)	—			—			(379		)
Total revenue	103,054			34,327			(18,323		)	119,058
Operating expenses
Lease operating	18,071			—			(3,879		)	14,192
Transportation, processing and marketing	17,561			3,062			(14,444		)	6,179
Midstream operating	—			6,621			—			6,621
Cost of sales for purchased gathered production	—			7,656			—			7,656
Production taxes	4,673			—			—			4,673
Workovers	757			26			—			783
Exploration	40,847			—			—			40,847
Depreciation, depletion and amortization	33,407			3,592			—			36,999
Impairment of assets	387,721			303,402			—			691,123
General and administrative	14,852			8,075			5,065			27,992
Total operating expenses	517,889			332,434			(13,258		)	837,065
Operating income	(414,835		)	(298,107		)	(5,065		)	(718,007		)
Other income (expense)
Interest expense	(12,233		)	(2,912		)	—			(15,145		)
Interest income	45			6			18			69
Equity in earnings of unconsolidated subsidiaries	—			(29		)	—			(29		)
Reorganization items, net	22,905			—			(438		)	22,467
Total other income (expense)	10,717			(2,935		)	(420		)	7,362
Income (loss) from continuing operations before income taxes	(404,118		)	(301,042		)	(5,485		)	(710,645		)
Interest expense	12,233			2,912			—			15,145
Depreciation, depletion and amortization	33,407			3,592			—			36,999
Loss on unrealized hedges	7,112			—			—			7,112
Impairment of assets	387,721			303,402			—			691,123
Equity-based compensation	1,396			110			—			1,506
Exploration	40,847			—			—			40,847
Severance costs	418			178			—			596
Strategic costs	3,647			1,397			3,397			8,441
Provision for uncollectible related party receivable	—			2,310			—			2,310
Reorganization items, net	(22,905		)	—			438			(22,467		)
Adjusted EBITDAX	$	59,758		$	12,859		$	(1,650	)	$	70,967
Capital expenditures	$	63,571		$	4,381		$	—		$	67,952

29

	Three Months Ended September 30, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	107,253		$	—		$	—		$	107,253
Natural gas	11,959			—			—			11,959
Natural gas liquids	13,880			—			—			13,880
Sales of gathered production	—			27,405			(18,276		)	9,129
Midstream revenue	—			20,775			(12,973		)	7,802
Segment sales revenue	133,092			48,180			(31,249		)	150,023
Other revenue	1,011			—			—			1,011
Operating revenue	134,103			48,180			(31,249		)	151,034
Loss on sale of assets	(18		)	—			—			(18		)
Loss on derivatives	(11,212		)	—			—			(11,212		)
Total revenue	122,873			48,180			(31,249		)	139,804
Operating expenses
Lease operating	16,351			—			—			16,351
Transportation, processing and marketing	15,820			2,334			(12,973		)	5,181
Midstream operating	—			4,507			—			4,507
Cost of sales for purchased gathered production	—			27,737			(18,276		)	9,461
Production taxes	6,311			—			—			6,311
Workovers	1,065			—			—			1,065
Exploration	1,029			—			—			1,029
Depreciation, depletion and amortization	45,849			7,254			—			53,103
Impairment of assets	—			—			—			—
General and administrative	7,918			3,423			561			11,902
Total operating expenses	94,343			45,255			(30,688		)	108,910
Operating income	28,530			2,925			(561		)	30,894
Other income (expense)
Interest expense	(11,008		)	(1,339		)	—			(12,347		)
Interest income	322			3			32			357
Total other income (expense)	(10,686		)	(1,336		)	32			(11,990		)
Income (loss) from continuing operations before income taxes	17,844			1,589			(529		)	18,904
Interest expense	11,008			1,339			—			12,347
Depreciation, depletion and amortization	45,849			7,254			—			53,103
Gain on unrealized hedges	(2,655		)	—			—			(2,655		)
Equity-based compensation	326			278			—			604
Exploration	1,029			—			—			1,029
Adjusted EBITDAX	$	73,401		$	10,460		$	(529	)	$	83,332
Capital expenditures	$	169,967		$	13,047		$	—		$	183,014

