Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

~~_______________________________________~~_____________________________________

FORM 10-Q

~~_______________________________________~~_____________________________________

(Mark One)

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

For the quarterly period ended: ~~September~~March 3031, ~~2018~~2019

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

For the transition period from to ___ 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)

Delaware	81-4433840
(State or other jurisdiction ofincorporation or organization)	(I.R.S. EmployerIdentification 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:

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



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per share	AMR	The NASDAQ Capital Market
Warrants to purchase one share of Class A Common Stock	AMRWW	The NASDAQ Capital Market

Indicate by check mark whether the registrant (1) has ~~submitted~~filed ~~electronically~~all ~~every~~reports ~~Interactive Data File~~ required to be ~~submitted~~filed ~~pursuant~~by toSection 13 ~~Rule~~or ~~405~~15(d) of ~~Regulation~~the ~~S-T~~Securities ~~(§232.405~~Exchange Act of ~~this~~1934 ~~chapter)~~ during the preceding 12 months (or for such shorter period that the registrant was required to ~~submit~~file such ~~files.~~reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x¨ No o x

Indicate by check mark whether the registrant ishas asubmitted ~~large~~electronically ~~accelerated~~every ~~filer,~~Interactive anData ~~accelerated~~File ~~filer,~~required ato ~~non-accelerated~~be ~~filer,~~submitted apursuant ~~smaller~~to ~~reporting~~Rule ~~company~~405 orof anRegulation ~~emerging~~S-T ~~growth company~~(§232.405 ~~See definition~~ of ~~“large~~this ~~accelerated~~chapter) ~~filer”,~~during ~~“accelerated~~the ~~filer”,~~preceding ~~“smaller~~12 ~~reporting~~months ~~company”~~(or ~~and~~for ~~“emerging~~such ~~growth~~shorter ~~company”~~period inthat ~~Rule~~the ~~12b-2~~registrant ofwas ~~the~~required ~~Exchange~~to ~~Act.~~submit ~~(Check~~such ~~one~~files.) Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See 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 ox Accelerated filer o¨ Non-accelerated filer x¨ Smaller reporting company o¨ Emerging growth company x¨

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

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

As of ~~October~~August 31, ~~2018~~2019, there were ~~175~~182,~~957~~755,~~183~~573 shares of Class A Common Stock and ~~204~~ 199,~~921~~987,~~888~~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 2554,~~094,585~~294 nonvested restricted stock awards outstanding as of ~~October~~August 31, ~~2018~~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	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3. Quantitative and Qualitative Disclosures about Market Risk	35
Item 4. Controls and Procedures	36
PART II - OTHER INFORMATION
Item 1. Legal Proceedings	37
Item 1A. Risk Factors	37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3. Defaults Upon Senior Securities	42
Item 4. Mine Safety Disclosures	42
Item 5. Other Information	42
Item 6. Exhibits	43
Signatures	44

Table of Contents

Index to Financial Statements

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 Quarter -	The combined Predecessor Period (January 1, 2018 to February 8, 2018) and the successor period from February 9, 2018 to March 31, 2018.
2019 Quarter -	The period from January 1, 2019 to March 31, 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 -	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 markets our oil and gas production and provides services relating to our derivatives.
Bankruptcy Code -	Chapter 11 of the United States Bankruptcy Code.
Bankruptcy Court -	United States Bankruptcy Court for the Southern District of Texas.
BCE -	BCE-STACK Development LLC, a fund advised by Bayou City Management, LLC.
Business Combination	The acquisition by Alta Mesa Resources, Inc. of controlling interests in Alta Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, and KFM Midstream, LLC.
Debtors -	Alta Mesa Resources, Inc., Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP.
High Mesa -	High Mesa Holdings, LP, a partnership formed in connection with executing the Business Combination.
HMI -	High Mesa, Inc., the predecessor owner of Alta Mesa Holdings, LP.
KFM -	Kingfisher Midstream, LLC. This entity conducts our Midstream activities.
KFM Credit Facility -	Kingfisher Midstream, LLC amended and restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent.
Midstream -	Reportable business segment representing our midstream activities.
Predecessor Period -	The period from January 1, 2018 through February 8, 2018.
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 March 31, 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.

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໿Index to Financial Statements

	Page Number
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.
Glossary of Terms	3
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.
Cautionary Statement Regarding Forward-Looking Statements	4
Boed -	One Boe per day.
PART I — FINANCIAL INFORMATION
Btu or British Thermal Unit -	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Item 1. Financial Statements (unaudited)
Completion -	The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil.
Consolidated Balance Sheets	6
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.
Consolidated Statements of Operations	8
Cryogenic -	The process of using extreme cold to separate NGLs from the natural gas stream.
Consolidated Statements of Cash Flows	9
DD&A -	Depreciation, depletion and amortization.
Consolidated Statements of Changes in Stockholders’ Equity	10
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.
Consolidated Statements of Changes in Partners’ Capital	11
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.
Notes to Consolidated Financial Statements	12
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.
Note 1 — Description of Business	12
Dry hole -	A well found to be incapable of producing hydrocarbons in commercial quantities.
Note 2 — Summary of Significant Accounting Policies	12
Dth -	A dekatherm is a unit of energy used primarily to measure natural gas and is equal to 1,000,000 Btu.
Note 3 — Supplemental Cash Flow Information	22
Dthd -	1,000,000 Btu per day.
Note 4 — Business Combination	22
EBITDA -	Earnings before interest, taxes, depreciation, depletion and amortization.
Note 5 — Property, Plant and Equipment	28
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.
Note 6 — Discontinued Operations (Predecessor)	28
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.
Note 7 — Fair Value Measurements	30
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.
Note 8 — Derivative Financial Instruments	32
Formation -	A layer of rock which has distinct characteristics that differs from adjacent rock.
Note 9 — Intangible Assets	35
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.
Note 10 — Equity Method Investment	36
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.
Note 11 — Asset Retirement Obligations	37
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.
Note 12 — Long-Term Debt, Net	37
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.
Note 13 — Accounts Payable and Accrued Liabilities	41
Note 14 — Commitments and Contingencies	42
Note 15 — Significant Risks and Uncertainties	43
Note 16 — Stockholders’ Equity and Partners’ Capital	44
Note 17 — Equity-based Compensation (Successor)	46
Note 18 — Income Taxes	48
Note 19 — Related Party Transactions	50
Note 20 — Subsidiary Guarantors	52
Note 21 — Business Segment Information	52
Note 22 — Subsequent Events	54
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
Item 3. Quantitative and Qualitative Disclosures about Market Risk	72
Item 4. Controls and Procedures	72
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	73
Item 1A. Risk Factors	73
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	73
Item 5. Other Information	74
Item 6. Exhibits	75
Signatures	76

2ii

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~~Glossary~~Index ofto ~~Terms~~Financial Statements

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



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.
MMBoe -	One million boe.
MMBtud -	One million British thermal units per day.
MMcf -	One million cubic feet of natural gas.
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.
MMBbl -	One million barrels of crude oil, condensate or natural gas liquids.
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.
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.