30

	Nine Months Ended September 30, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	261,041		$	—		$	—		$	261,041
Natural gas	41,622			—			—			41,622
Natural gas liquids	29,800			—			—			29,800
Sales of gathered production	—			28,386			—			28,386
Midstream revenue	—			64,814			(45,228		)	19,586
Segment sales revenue	332,463			93,200			(45,228		)	380,435
Other revenue	1,200			20,094			(13,052		)	8,242
Operating revenue	333,663			113,294			(58,280		)	388,677
Gain (loss) on sale of assets	1,483			(106		)	—			1,377
Loss on derivatives	(11,744		)	—			—			(11,744		)
Total revenue	323,402			113,188			(58,280		)	378,310
Operating expenses
Lease operating	62,302			—			(13,052		)	49,250
Transportation, processing and marketing	54,936			7,911			(45,228		)	17,619
Midstream operating	—			19,292			—			19,292
Cost of sales for purchased gathered production	—			26,071			—			26,071
Production taxes	15,273			—			—			15,273
Workovers	1,366			537			—			1,903
Exploration	46,190			—			—			46,190
Depreciation, depletion and amortization	102,586			10,321			—			112,907
Impairment of assets	394,221			303,402			—			697,623
General and administrative	51,522			21,462			11,698			84,682
Total operating expenses	728,396			388,996			(46,582		)	1,070,810
Operating income	(404,994		)	(275,808		)	(11,698		)	(692,500		)
Other income (expense)
Interest expense	(39,134		)	(8,226		)	—			(47,360		)
Interest income	126			16			57			199
Equity in earnings of unconsolidated subsidiaries	—			713			—			713
Reorganization items, net	22,905			—			(438		)	22,467
Total other income (expense)	(16,103		)	(7,497		)	(381		)	(23,981		)
Income (loss) from continuing operations before income taxes	(421,097		)	(283,305		)	(12,079		)	(716,481		)
Interest expense	39,134			8,226			—			47,360
Depreciation, depletion and amortization	102,586			10,321			—			112,907
Loss on unrealized hedges	19,386			—			—			19,386
Impairment of assets	394,221			303,402			—			697,623
Equity-based compensation	4,453			572			—			5,025
Exploration	46,190			—			—			46,190
Severance costs	5,002			2,162			—			7,164
Strategic costs	6,489			1,397			3,397			11,283
Provision for uncollectible related party receivable	—			2,310			—			2,310
Reorganization items, net	(22,905		)	—			438			(22,467		)
Adjusted EBITDAX	$	173,459		$	45,085		$	(8,244	)	$	210,300
Equity method investment at period end	$	—		$	1,813		$	—		$	1,813
Capital expenditures	243,709			72,185			—			315,894
Total assets at period end	552,744			156,225			(11,902		)	697,067

31

	February 9, 2018 Through September 30, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	222,822		$	—		$	—		$	222,822
Natural gas	25,149			—			—			25,149
Natural gas liquids	28,835			—			—			28,835
Sales of gathered production	—			59,039			(37,113		)	21,926
Midstream revenue	—			44,446			(26,567		)	17,879
Segment sales revenue	276,806			103,485			(63,680		)	316,611
Other revenue	3,795			—			—			3,795
Operating revenue	280,601			103,485			(63,680		)	320,406
Gain on sale of assets	5,058			—			—			5,058
Loss on derivatives	(62,442		)	—			—			(62,442		)
Total revenue	223,217			103,485			(63,680		)	263,022
Operating expenses
Lease operating	37,347			—			—			37,347
Transportation, processing and marketing	32,608			7,895			(26,567		)	13,936
Midstream operating	—			8,407			—			8,407
Cost of sales for purchased gathered production	—			59,285			(37,113		)	22,172
Production taxes	10,332			—			—			10,332
Workovers	2,643			—			—			2,643
Exploration	10,697			—			—			10,697
Depreciation, depletion and amortization	83,557			19,159			—			102,716
Impairment of assets	—			—			—			—
General and administrative	60,383			9,736			1,991			72,110
Total operating expenses	237,567			104,482			(61,689		)	280,360
Operating income	(14,350		)	(997		)	(1,991		)	(17,338		)
Other income (expense)
Interest expense	(26,565		)	(3,005		)	—			(29,570		)
Interest income	1,688			3			36			1,727
Total other income (expense)	(24,877		)	(3,002		)	36			(27,843		)
Income (loss) from continuing operations before income taxes	(39,227		)	(3,999		)	(1,955		)	(45,181		)
Interest expense	26,565			3,005			—			29,570
Depreciation, depletion and amortization	83,557			19,159			—			102,716
Loss on unrealized hedges	30,241			—			—			30,241
Equity-based compensation	6,714			784			835			8,333
Exploration	10,697			—			—			10,697
Business Combination	23,717			—			—			23,717
Adjusted EBITDAX	$	142,264		$	18,949		$	(1,120	)	$	160,093
Capital expenditures	$	489,009		$	34,636		$	—		$	523,645
Total assets at period end	2,957,284			1,447,913			7,862			4,413,059

32

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 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. 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 vital 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 September 30, 2019, we have a highly contiguous position of approximately 128,000 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 operated 2 rigs after restarting the program, however, as a result of our 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 to meet our financial obligations. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings.

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 September 30, 2019, in comparison to the results for the three months ended September 30, 2018, and the results for the nine months ended September 30, 2019, in comparison to (i) the results of the Upstream and Midstream segments for the period February 9, 2018 through September 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.

33

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 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

On September 11, 2019, the Debtors filed voluntary Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code. 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, (together the “non-Debtors”) are not in bankruptcy or otherwise 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 have been authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The current cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral until November 21, 2019 on the terms and conditions agreed by the AMH Debtors and their creditors (including the lenders under the Alta Mesa RBL) as set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain other milestones related to sale of the Debtor assets. The continued access to the cash collateral will also be dependent

34

upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.

The Debtors are in a marketing process to sell their assets along with KFM’s midstream assets. On October 11, 2019, the Bankruptcy Court entered an order approving, among other things, proposed bidding procedures and the dates for an auction, a hearing to approve the sale or sales of assets, and related dates and deadlines. The auction is scheduled to occur on January 8, 2020 and the sale hearing is scheduled to occur on January 10, 2020. Both of the scheduled dates are subject to postponement.

Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that (i) the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions and non-Debtors KFM and its subsidiaries can be rejected by the Debtors, (ii) certain amendments to the crude oil and gas gathering agreements were constructive and actual fraudulent transfers, (iii) the crude oil and gas gathering agreements are subject to rescission as the products of breaches of fiduciary duty, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement is therefore terminated. On October 25, 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFM and Oklahoma Produced Water Solutions, LLC as Defendants. On November 4, 2019, the plaintiff AMH Debtors provided notice of alleged events of default under the crude oil and gas gathering agreements and reserved their rights and remedies, including termination of those agreements. The plaintiff AMH Debtors have also submitted a motion to file a second amended complaint to include these events of default allegations. The litigation is set for trial on December 9, 2019.

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. In September 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. The Administrative Agent and the lenders have reserved their right to pursue any remedies available to them, including charging the default rate of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral. Although the Administrative Agent and the lenders have not taken any such actions, KFM will not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact AMR’s and KFM’s ability to meet all financial obligations as they come due and KFM’s ability to make distributions to AMR that otherwise may have been permitted. As a result of Alta Mesa’s bankruptcy and the limitations imposed under a Bankruptcy Court approved cash collateral agreement and alleged defaults under the KFM Credit Facility, AMR’s only remaining source of liquidity is through non-debtor subsidiary SRII Opco. At October 31, 2019, SRII Opco had cash on hand of $5.5 million. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.

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 was to produce, over time, relative revenue stability. However, both settlements and fair value changes in our derivatives have historically significantly impacted our short-term results of operations. During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts for net proceeds of approximately $4.0 million. Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL.

Impairments

During the three months ended September 30, 2019, we determined that the reduction in our borrowing base under the Alta Mesa RBL and our filing for bankruptcy protection were indicators of potential impairment of our tangible long-lived assets due to the negative impact they would have on our future development plans, revenue and cash flows. Accordingly, we compared our estimated future undiscounted cash flows to the carrying value of our oil and gas properties and our Midstream property and equipment, which indicated that they were not fully recoverable. Based on a determination of the fair value of those assets utilizing estimates of discounted cash flows and market values, we recognized impairments of (i) $387.7 million for our proved oil and gas properties and (ii) $303.4 million for our Midstream property and equipment.

35

We also impaired certain operating lease right-of-use assets during the nine months ended September 30, 2019 totaling $6.5 million based on our expected inability to recover the full cash cost of our lease obligations through subleasing certain unused office space in three buildings located in Houston, Texas and Oklahoma City, Oklahoma.

Late in the fourth quarter of 2018, the combination of depressed prevailing oil and 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 our revenue growth and our operating cash flow.

36

RESULTS OF OPERATIONS

For the Three Months Ended September 30, 2019 (“Third Quarter 2019”) Compared to the Three Months Ended September 30, 2018 (“Third 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)	Third Quarter 2019			Third Quarter 2018
Net production:
Oil (Mbbls)	1,516			1,539
Natural gas (MMcf)	6,416			5,116
NGLs (Mbbls)	642			685
Total (MBoe)	3,227			3,077
Average net daily production volumes:
Oil (Mbblsd)	16.5			16.7
Natural gas (MMcfd)	69.7			55.6
NGLs (Mbblsd)	7.0			7.4
Total (MBoed)	35.1			33.4
Average sales prices:
Oil (per bbl)	$	55.40		$	69.67
Effect of realized derivatives settlements (per bbl)	3.25			(8.88		)
Oil, after hedging (per bbl)	$	58.65		$	60.79
Percentage of unhedged realized oil price to NYMEX oil price	98		%	100		%
Natural gas (per Mcf)	$	1.68		$	2.34
Effect of realized derivatives settlements (per Mcf)	0.28			(0.04		)
Natural gas, after hedging (per Mcf)	$	1.96		$	2.30
NGLs (per bbl)	$	12.98		$	20.26
Effect of realized derivatives settlements (per bbl)	—			—
NGLs, after hedging (per bbl)	$	12.98		$	20.26
Revenue
Oil sales	$	84,010		$	107,253
Natural gas sales	10,788			11,959
NGL sales	8,333			13,880
Total sales revenue	$	103,131		$	133,092
Loss on sale of assets	$	—		$	(18	)

Oil sales for the third quarter 2019 decreased due primarily to lower average sales prices before hedging as well as decreased oil production. Natural gas sales for the third quarter 2019 decreased due primarily to lower average sales prices before hedging, partially offset by increased gas production. NGL sales for the third quarter 2019 decreased due to both lower average sales prices before hedging and decreased volumes.

37

Derivatives

(in thousands)	Third Quarter 2019			Third Quarter 2018
Gain (loss) on derivatives:
Oil	$	4,922		$	(13,663	)
Natural gas	1,811			(204		)
Total realized gains (losses)	6,733			(13,867		)
Unrealized gains (losses)	(7,112		)	2,655
Total gain (loss) on derivatives	$	(379	)	$	(11,212	)

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. The decrease in derivative losses results from more price stability during 2019.