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

iii

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Index to Financial Statements



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.

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Index to Financial Statements

Cautionary Statement Regarding Forward-Looking Statements

The information in this ~~report~~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 ~~on Form 10-Q~~, regarding our ability to continue as a going concern, strategy, future operations, financial position, estimated ~~revenues~~revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this ~~report~~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” ~~included~~ in ~~our~~this ~~2017~~Quarterly Report and our Annual Report on Form 10-K ~~and~~for ~~Part~~the ~~II,~~year ~~Item~~ended 1ADecember 31, of2018 ~~this~~(“2018 ~~report~~10-K”). These forward-looking statements ~~reflect~~are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about:

• ~~the~~our ~~benefits~~ability ofto ~~the~~continue ~~Business Combination,~~ as ~~defined~~a ingoing ~~Note 4 of the accompanying Notes to Consolidated Financial Statements~~concern;

• the ~~future~~outcome ~~financial~~or ~~performance~~timing of ~~the~~our ~~combined~~emergence ~~company~~from ~~following~~bankruptcy, including limitations placed upon us by the ~~Business~~process ~~Combination~~and our ability to develop, confirm and consummate a plan under Chapter 11 or an alternative restructuring or sale transaction;

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


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


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


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


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


•	our ability to execute our stated business strategy;


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

• our ~~estimated~~ability ~~purchase~~to ~~price~~replace ~~and~~the ~~purchase~~reserves ~~price~~we ~~allocations~~produce through drilling and through acquisitions;


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

• our ~~horizontal~~ drilling, completion and production technology;

• ~~our~~future ~~ability~~oil ~~to replace the reserves we produce through drilling~~ and ~~property~~gas ~~acquisitions~~prices;

• ~~our~~the ~~financial~~supply ~~strategy,~~and ~~liquidity~~demand ~~and~~for ~~capital~~our ~~required~~production ~~for~~and our ~~development~~midstream ~~program~~services;

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

• ~~the~~our ~~supply~~hedging ~~and~~strategy ~~demand for crude oil, natural gas, natural gas liquids,~~ and ~~midstream~~expected ~~services~~results;

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

• our hedging strategy and results;

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


•	competition and government regulation;

• our stock buyback program;


•	our ability to obtain permits and governmental approvals;

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


•	pending legal and environmental matters;

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

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


•	our leasehold or business acquisitions;

• our costs of developing our ~~oil and gas~~ 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, ~~crude oil~~ and ~~midstream~~crude ~~products~~oil;

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

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

• our ~~plans,~~ability ~~objectives,~~to ~~expectations~~collect ~~and~~receivables ~~intentions~~from ~~contained~~High inMesa, ~~this~~Inc. ~~report~~and ~~that~~its ~~are~~subsidiaries; ~~not historical.~~and

We• ~~caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond~~ our ~~control~~plans, ~~incident to the exploration for and development~~objectives, ~~production,~~expectations ~~gathering~~ and ~~sale~~intentions ofcontained ~~oil,~~in ~~natural~~this ~~gas~~Quarterly ~~and~~Report ~~natural gas liquids. Some factors~~ that ~~could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but~~ are not limited to, the ability of the combined company to realize the anticipated benefits of the Business Combination, costs related to the Business Combination, commodity price volatility, low prices for oil, natural gas and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, risks related to weather, security, drilling and operations, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in historical.

4We 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

Table of Contents

~~our~~Index ~~debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure~~ to ~~realize~~Financial expected value creation from property acquisitions, title defects, limited control over non-operated properties, and the other risks described under “Item 1A. Risk Factors” in our 2017 Annual Report on Form 10-K and in this report.Statements

~~Reserve~~and ~~engineering~~sale isof oil, natural gas and natural gas liquids. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, the ability to confirm and consummate a ~~process~~plan of ~~estimating~~reorganization; ~~underground~~risks ~~accumulations~~attendant ofto ~~oil~~the bankruptcy process, including the effects thereof on our business and ~~natural~~on ~~gas~~the interests of various constituents, the length of time that ~~cannot~~we might be ~~measured~~required to operate in anbankruptcy ~~exact~~and ~~way.~~the ~~The~~continued ~~accuracy~~availability of operating capital during the pendency of such proceedings; risks associated with third party motions in any ~~reserve~~bankruptcy ~~estimate~~case, ~~depends~~which onmay interfere with the ~~quality~~ability to confirm and consummate a plan of ~~available~~reorganization; ~~data,~~potential ~~the~~adverse ~~interpretation~~effects on our liquidity or results of ~~such~~operations; ~~data~~increased ~~and~~costs to execute the reorganization; effects on the market price of our common stock and ~~cost~~on ~~assumptions~~our ~~made~~ability byto ~~reservoir~~access ~~engineers. Specifically~~the capital markets; commodity price volatility, ~~future~~global ~~prices~~economic ~~received~~conditions, including supply and demand levels for ~~production~~oil, gas and NGLs, inflation, increased operating costs, ~~may~~lack ~~vary~~of availability of drilling and production equipment, ~~perhaps~~supplies, ~~significantly~~services and qualified personnel, liabilities resulting from litigation or the ~~prices~~SEC investigation, difficulties in obtaining necessary approvals and ~~costs~~permits, ~~assumed~~uncertainties ~~for~~related ~~purposes~~to new technologies, geographical concentration of ~~these~~our ~~estimates. In~~operations, ~~addition~~environmental risks, ~~the~~weather ~~results~~risks, ofsecurity risks, drilling and other operating risks, ~~testing~~regulatory changes, the uncertainty inherent in estimating oil and gas reserves and in projecting future rates of production, ~~activities~~reductions ~~may~~in ~~justify~~cash ~~revisions~~flow, lack of ~~estimates~~access ~~that~~to ~~were~~capital, ~~made~~our ~~previously.~~ability Ifto ~~significant~~satisfy future cash obligations, ~~such~~restrictions ~~revisions~~in ~~would~~our ~~change~~debt agreements, the ~~schedule~~timing of ~~any~~development ~~further~~expenditures, ~~production~~managing our growth and ~~development~~integration ~~drilling.~~of ~~Accordingly~~acquisitions, ~~reserve~~cyber-attacks, ~~estimates~~failure ~~may~~to ~~differ~~realize ~~significantly~~expected value creation from ~~the~~property ~~quantities~~acquisitions, oftitle ~~oil~~defects, limited control over non-operated properties, and ~~natural~~the ~~gas~~other ~~that~~risks ~~are~~described ~~ultimately~~in ~~recovered~~Risk Factors in our 2018 10-K.