During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts for net proceeds of approximately $4.0 million. Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL.

Operating Expenses

(in thousands, except per unit data)	Third Quarter 2019		Third Quarter 2018
Operating expenses:
Lease operating	$	18,071	$	16,351
Transportation and marketing	17,561		15,820
Production taxes	4,673		6,311
Workovers	757		1,065
Exploration	40,847		1,029
Depreciation, depletion and amortization	33,407		45,849
Impairment of assets	387,721		—
General and administrative	14,852		7,918
Total operating expense	$	517,889	$	94,343
Operating expenses per BOE:
Lease operating	$	5.60	$	5.31
Transportation and marketing	5.44		5.14
Production taxes	1.45		2.05
Workovers	0.23		0.35
Depreciation, depletion and amortization	10.35		14.90

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

Transportation and marketing expense for the third quarter 2019 increased due to higher gas volumes. The amount for the third quarter 2019 also reflects a more significant expense due to an increase in committed capacity.

Production taxes for the third quarter 2019 decreased due to the decrease in gross production revenue from the third quarter 2018.

38

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

(in thousands)	Third Quarter 2019		Third Quarter 2018
Exploration expense:
Geological and geophysical costs	$	192	$	947
Other exploration expense, including expired leases	40,655		149
ARO settlements in excess of recorded liabilities	—		(67		)
Total exploration expense	$	40,847	$	1,029

Exploration expense during the third quarter 2019 increased largely due to an increase in expired and expiring leases, primarily for those in Major County, Oklahoma.

Depreciation, depletion and amortization was lower on a per BOE basis during the third 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.

Impairment of assets reflects the recognition of $387.7 million for impairment of proved properties during the third quarter 2019. No similar impairments were recognized during the third quarter 2018.

(in thousands)	Third Quarter 2019		Third Quarter 2018
General and administrative expense:
Employee-related costs	$	3,695	$	3,577
Equity-based compensation	1,396		326
Professional fees	3,526		2,215
Strategic costs	3,647		—
Severance costs	418		—
Information technology	1,151		967
Operating leases	793		815
Provision for uncollectible receivables	—		2
Other	226		16
Total general and administrative expense	$	14,852	$	7,918

General and administrative expenses during the third quarter 2019 increased due mainly to costs for legal and financial strategic advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties. As of the Petition Date, all professional fees incurred from that date forward and directly related to the bankruptcy, are reported as Reorganization items, net.

39

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

(in thousands)	Third Quarter 2019			Third Quarter 2018
Income (loss) from continuing operations before income taxes	$	(404,118	)	$	17,844
Interest expense	12,233			11,008
Depreciation, depletion and amortization	33,407			45,849
Exploration	40,847			1,029
Loss (gain) on unrealized hedges	7,112			(2,655		)
Impairment of assets	387,721			—
Equity-based compensation	1,396			326
Severance costs	418			—
Strategic costs	3,647			—
Reorganization items, net	(22,905		)	—
Adjusted EBITDAX	$	59,758		$	73,401

Other (Income) Expense

(in thousands)	Third Quarter 2019			Third Quarter 2018
Alta Mesa RBL	$	5,234		$	457
2024 Notes	7,765			9,844
Bond premium amortization	(970		)	(1,230		)
Deferred financing cost amortization	56			70
Other	148			1,867
Total interest expense	12,233			11,008
Interest income	(45		)	(322		)
Reorganization items, net	(22,905		)	—
Total other (income) expense, net	$	(10,717	)	$	10,686

Interest expense for the third quarter 2019 increased due primarily to increased levels of borrowings under the Alta Mesa RBL and higher recent interest rates. No interest expense on the 2024 Notes has been recognized since our filing for bankruptcy due to our expectations that such post-bankruptcy interest will not be paid. In addition, the remaining bond premium associated with the 2024 Notes and deferred financing costs associated with the Alta Mesa RBL were written off. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.

Reorganization items, net

(in thousands)	Three Months Ended September 30, 2019
Unamortized deferred financing fees and premiums	$	(24,748	)
Terminated contracts	(394		)
Legal and other professional advisory fees	2,237
Reorganization items, net	$	(22,905	)

40

Midstream Segment Results

Revenue

(in thousands)	Third Quarter 2019		Third Quarter 2018
Produced water disposal fees	$	5,720	$	—
Midstream revenue	20,326		20,775
Sales of gathered production	8,387		27,405
Total Midstream revenue	$	34,433	$	48,180
KFM produced water gathering volumes (Mbbls)	5,799		—
KFM crude oil volumes (Mbbls)	12		760
KFM gas volumes (MMcf)	12,309		10,710

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

Sales of gathered production decreased due to a substantial decrease in the sales price of NGLs.

Operating Expenses

(in thousands)	Third Quarter 2019		Third Quarter 2018
Midstream operating	$	6,621	$	4,507
Cost of sales for purchased gathered production	7,656		27,737
Transportation and processing	3,062		2,334
Workovers	26		—
Depreciation and amortization	3,592		7,254
Impairment of assets	303,402		—
General and administrative	8,075		3,423
Total operating expenses	$	332,434	$	45,255

Midstream operating expense increased due to additional operating expenses for the produced water disposal assets acquired from Alta Mesa during the fourth quarter of 2018.