~~Should~~Estimating ~~one~~reserve orquantities ~~more~~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 ~~risks~~relative ormix ~~uncertainties~~of ~~described~~oil, innatural gas and NGLs that will be ultimately produced, drilling and operating costs, capital expenditures, the ~~2017~~effect ~~Annual~~of ~~Report~~government onregulation, ~~Form~~taxes ~~10-K~~and oravailability ~~this~~of ~~report~~funds. Future ~~occur~~prices received for production and costs may vary, orperhaps ~~should~~significantly, ~~underlying~~from the assumptions ~~prove~~used ~~incorrect,~~in our ~~actual~~estimates. In addition, the results of drilling, testing and ~~plans~~production ~~could~~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 ~~materially~~significantly from ~~those~~the ~~expressed~~quantities inof ~~any~~oil ~~forward-looking~~and ~~statements~~gas that are ultimately recovered.

~~Except~~Should asone ~~otherwise~~or ~~required~~more byof ~~applicable~~the ~~law,~~risks weor ~~disclaim~~uncertainties ~~any~~described ~~duty~~in tothis ~~update~~Quarterly ~~any~~Report ~~forward-looking~~or ~~statements,~~in ~~all~~the of2018 ~~which~~10-K ~~are~~occur, ~~expressly~~or ~~qualified~~should byunderlying ~~the~~assumptions ~~statements~~prove ~~in this section~~incorrect, toour ~~reflect~~actual ~~events~~results orand ~~circumstances~~plans ~~occurring~~could ~~after~~differ ~~the~~materially ~~date~~from ofthose ~~this~~expressed ~~Quarterly~~in ~~Report~~any ~~on Form 10~~forward-Qlooking statements.

5Except 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.

Table of Contents

~~PART~~Index Ito —Financial ~~FINANCIAL INFORMATION~~Statements

~~ITEM 1.~~PART ~~Financial~~I ~~Statements~~- FINANCIAL INFORMATION

Item 1. Financial Statements

ALTA MESA RESOURCES, INC.

CONDENSED CONSOLIDATED ~~BALANCE~~STATEMENTS ~~SHEETS~~OF OPERATIONS (Unaudited)

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

	Successor				~~Predecessor~~		Predecessor
	September 30, 2018				December 31, 2017
	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 8, 2018
ASSETS
Revenue
CURRENT ASSETS
Oil	$	86,363		$	40,278		$	30,972
Cash and cash equivalents	$	32,185			$	3,660
Natural gas	18,450			5,210			4,276
Restricted cash	872				1,269
Natural gas liquids	11,216			4,714			4,000
Accounts receivable, net	122,828				76,161
Sales of gathered production	9,560			3,873			—
Other receivables	250				1,388
Midstream revenue	7,155			3,260			—
Receivables due from related party	15,395				790
Other	3,085			555			888
Note receivable due from related party	1,642				—
Operating revenue	135,829			57,890			40,136
Prepaid expenses and other current assets	3,883				2,932
Gain on sale of assets	1,483			5,139			840
Current assets — discontinued operations	—				5,195
Gain (loss) on derivatives	(23,777		)	(22,011		)	6,663
Derivative financial instruments	—				216
Total revenue	113,535			41,018			47,639
Total current assets	177,055				91,611
Operating expenses
PROPERTY, PLANT AND EQUIPMENT
Lease operating	19,944			8,317			4,408
Oil and natural gas properties, successful efforts method, net	2,697,757				894,630
Transportation, processing and marketing	4,603			3,359			3,725
Other property, plant and equipment, net	401,424				32,140
Midstream operating	6,151			587			—
Total property, plant and equipment, net	3,099,181				926,770
Cost of sales for purchased gathered production	9,695			3,809			—
OTHER ASSETS
Production taxes	5,483			1,415			953
Equity method investment	9,338				—
Workovers	313			1,245			423
Deferred financing costs, net	3,377				1,787
Exploration	2,054			1,585			7,003
Notes receivable due from related party	11,492				12,369
Depreciation, depletion and amortization	37,899			15,679			11,670
Goodwill	699,898				—
General and administrative	29,518			37,752			21,234
Intangible assets, net	403,552				—
Total operating expenses	115,660			73,748			49,416
Deposits and other long-term assets	89				9,067
Operating income	(2,125		)	(32,730		)	(1,777		)
Non-current assets — discontinued operations	—				43,785
Other income (expense)
Deferred tax asset	9,077				—
Interest expense	(15,460		)	(5,444		)	(5,511		)
Derivative financial instruments	—				8
Interest income	51			546			172
Total other assets	1,136,823				67,016
Equity in earnings of unconsolidated subsidiaries	99			—			—
TOTAL ASSETS	$	4,413,059			$	1,085,397
Total other income (expense), net	(15,310		)	(4,898		)	(5,339		)
Loss from continuing operations before income taxes	(17,435		)	(37,628		)	(7,116		)
Income tax provision (benefit)	—			(3,874		)	—
Loss from continuing operations	(17,435		)	(33,754		)	(7,116		)
Loss from discontinued operations, net of tax	—			—			(7,746		)
Net loss	(17,435		)	(33,754		)	$	(14,862	)
Net loss attributable to noncontrolling interests	(9,028		)	(20,424		)
Net loss attributable to Alta Mesa Resources, Inc. stockholders	$	(8,407	)	$	(13,330	)
Attributable to Alta Mesa Resources, Inc. stockholders:
Loss per share - basic and diluted	$	(0.05	)	$	(0.08	)
Weighted average shares outstanding - basic and diluted	180,265,954			169,371,730