Cost of sales for purchased gathered production decreased due to the sales decline to third parties for sales of gathered production.

Transportation and processing expense increased as a result of an increase in gas throughput volumes.

Depreciation and amortization decreased due to $5.2 million of amortization expense related to intangible customer relationship assets that were fully impaired at December 31, 2018.

Impairment of assets totaling $303.4 million was recognized during the third quarter 2019 to adjust the segment’s property and equipment to fair value as the future expected cash flows were not sufficient to provide for recovery of the carrying value of the assets. No similar impairment was recognized during the third quarter 2018.

41

(in thousands)	Third Quarter 2019		Third Quarter 2018
General and administrative expenses:
Employee-related costs	$	3,155	$	1,669
Equity-based compensation	110		278
Professional fees	409		431
Strategic costs	1,397		—
Severance costs	178		—
Information technology	119		108
Operating leases	131		110
Provision for uncollectible receivables	2,310		—
Other	266		827
Total general and administrative expense	$	8,075	$	3,423

General and administrative expense increased during the third quarter 2019 as a result of increased employee-related costs allocable to KFM, and a provision to fully reserve a receivable from KFM’s former owner due to our assessment regarding collectibility.

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

(in thousands)	Third Quarter 2019			Third Quarter 2018
Income (loss) from continuing operations before income taxes	$	(301,042	)	$	1,589
Interest expense	2,912			1,339
Depreciation and amortization	3,592			7,254
Impairment of assets	303,402			—
Equity-based compensation	110			278
Severance costs	178			—
Strategic costs	1,397			—
Provision for uncollectible related party receivable	2,310			—
Adjusted Midstream EBITDA	$	12,859		$	10,460

Other (Income) Expense

(in thousands)	Third Quarter 2019			Third Quarter 2018
KFM Credit Facility	$	2,723		$	998
Deferred financing cost amortization	117			117
Other	72			224
Total interest expense	2,912			1,339
Interest income	(6		)	(3		)
Equity in earnings of unconsolidated subsidiaries	29			—
Total other (income) expense, net	$	2,935		$	1,336

Interest expense for the third quarter 2019 increased primarily due to increased levels of borrowings under the KFM 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.

42

For the Nine Months Ended September 30, 2019 (“2019 Period”) Compared to the Periods February 9, 2018 Through September 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 Successor Period from February 9, 2018 through September 30, 2018 and Predecessor Period from January 1, 2018 through February 8, 2018 as the “2018 Period”.

Upstream Segment Results

Revenue

	Successor						Predecessor
(in thousands, except per unit data)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Net production:
Oil (Mbbl)	4,680			3,313			494
Natural gas (MMcf)	18,530			11,308			1,609
NGLs (Mbbl)	2,256			1,462			151
Total (MBoe)	10,024			6,660			914
Average net daily production volumes:
Oil (Mbbld)	17.1			14.2			12.7
Natural gas (MMcfd)	67.9			48.3			41.2
NGLs (Mbbld)	8.3			6.2			3.9
Total (MBoed)	36.7			28.5			23.4
Average sales prices:
Oil (per bbl)	$	55.77		$	67.26		$	62.68
Effect of realized derivatives settlements (per bbl)	1.47			(10.02		)	(6.44		)
Oil, after hedging (per bbl)	$	57.24		$	57.24		$	56.24
Percentage of unhedged realized oil price to NYMEX oil price	98		%	100		%	99		%
Natural gas (per Mcf)	$	2.25		$	2.22		$	2.66
Effect of realized derivatives settlements (per Mcf)	0.04			0.03			0.94
Natural gas, after hedging (per Mcf)	$	2.29		$	2.25		$	3.60
NGLs (per bbl)	$	13.21		$	19.72		$	26.41
Effect of realized derivatives settlements (per bbl)	—			—			—
NGLs, after hedging (per bbl)	$	13.21		$	19.72		$	26.41
Revenue
Oil sales	$	261,041		$	222,822		$	30,972
Natural gas sales	41,622			25,149			4,276
NGL sales	29,800			28,835			4,000
Total sales	$	332,463		$	276,806		$	39,248
Gain on sale of assets	$	1,483		$	5,058		$	840

43

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 primarily due to an increase in production as a result of the extensive development program conducted 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)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives:
Oil	$	6,858		$	(32,555	)	$	(3,819	)
Natural gas	784			354			1,523
Total realized gains (losses)	7,642			(32,201		)	(2,296		)
Unrealized gains (losses)	(19,386		)	(30,241		)	8,959
Total gain (loss) on derivatives	$	(11,744	)	$	(62,442	)	$	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 nine month period.

The reduced derivative losses in the 2019 Period are due to greater price stability in 2019, whereas in the 2018 Period commodity prices improved over that time period.

During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts for net proceeds of approximately $4.0 million. Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL.

44

Operating Expenses

	Successor				Predecessor
(in thousands, except per unit data)	Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018		January 1, 2018 Through February 8, 2018
Operating expenses:
Lease operating	$	62,302	$	37,347	$	4,408
Transportation and marketing	54,936		32,608		3,725
Production taxes	15,273		10,332		953
Workovers	1,366		2,643		423
Exploration	46,190		10,697		7,003
Depreciation, depletion and amortization	102,586		83,557		11,670
Impairment of assets	394,221		—		—
General and administrative	51,522		60,383		21,234
Total operating expense	$	728,396	$	237,567	$	49,416
Operating expenses per BOE:
Lease operating	$	6.22	$	5.61	$	4.82
Transportation and marketing	5.48		4.90		4.08
Production taxes	1.52		1.55		1.04
Workovers	0.14		0.40		0.46
Depreciation, depletion and amortization	10.23		12.55		12.77

Lease operating expense for the 2019 Period increased due to higher gas production and the impact of additional costs after 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 gross production 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 less workover projects being undertaken to reduce costs.

	Successor				Predecessor
(in thousands)	Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018		January 1, 2018 Through February 8, 2018
Exploration expense:
Geological and geophysical costs	$	870	$	2,537	$	2,440
Other exploration expense, including expired leases	45,259		7,561		4,504
ARO settlements in excess of recorded liabilities	61		599		59
Total exploration expense	$	46,190	$	10,697	$	7,003

45

Exploration expense for the 2019 Period increased largely due to an increase in expired and expiring leases, primarily for those in Major County, Oklahoma. Geological and geophysical costs are down due to headcount reductions.

Impairment of assets reflects the recognition of $394.2 million for impairment of proved properties and right-of-use assets during the 2019 Period. No similar impairments were recognized during the 2018 Period.

	Successor				Predecessor
(in thousands)	Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018		January 1, 2018 Through February 8, 2018
General and administrative expense:
Employee-related costs	$	18,652	$	16,223	$	1,032
Equity-based compensation	4,453		6,714		—
Professional fees	8,479		7,749		1,019
Strategic costs	6,489		—		—
Business Combination	—		23,717		17,040
Severance costs	5,002		—		—
Information technology	3,131		3,616		—
Operating leases	3,110		2,301		208
Provision for uncollectible receivables	1,139		—		—
Other	1,067		63		1,935
Total general and administrative expense	$	51,522	$	60,383	$	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, as well as severance costs associated with a reduction in force. As of the Petition Date, all professional fees incurred from that date forward and directly related to the bankruptcy, are reported as Reorganization items, net.

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

46

	Successor						Predecessor
(in thousands)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Loss from continuing operations before income taxes	$	(421,097	)	$	(39,227	)	$	(7,116	)
Interest expense	39,134			26,565			5,511
Depreciation, depletion and amortization	102,586			83,557			11,670
Exploration	46,190			10,697			7,003
Loss (gain) on unrealized hedges	19,386			30,241			(8,959		)
Impairment of assets	394,221			—			—
Equity-based compensation	4,453			6,714			—
Severance costs	5,002			—			—
Strategic costs	6,489			—			—
Business Combination	—			23,717			17,040
Reorganization items, net	(22,905		)	—			—
Adjusted EBITDAX	$	173,459		$	142,264		$	25,149

Other (Income) Expense

	Successor						Predecessor
(in thousands)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Alta Mesa RBL	$	14,017		$	709		$	815
2024 Notes	27,453			26,250			3,281
Bond premium amortization	(3,432		)	(3,281		)	—
Deferred financing cost amortization	195			150			171
Other	901			2,737			1,244
Total interest expense	39,134			26,565			5,511
Interest income	(126		)	(1,688		)	(172		)
Reorganization items, net	(22,905		)	—			—
Total other (income) expense, net	$	16,103		$	24,877		$	5,339

Interest expense for the 2019 Period increased primarily due to increased levels of borrowing under the Alta Mesa RBL. No interest expense on the 2024 Notes has been recognized since our filing for bankruptcy due to our expectations that such post-bankruptcy interest will not be paid. In addition, the remaining bond premium associated with the 2024 Notes and deferred financing costs associated with the Alta Mesa RBL were written off. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.

47

Reorganization items, net

(in thousands)	Nine Months Ended September 30, 2019
Unamortized deferred financing fees and premiums	$	(24,748	)
Terminated contracts	(394		)
Legal and other professional advisory fees	2,237
Reorganization items, net	$	(22,905	)

Midstream Segment Results

Revenue

(in thousands)	Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018
Produced water disposal fees	$	20,094	$	—
Midstream revenue	64,814		44,446
Sales of gathered production	28,386		59,039
Total Midstream revenue	$	113,294	$	103,485
KFM produced water gathering volumes (Mbbls)	20,421		—
KFM crude oil volumes (Mbbls)	1,049		1,193
KFM gas volumes (MMcf)	37,409		23,654

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

Midstream revenue increased due to increased oil and gas gathered volumes and the impact of a second cryogenic processing train being commissioned in mid-2018.

Sales of gathered production decreased due to a substantial decrease in the sales price of NGLs.