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

Table of Contents

	Successor			Predecessor
	September 30, 2018			December 31, 2017
LIABILITIES, PARTNERS’ CAPITAL AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	240,431		$	170,489
Accounts payable — affiliate	—			5,476
Advances from non-operators	9,233			5,502
Advances from related party	16,917			23,390
Asset retirement obligations	1,300			69
Current liabilities — discontinued operations	—			15,419
Derivative financial instruments	34,396			19,303
Total current liabilities	302,277			239,648
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	9,169			10,400
Long-term debt, net	676,354			607,440
Noncurrent liabilities — discontinued operations	—			66,862
Derivative financial instruments	7,078			1,114
Deferred tax liability	4,893			—
Other long-term liabilities	5			5,488
Total long-term liabilities	697,499			691,304
TOTAL LIABILITIES	999,776			930,952
PREFERRED STOCK, $0.0001 par value
Class A: 1,000,000 shares authorized; 3 shares issued and outstanding	—			—
Class B: 1,000,000 shares authorized; 1 share issued and outstanding	—			—
Commitments and Contingencies (Note 14)
PARTNERS’ CAPITAL	—			154,445
STOCKHOLDERS’ EQUITY
Common stock, $0.0001 par value
Class A: 1,200,000,000 shares authorized; 175,957,183 shares issued and outstanding	18			—
Class C: 280,000,000 shares authorized; 204,921,888 shares issued and outstanding	20			—
Additional paid in capital	1,472,570			—
Accumulated deficit	(20,658		)	—
Total stockholders’ equity/partners’ capital	1,451,950			154,445
Noncontrolling interest	1,961,333			—
Total equity	3,413,283			154,445
TOTAL LIABILITIES, PARTNERS’ CAPITAL AND STOCKHOLDERS’ EQUITY	$	4,413,059		$	1,085,397

Index to Financial Statements

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

Table of Contents

ALTA MESA RESOURCES, INC.

CONDENSED CONSOLIDATED ~~STATEMENTS~~BALANCE OFSHEETS ~~OPERATIONS~~ (Unaudited)

(in thousands~~, except per share data~~)

	Successor			Predecessor			Successor			Predecessor
	Three			Three			February 9, 2018			January 1, 2018			Nine
	Months Ended			Months Ended			Through			Through			Months Ended
	September 30, 2018			September 30, 2017			September 30, 2018			February 8, 2018			September 30, 2017
OPERATING REVENUES AND OTHER
Oil	$	107,253		$	44,201		$	222,822		$	30,972		$	133,489
Natural gas	11,959			9,583			25,149			4,276			29,816
Natural gas liquids	13,880			7,548			28,835			4,000			21,201
Product sales	22,676			—			50,650			—			—
Gathering and processing revenue	8,102			—			18,586			—			—
Other revenues	1,011			1,792			3,795			888			5,005
Total operating revenues	164,881			63,124			349,837			40,136			189,511
Gain (loss) on sale of assets and other	(18		)	—			5,898			—			—
Gain on acquisition of oil and gas properties	—			5,267			—			—			5,267
Gain (loss) on derivative contracts	(11,212		)	(10,468		)	(63,077		)	7,298			38,024
Total operating revenues and other	153,651			57,923			292,658			47,434			232,802
OPERATING EXPENSES
Lease operating expense	16,351			10,407			37,347			4,485			32,897
Marketing and transportation expense	2,847			8,314			6,041			3,725			20,486
Plant operating expense	4,507			—			8,407			—			—
Product expense	22,830			—			50,433			—			—
Gathering and processing expense	2,334			—			7,912			—			—
Production taxes	6,311			1,262			10,332			953			3,712
Workover expense	1,065			1,441			2,643			423			3,131
Exploration expense	1,029			3,649			14,067			3,633			11,888
Depreciation, depletion and amortization expense	52,877			24,159			102,227			11,784			63,247
Impairment expense	—			—			—			—			1,188
Accretion expense	226			108			489			39			234
General and administrative expense	11,902			17,445			68,915			24,352			35,474
Total operating expenses	122,279			66,785			308,813			49,394			172,257
INCOME (LOSS) FROM OPERATIONS	31,372			(8,862		)	(16,155		)	(1,960		)	60,545
OTHER INCOME (EXPENSE)
Interest expense	(12,348		)	(13,545		)	(29,571		)	(5,511		)	(38,165		)
Interest income and other	357			244			1,727			172			792
Total other income (expense), net	(11,991		)	(13,301		)	(27,844		)	(5,339		)	(37,373		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	19,381			(22,163		)	(43,999		)	(7,299		)	23,172
Income tax provision (benefit)	1,626			—			(5,865		)	—			285
INCOME (LOSS) FROM CONTINUING OPERATIONS	17,755			(22,163		)	(38,134		)	(7,299		)	22,887
Loss from discontinued operations, net of tax	—			(2,041		)	—			(7,593		)	(37,490		)
NET INCOME (LOSS)	17,755			(24,204		)	(38,134		)	(14,892		)	(14,603		)
Net income (loss) attributable to non-controlling interest	10,620			—			(25,590		)	—			—
NET INCOME (LOSS) ATTRIBUTABLE TO ALTA MESA RESOURCES, INC. STOCKHOLDERS	$	7,135		$	(24,204	)	$	(12,544	)	$	(14,892	)	$	(14,603	)
NET INCOME (LOSS) PER COMMON SHARE ATTRIBUTABLE TO ALTA MESA RESOURCES INC. STOCKHOLDERS:
Basic	$	0.04					$	(0.07	)
Diluted	$	0.04					$	(0.08	)

໿

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



	March 31, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	36,512	$	26,854
Restricted cash	798		1,001
Accounts receivable, net	81,936		87,842
Other receivables	2,239		6,331
Related party receivables, net	2,310		3,341
Prepaid expenses and other	4,923		1,125
Derivatives	—		16,423
Total current assets	128,718		142,917
Property and equipment, net
Oil and gas properties, successful efforts method	777,750		763,337
Other property and equipment	456,964		444,269
Total property and equipment, net	1,234,714		1,207,606
Other assets
Operating lease right-of-use assets, net	15,085		—
Equity method investment	1,199		1,100
Deferred financing costs, net	3,084		3,195
Deposits and other long-term assets	50		65
Derivatives	461		2,947
Total other assets	19,879		7,307
Total assets	$	1,383,311	$	1,357,830



	March 31, 2019			December 31, 2018
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt	$	988,892		$	690,123
Accounts payable and accrued liabilities	148,682			247,439
Advances from non-operators	2,366			5,193
Advances from related party	4,478			9,839
Asset retirement obligations, current portion	48			2,079
Current operating lease liability	976			—
Derivatives	5,057			1,710
Total current liabilities	1,150,499			956,383
Long-term liabilities
Asset retirement obligations, net of current portion	11,895			9,473
Long-term debt, net	—			174,000
Other long-term liabilities	3,414			1,667
Operating lease liabilities, net of current portion	14,209			—
Derivatives	2,065			180
Total long-term liabilities	31,583			185,320
Total liabilities	1,182,082			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; 180,410,200 shares issued and outstanding (180,072,227 issued and outstanding at December 31, 2018)	18			18
Class C: 280,000,000 shares authorized; 202,169,576 issued and outstanding at March 31, 2019 and December 31, 2018	20			20
Additional paid in capital	1,506,128			1,503,382
Accumulated deficit	(1,541,220		)	(1,532,813		)
Total stockholders’ equity	(35,054		)	(29,393		)
Noncontrolling interests	236,283			245,520
Total equity	201,229			216,127
Total liabilities and stockholders’ equity	$	1,383,311		$	1,357,830

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

Table of Contents

Index to Financial Statements

ALTA MESA RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)

	Successor				~~Predecessor~~			Predecessor
	February 9, 2018 Through September 30, 2018				January 1, 2018 Through February 8, 2018			Nine Months EndedSeptember 30, 2017
	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018				January 1, 2018ThroughFebruary 8, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Cash flows from operating activities:
Net loss	$	(3817,~~134~~435	)	$	$(33,754	~~(14,892~~)	)	$	(14,~~603~~862	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization expense	102,227				12,414			80,082
Depreciation, depletion and amortization	37,899			15,679				12,554
Impairment expense	—				5,560			29,206
Non-cash lease expense	847			—				—
Accretion expense	489				140			1,447
Provision for uncollectible related party receivables	853			—				—
Amortization of deferred financing costs	339				171			2,205
Impairment of assets	—			—				5,560
Amortization of debt premium	(3,281		)		—			—
Amortization of deferred financing costs	120			—				171
Equity-based compensation expense	8,333				—			—
Amortization of debt premium	(1,231		)	(820		)		—
Dry hole expense	—				(45		)	2,447
Equity-based compensation expense	2,679			3,466				—
Expired leases	10,658				1,250			8,394
Non-cash exploration expense	181			819				4,575
(Gain) loss on derivative contracts	63,077				(7,298		)	(38,024		)
(Gain) loss on derivatives	23,777			22,011				(6,663		)
Cash settlements of derivative contracts	(32,836		)		(1,661		)	1,775
Cash settlements of derivatives	365			(3,975		)		(2,296		)
Premium paid on derivative contracts	—				—			(520		)
Interest converted into debt	—			—				103
Interest converted into debt	—				103			904
Interest added to notes receivable from affiliate	—			(163		)		(85		)
Interest added to notes receivable due from related party	(680		)		(85		)	(619		)
Deferred tax provision (benefit)	—			(3,874		)		—
Deferred tax benefit	(5,082		)		—			—
Loss on sale of fixed assets	—			—				1,923
Loss on sale of assets and other	81				1,923			—
Equity in earnings of unconsolidated subsidiaries	(99		)	—				—
Gain on acquisition of oil and gas properties	—				—			(6,893		)
Impact on cash from changes in:
Impact on cash from changes in assets and liabilities:
Accounts receivable	5,906			(3,746		)		(21,184		)
Accounts receivable	(16,225		)		(20,895		)	(33,649		)
Other receivables	4,093			997				(662		)
Other receivables	972				(9,887		)	7,382
Related party receivables	179			(1,510		)		(117		)
Receivables due from related party	(14,488		)		(117		)	169
Prepaid expenses and other assets	(3,783		)	(2,193		)		(591		)
Prepaid expenses and other non-current assets	8,366				9,970			(9,938		)
Advances from related party	(5,360		)	(7,008		)		24,116
Advances from related party	(30,589		)		24,116			5,266
Settlement of asset retirement obligations	(147		)	(166		)		(63		)
Settlement of asset retirement obligation	(1,249		)		(63		)	(6,083		)
Accounts payable, accrued liabilities and other liabilities	(3,293		)	(72,323		)		23,857
Accounts payable, accrued liabilities, and other liabilities	(49,472		)		25,815			27,308
Operating lease obligations	(748		)	—				—
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,506				26,519			56,256
Cash from operating activities	44,803			(86,560		)		26,336
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash flows from investing activities:
Capital expenditures for property, plant and equipment	(523,645		)		(38,096		)	(244,308		)
Capital expenditures	(161,348		)	(133,055		)		(36,695		)
Acquisitions, net of cash acquired	~~(791,819~~—		)	(796,827	—	)		(551,~~236~~218		)
Proceeds withdrawn from Trust Account	1,042,742				—			—
Proceeds withdrawn from trust account	—			1,042,742				—
Investment in equity affiliate and other, net	(9,326		)		—			(1,515		)
Cash from investing activities	(161,348		)	112,860				(37,913		)
NET CASH USED IN INVESTING ACTIVITIES	(282,048		)		(38,096		)	(301,059		)
Cash flows from financing activities:
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt borrowings	126,000			9,000				60,000
Proceeds from long-term debt	162,500				60,000			286,065
Repayments of long-term debt	—			(134,065		)		(43,000		)
Repayments of long-term debt	(193,565		)		(43,000		)	(251,622		)
Deferred financing costs paid	—			(1,007		)		—
Additions to deferred financing costs	(3,716		)		—			(220		)
Capital distributions	—			—				(68		)
Purchase and retirement of Class A common shares	(14,750		)		—			—
Proceeds from issuance of Class A shares	—			400,000				—
Capital distributions	—				(68		)	—
Repayment of sponsor note	—			(2,000		)		—
Capital contributions	—				—			207,875
Repayment of deferred underwriting compensation	—			(36,225		)		—
Proceeds from issuance of Class A shares	400,000				—			—
Redemption of Class A common shares	—			(33		)		—
Repayment of sponsor note	(2,000		)		—			—
Cash from financing activities	126,000			235,670				16,932
Repayment of deferred underwriting compensation	(36,225		)		—			—
Net increase in cash, cash equivalents and restricted cash	9,455			261,970				5,355
Redemption of Class A common shares	(33		)		—			—
Cash, cash equivalents and restricted cash, beginning of period	27,855			388				4,990
NET CASH PROVIDED BY FINANCING ACTIVITIES	312,211				16,932			242,098
Cash, cash equivalents and restricted cash, end of period	$	37,310		$	262,358			$	10,345
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	32,669				5,355			(2,705		)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period	388				4,990			7,618
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, end of period	$	33,057			$	10,345		$	4,913