Operating Expenses

(in thousands)	Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018
Midstream operating	$	19,292	$	8,407
Cost of sales for purchased gathered production	26,071		59,285
Transportation and processing	7,911		7,895
Workovers	537		—
Depreciation and amortization	10,321		19,159
Impairment of assets	303,402		—
General and administrative	21,462		9,736
Total operating expenses	$	388,996	$	104,482

48

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 for purchased gathered production decreased in the 2019 Period due to the sales decline to third parties for sales of gathered production.

Depreciation and amortization during the 2018 Period included $13.9 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 million in depreciation of tangible assets during the 2019 Period due to capital spending since September 30, 2018, including the purchase of the produced waster disposal assets from Alta Mesa in the fourth quarter of 2018.

Impairment of assets totaling $303.4 million was recognized during the 2019 Period to adjust the segment’s property and equipment to fair value as the future expected cash flows were not sufficient to provide for recovery of the carrying value of the assets. No similar impairment was recognized during the 2018 Period.

(in thousands)	Nine Months Ended September 30, 2019		February 9, 2018 Through September 30, 2018
General and administrative expenses:
Employee-related costs	$	10,878	$	5,682
Equity-based compensation	572		784
Professional fees	2,254		963
Strategic costs	1,397		10
Severance costs	2,162		—
Information technology	245		112
Operating leases	348		149
Provision for uncollectible receivable	2,310		—
Other	1,296		2,036
Total general and administrative expense	$	21,462	$	9,736

General and administrative expense increased during the 2019 Period as a result of increased employee-related costs allocable to KFM and a provision to fully reserve a receivable from KFM’s former owner due to our assessment regarding collectibility. Moreover, 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 our income (loss) from continuing operations before income taxes to Adjusted Midstream EBITDA:

49

(in thousands)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018
Loss from continuing operations before income taxes	$	(283,305	)	$	(3,999	)
Interest expense	8,226			3,005
Depreciation and amortization	10,321			19,159
Impairment of assets	303,402			—
Equity-based compensation	572			784
Severance costs	2,162			—
Strategic costs	1,397			—
Provision for uncollectible related party receivable	2,310			—
Adjusted Midstream EBITDA	$	45,085		$	18,949

Other (Income) Expense

(in thousands)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018
KFM Credit Facility	$	7,534		$	1,320
Predecessor revolving credit facility	—			980
Deferred financing cost amortization	346			189
Other	346			516
Total interest expense	8,226			3,005
Interest income	(16		)	(3		)
Equity in earnings of unconsolidated subsidiaries	(713		)	—
Total other (income) expense, net	$	7,497		$	3,002

Interest expense for the 2019 Period increased primarily due to increased levels of borrowings particularly under the KFM 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.

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 derivatives. During 2019, our main sources of liquidity and capital resources came from operating cash flow and borrowings under the Alta Mesa RBL and KFM Credit Facility.

In April 2019, our borrowing base under the Alta Mesa RBL was reduced from $400.0 million to $370.0 million leaving 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. As indicated above, AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments.

50

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. In September 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. The Administrative Agent and the lenders have reserved their right to pursue any remedies available to them, including charging the default rate of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral. Although the Administrative Agent and the lenders have not taken any such actions, KFM will not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact AMR’s and KFM’s ability to meet all financial obligations as they come due and KFM’s ability to make distributions to AMR that otherwise may have been permitted. As a result of Alta Mesa’s bankruptcy and the limitations imposed under a Bankruptcy Court approved cash collateral agreement and alleged defaults under the KFM Credit Facility, AMR’s only remaining source of liquidity is through non-debtor subsidiary SRII Opco. At October 31, 2019, SRII Opco had cash on hand of $5.5 million. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings.

During September 2019, 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. Under the terms and conditions of the cash collateral order approved by the Bankruptcy Court and corresponding budget, we are not able to operate any drilling rigs 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 to meet our financial obligations.

During November 2019 we reached an agreement with our co-investor in Cimarron Express Pipeline, LLC (“CEPL”) to begin the process of redeeming their 50% ownership.  As a result, we expect to begin consolidating Cimarron following that redemption, which will provide additional cash resources of approximately $7 million and additional rights-of-way.   The value of the net assets to be consolidated beginning in November 2019 approximates the value of the equity method investment as of September 30, 2019. Once CEPL is consolidated, the cash it holds will generally be available to KFM for its use to meet operating costs, but due to the alleged default under the KFM Credit Facility, it cannot be distributed to AMR for its expenses or other uses.

At December 31, 2018, Alta Mesa had an $18.3 million letter of credit issued to provide financial assurance for a multi-year obligation. During 2019, this letter of credit was reduced by $2.4 million in the ordinary course. In November 2019, the transportation company demanded full payment of $15.9 million for non-payment of $0.5 million in prepetition claims. This amount was paid by the administrative agent of the Alta Mesa RBL, but we believe the claims arising under the transportation contract were stayed by Alta Mesa’s bankruptcy filing. A demand letter has been sent to the transportation company to return the excess payment above the prepetition claims. It is unclear if or when this matter will be resolved.

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.