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

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Index to Financial Statements

ALTA MESA RESOURCES, INC.

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

(in thousands)

	Common Stock														~~Additional~~						Total
	Class A				Class B					Class C					Paid-In			Accumulated			Stockholders’			Noncontrolling			Total
	Shares		Amount		Shares		Amount			Shares		Amount			Capital			Deficit			Equity			~~Interest~~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,~~235~~330		)	(13,~~235~~330		)	(20,~~314~~424		)	(33,~~549~~754		)
Balance at March 31, 2018	169,372		17$	17	—		—$	—		213,402		21$	21		~~1,402,888~~$	1,402,888		~~(21,349~~$	(21,444	)	~~1,381,577~~$	1,381,482		~~2,038,321~~$	2,038,211		~~3,419,898~~$	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	—		—		—		—			—		—			—			(6,444		)	(6,444		)	(15,896		)	(22,340		)
Balance at June 30, 2018	179,059		18		—		—			204,922		20			1,498,023			(27,793		)	1,470,268			1,939,874			3,410,142
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	—		—		—		—			—		—			—			7,135			7,135			10,620			17,755
Balance at September 30, 2018	175,957		$	18	—		$	—		204,922		$	20		$	1,472,570		$	(20,658	)	$	1,451,950		$	1,961,333		$	3,413,283

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




	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

10The accompanying notes are an integral part of these financial statements.

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ALTA MESA RESOURCES, INC.

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

(in thousands)

໿

	Predecessor
	Three Months EndedSeptember 30, 2017			January 1, 2018 Through February 8, 2018			Nine Months EndedSeptember 30, 2017
Balance, December 31, 2017	$	154,445
Beginning balance	$	41,707		$	154,445		$	32,106
Distribution of non-STACK oil and gas assets, net of associated liabilities	43,482
Distribution of non-stack (assets) net liability	—			33,102			—
Net loss	(14,862		)
Capital contribution	200,000			—			200,000
Balance, February 8, 2018	$	183,065
Net loss	(24,204		)	(14,892		)	(14,603		)
Ending balance	$	217,503		$	172,655		$	217,503

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

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Index to Financial Statements

ALTA MESA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Alta Mesa Resources, Inc., together with its consolidated subsidiaries (“~~AMR,” “~~we,” ~~“us,” “our,”~~ or “the “Company”), is an independent ~~energy~~exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. ~~Our~~We ~~activities~~operate ~~are~~in ~~primarily~~two ~~directed~~reportable atbusiness ~~the~~segments ~~horizontal~~- ~~development~~Upstream ofand anMidstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and ~~liquids-rich~~gas ~~resource~~properties ~~play~~located in an area of the ~~basin~~Anadarko Basin commonly referred to as the ~~Sooner~~STACK. We ~~Trend~~generate ~~Anadarko~~upstream ~~Basin~~revenue ~~Canadian~~principally by the production and ~~Kingfisher~~sale ~~County~~of ~~(“STACK”)~~oil, gas and NGLs. We also operate ain ~~midstream~~the ~~services~~Midstream ~~business~~segment through Kingfisher Midstream, LLC (“~~Kingfisher~~KFM”),. KFM has a ~~Delaware~~gas ~~limited~~and ~~liability~~oil ~~company. Kingfisher~~gathering ~~has~~network, ~~natural~~a cryogenic gas ~~gathering~~processing ~~and~~plant ~~processing~~with ~~and~~offtake ~~crude~~capacity, ~~oil~~field ~~gathering~~compression facilities and ~~storage~~a ~~assets~~produced ~~located~~water disposal system in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The ~~Kingfisher~~KFM assets are integral to our ~~oil~~Upstream ~~and~~operations, ~~natural~~which ~~gas~~we ~~operations~~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, ~~capital stock~~ exchange, ~~asset~~ acquisition, ~~stock~~ purchase, reorganization or similar business combination involving ~~the~~it ~~Company~~ 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.” Our Class A Common Stock and public warrants are listed on the NASDAQ Capital Market (“NASDAQ”) under the symbols “AMR” and “AMRWW,” respectively. However, as a result of our failure to comply with the NASDAQ continued listing requirements, trading of our common stock and warrants will be suspended at the opening of business on September 24, 2019 and will be removed from listing and registration on NASDAQ. The Company expects the common stock and warrants to be traded over the counter under the trading symbols “AMRQ” and “AMRWWQ”, respectively.

OnIn ~~March 29,~~connection ~~2017,~~with ~~we consummated our initial public offering (“IPO”), generating net proceeds of approximately $1.035 billion, as well as~~ the ~~private~~closing ~~sale~~ of ~~15,133,333 warrants (~~the ~~“Private~~Business ~~Placement Warrants”) to Silver Run Sponsor II~~Combination, ~~LLC~~Alta ~~(the~~Mesa ~~“Sponsor”)~~distributed ~~for~~its ~~$22.7~~non-STACK ~~million. Proceeds~~oil ~~from~~and ~~the~~gas ~~IPO~~assets ~~were~~and ~~placed~~associated inliabilities ~~a trust account in 2017. The amounts deposited~~ to ~~the~~its ~~trust~~prior ~~account~~owner, ~~including~~High interest, were utilized to fund a business combination (the “Business Combination”), as described in Note 4 — Business Combination, on February 9, 2018 in which the Company acquired interests in Alta Mesa Holdings, LP (“~~Alta~~High Mesa”),. The ~~Alta~~non-STACK ~~Mesa~~assets ~~Holdings GP, LLC (“Alta Mesa GP”)~~ and ~~Kingfisher~~liabilities ~~through~~are areflected ~~newly~~as ~~formed~~discontinued ~~subsidiary,~~operations ~~SRII~~in ~~Opco,~~our LPfinancial ~~(“SRII Opco”)~~statements.

InAll ~~connection~~intercompany ~~with~~transactions ~~the~~and ~~closing~~accounts ofhave ~~the~~been ~~Business~~eliminated. ~~Combination~~These interim condensed consolidated financial statements are unaudited, ~~Alta~~but ~~Mesa~~we ~~distributed~~believe ~~its~~these ~~non-STACK~~statements ~~assets~~reflect ~~and~~all ~~liabilities~~adjustments tonecessary ~~High~~for ~~Mesa~~a ~~Holdings,~~fair LPpresentation (for the ~~“AM~~periods ~~Contributor”)~~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 ~~Company~~SEC’s ~~changed~~rules ~~its~~for ~~name~~interim ~~from~~financial ~~“Silver~~statements ~~Run~~and ~~Acquisition~~do ~~Corporation~~not ~~II”~~include toall the information and disclosures required by generally accepted accounting principles (“~~Alta~~GAAP”) ~~Mesa~~for ~~Resources,~~complete ~~Inc~~financial statements.” ~~and~~These ~~continued~~financial ~~the~~statements ~~listing~~should ofbe ~~its~~read ~~Class~~in Aconjunction ~~Common~~with ~~Stock~~the audited consolidated financial statements and ~~public~~notes ~~warrants~~thereto ~~(which~~included ~~were~~in ~~originally~~our ~~sold~~2018 as10-K. ~~part~~The ofresults for the ~~units~~three ~~issued~~months inended ~~our~~March 31, ~~initial~~2019, ~~public~~are ~~offering)~~not onnecessarily ~~NASDAQ~~indicative ~~under~~of the ~~symbols~~results ~~“AMR”~~to ~~and~~be ~~“AMRWW,”~~expected ~~respectively~~for the full year. We have no items of other comprehensive income during any period presented. Certain prior period amounts have been reclassified to conform to the current period presentation.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

~~Basis~~Going of Presentation. As a result of the Business Combination, the Company is the acquirer for accounting purposes and Alta Mesa and Kingfisher are the acquirees. Alta Mesa is our accounting predecessor. The Company’s financial statement presentation reflects Alta Mesa as the “Predecessor” for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, which includes the consolidation of Alta Mesa and Kingfisher concurrent with the Business Combination on February 9, 2018. The Business Combination was accounted for using the acquisition method of accounting, and the Successor financial statements reflect a new basis of accounting that is based on the fair value of Alta Mesa and Kingfisher’s net assets acquired as of the acquisition date. See Note 4 — Business Combination for further information related to the Business Combination. As a result of the Business Combination and the transactions contemplated by the Contribution Agreements, the financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the Transactions and the period on or after that date, to indicate that the financial statements presented are those of different entities and reflect the application of the different basis of accounting between the periods presented. The Successor periods presented herein are for the three months ended September 30, 2018 and from February 9, 2018 to September 30, 2018 (collectively, “Successor Periods”); and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”), the three months ended September 30, 2017 and the nine months ended September 30, 2017 (“2017 Predecessor Period,” and, together with the 2018 Predecessor Period, the “Predecessor Periods”).Concern

~~Prior~~We are required to ~~the~~evaluate ~~Business~~our ~~Combination,~~ability ~~Alta~~to ~~Mesa~~continue ~~distributed~~as ~~its~~a ~~non-STACK~~going ~~assets~~concern ~~and~~for ~~liabilities~~a toperiod of one year following the AMdate ~~Contributor~~of issuance of our financial statements. ~~The~~ As ~~distribution~~part of ~~its~~that ~~non-STACK~~evaluation, ~~assets~~we ~~and~~took ~~liabilities~~into consideration a number of factors that were previously disclosed in our 2018 ~~and~~10-K. Most ~~the~~significantly, ~~sale~~we ofhave ~~its~~seen ~~Weeks~~significant ~~Island~~reductions ~~field~~to ~~during~~our borrowing base under the ~~fourth~~Alta ~~quarter~~Mesa ofRBL ~~2017~~in ~~(collectively~~2019. On April 1, 2019, our borrowing base under the ~~“non-STACK~~Alta ~~assets”)~~Mesa ~~were~~RBL ~~part~~was ofreduced by $30 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa’s ~~overall~~RBL ~~strategic~~lenders ~~shift~~exercised their ability to ~~operate~~make ~~only~~an inoptional redetermination of our borrowing base ahead of the ~~eastern~~regular ~~Anadarko~~redetermination ~~Basin~~scheduled in October 2019, and via this redetermination our borrowing base was reset to $200 million, effective August 13, 2019. As aour ~~result~~combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we ~~have~~had ~~classified~~five ~~the~~months, ~~assets~~beginning ~~and~~September ~~liabilities~~2019, ~~and~~to ~~operating~~make ~~results~~ratable monthly payments of ~~the~~$32.5 ~~non-STACK~~million ~~assets~~to ascause