51

Cash Flow Analysis

	Successor						Predecessor
(in thousands)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Cash from operating activities	$	129,452		$	2,506		$	26,336
Cash from investing activities	(315,894		)	(282,048		)	(37,913		)
Cash from financing activities	228,863			312,211			16,932
Net increase in cash, cash equivalents and restricted cash	$	42,421		$	32,669		$	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 $134.0 million compared to $101.6 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 $4.5 million of cash was used to increase working capital during the 2019 Period. During the 2018 Period, cash totaling $72.8 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)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Cash provided by (used for)
Capital expenditures	$	(315,894	)	$	(523,645	)	$	(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	—			(9,326		)	—
Cash from investing activities	$	(315,894	)	$	(282,048	)	$	(37,913	)

During the 2019 Period, capital expenditures included $147.8 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 but have averaged much closer to 2 rigs for the 2019 Period. As a result of our 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.

52

Cash flow from financing activities

	Successor						Predecessor
(in thousands)	Nine Months Ended September 30, 2019			February 9, 2018 Through September 30, 2018			January 1, 2018 Through February 8, 2018
Cash provided by (used for)
Proceeds from long-term debt borrowings	$	238,500		$	162,500		$	60,000
Repayments of long-term debt	(9,496		)	(193,565		)	(43,000		)
Payment of taxes withheld on equity-based compensation awards	(141		)	—			—
Deferred financing costs paid	—			(3,716		)	—
Purchase and retirement of Class A common shares	—			(14,750		)	—
Proceeds from issuance of Class A shares	—			400,000			—
Repayment of sponsor note	—			(2,000		)	—
Repayment of deferred underwriting compensation	—			(36,225		)	—
Other	—			(33		)	(68)
Cash from financing activities	$	228,863		$	312,211		$	16,932

During the 2019 Period, our outstanding balances owed under the Alta Mesa RBL and KFM Credit Facility increased by $229.0 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 in the future to manage or reduce market risk, but we do not plan to enter into derivatives for speculative purposes. We have not previously designated 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 historically used derivatives to reduce our exposure to the risks of price changes. During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts for net proceeds of approximately $4.0 million. Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL.

Counterparty and Customer Credit Risk 

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 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 nine months ended September 30, 2019, ARM marketed $117.0 million, or 30.1% 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 September 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

53

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 third quarter 2019, we satisfactorily completed testing of changes to access controls for payroll, production accounting and reserves systems to remediate material weaknesses identified during 2018 in those areas. Further remediation efforts are continuing to resolve other material weaknesses identified during the prior year and we anticipate additional testing of controls to occur during the fourth quarter of 2019.

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.

Litigation

As previously disclosed in our 2018 10-K, on March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to KFM in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants.  We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves.

The Mustang litigation was automatically stayed on the commencement of the Chapter 11 proceedings. On October 28, 2019, Mustang filed a motion asking the Bankruptcy Court to lift the automatic stay to allow the litigation to proceed in the District Court of Kingfisher County, Oklahoma.

54

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.

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 current cash collateral order expires November 21, 2019 and is subject to renewal for succeeding 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

55

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 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 (i) the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions and non-Debtors KFM and its subsidiaries can be rejected by the Debtors, (ii) certain amendments to the crude oil and gas gathering agreements were constructive and actual fraudulent transfers, (iii) the Defendants breached their respective fiduciary duties owed to the AMH Debtors by entering related-party crude oil and gas gathering agreements, which as a result are subject to rescission, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement is therefore terminated. 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. On October 25, 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFM and Oklahoma Produced Water Solutions, LLC as Defendants. On November 4, 2019, the plaintiff AMH Debtors provided notice of alleged events of default under the crude oil and gas gathering agreements and reserved their rights and remedies, including termination of those agreements. The plaintiff AMH Debtors have also submitted a motion to file a second amended complaint to include these events of default allegations. The litigation is set for trial on December 9, with summary judgment motions, if any, scheduled to be heard on November 22, 2019, and a pending motion to dismiss by Defendants KFM and Oklahoma Produced Water Solutions, LLC scheduled to be heard on November 21, 2019. The outcome of the litigation 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 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

56

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 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.

57

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 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

58

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 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

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.

In addition, 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.

On September 23, 2019, the lenders under the KFM Credit Facility provided notice of an alleged event of default arising as a result of certain liens upon KFM’s assets and reserved their rights and remedies thereunder, including charging the default rate

59

of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

60

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).
10.1	Separation Agreement by and between Alta Mesa Services, LP and Ronald J. Smith (incorporated by reference from Exhibit 10.1 to Alta Mesa Resources’ Current Report on Form 8-K filed with the SEC on July 8, 2019).
10.2	Amended and Restated Consulting Agreement, dated September 10, 2019, by and among Alta Mesa Services, LP, Meridian Energy, LLC, Randy Limbacher, John H. Campbell and Mark P. Castiglione (incorporated by reference from Exhibit 10.1 to Alta Mesa Resources’ Current Report on Form 8-K filed with the SEC on September 12, 2019).
10.3	Form of Bonus Agreement dated September 7, 2019, by and between Alta Mesa Resources, Inc. and Executive (incorporated by reference from Exhibit 10.1 to Alta Mesa Resources’ Current Report on Form 8-K filed with the SEC on September 12, 2019).
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.

61

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)
Dated	November 12, 2019

62