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~~discontinued~~Index ~~operations~~to ~~during~~Financial ~~the Predecessor Periods within the consolidated financial statements. See Note 6 — Discontinued Operations (Predecessor) for further discussion.~~Statements

~~Principles~~utilization ofto ~~Consolidation~~be ~~and~~less ~~Reporting. The~~than ~~consolidated~~or ~~financial~~equal ~~statements~~to ~~have been prepared in accordance with accounting principles generally accepted in~~ the ~~United~~borrowing ~~States of America (“GAAP”)~~base. ~~Certain~~Our ~~reclassifications~~Upstream ofbusiness ~~prior~~had ~~period~~cash ~~consolidated~~on ~~financial~~hand ~~statements~~at ~~have~~August ~~been made to conform to current reporting practices. The consolidated financial statements include the accounts of the Company and its subsidiaries~~31, ~~including~~2019 SRII Opco, after eliminating all significant intercompany transactions and balances. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. Noncontrolling interest represents third-party ownership interests in SRII Opco and is presented as a component of ~~equity~~$62.3 ~~See Note 16 — Stockholders’ Equity and Partners’ Capital for further discussion~~million.

~~The~~If ~~consolidated~~by ~~financial~~September ~~statements~~12, ~~included~~2019, ~~herein~~we ~~are~~had ~~unaudited~~not made the first payment of $32.5 million, ~~and~~we would have been in ~~the~~default. Despite ~~opinion~~taking ofvarious ~~management~~actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the ~~information~~Company, ~~furnished~~Alta ~~reflects~~Mesa ~~all~~GP, ~~material~~OEM ~~adjustments~~GP, ~~consisting~~LLC, ofAlta ~~normal~~Mesa ~~recurring~~Finance ~~adjustments~~Services Corp., ~~necessary~~Alta Mesa Services and Oklahoma Energy Acquisitions, LP (the “AMH Debtors” and, together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for areorganization ~~fair~~under ~~presentation~~Chapter 11 of ~~consolidated~~the ~~financial~~United ~~position~~States ~~and~~Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the ~~results~~“Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of ~~operations~~the ~~for~~Chapter 11 cases under the ~~interim~~caption ~~periods~~In ~~presented~~re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The ~~consolidated~~Debtors ~~results~~will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of ~~operations~~the ~~for~~Bankruptcy ~~interim~~Court ~~periods~~and ~~are~~in ~~not~~accordance ~~necessarily~~with ~~indicative~~the applicable provisions of ~~results~~the toBankruptcy beCode ~~expected~~and ~~for~~orders aof ~~full~~the ~~year~~Bankruptcy Court.

~~Segment~~On ~~Reporting~~September ~~(Successor). The~~12, ~~Company~~2019, ~~operates~~the inBankruptcy ~~two~~Court ~~business~~entered ~~segments. Alta~~various ~~Mesa~~orders ~~operates~~requested by the Debtors in ~~one~~order ~~industry~~to ~~segment~~stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, ~~which~~including isorders authorizing the ~~exploration~~Debtors ~~and~~to ~~production~~honor ofcertain ~~oil~~obligations to employees, vendors, and ~~natural~~holders ~~gas~~of royalty interests. ~~Kingfisher~~In ~~operates~~addition, in the ~~midstream~~AMH ~~segment~~Debtors aswere ~~the~~authorized ~~owner~~by ~~and~~the ~~operator~~Bankruptcy ofCourt ~~gas~~to ~~gathering~~use ~~and~~cash ~~processing~~collateral ~~assets~~of ~~and~~the ~~crude~~lenders ~~oil~~under ~~gathering~~the ~~and~~Alta ~~transportation~~Mesa ~~assets~~RBL. ~~Both~~The ~~operations~~cash ~~are~~collateral ~~conducted~~order inpermits ~~one~~the ~~geographic~~AMH ~~area~~Debtors to use their cash and proceeds of their collateral for an initial four week period on the ~~United~~terms ~~States~~and conditions agreed by the AMH Debtors and ~~all~~the ~~revenues~~lenders ~~are~~under ~~derived~~the ~~from~~Alta ~~customers~~Mesa ~~located~~RBL and set forth in the ~~United States~~order. The ~~Company~~terms ~~reports~~and ~~its~~conditions ~~consolidated~~include, ~~financial~~without ~~results~~limitation, ~~under~~adherence ~~two~~to ~~reportable~~a ~~segments:~~budget ~~(1)~~with ~~Exploration~~an &agreed ~~Production~~upon variance and ~~(2)~~meeting ~~Midstream~~certain milestones. ~~See~~ The ~~Note~~ability 21to —have ~~Business~~continued ~~Segment~~access ~~Information~~to ~~for~~the ~~financial~~cash ~~information~~collateral ~~about~~will ~~our~~also ~~segments~~be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order.

~~Use~~The ofDebtors ~~Estimates. The~~have ~~preparation~~begun ofa ~~consolidated~~marketing ~~financial~~process ~~statements~~to insell ~~conformity~~their ~~with~~assets, ~~GAAP~~which ~~requires~~may ~~management~~also toinclude ~~make~~the ~~estimates~~midstream ~~and~~assets ~~assumptions~~of ~~that~~certain ~~affect~~of ~~the~~their ~~reported~~non-Debtor ~~amounts~~affiliates. Certain of ~~assets~~the ~~and~~AMH ~~liabilities~~Debtors ~~and~~have ~~disclosure~~also offiled ~~contingent~~a ~~assets~~complaint ~~and~~seeking ~~liabilities~~a atBankruptcy ~~the~~Court ~~date~~determination ofthat the ~~consolidated~~crude ~~financial~~oil, ~~statements~~gas, and ~~the~~water ~~reported~~gathering ~~amounts~~agreements ofbetween ~~revenues~~Debtor Oklahoma Energy Acquisitions LP, an Alta Mesa subsidiary, and ~~expenses~~non-Debtors ~~during~~KFM ~~the~~and ~~reporting~~its ~~period~~subsidiaries can be rejected by the Debtors.

~~Reserve~~Certain ~~estimates significantly impact depreciation, depletion, and amortization expense and potential impairments~~ of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other estimates are utilized to determine amounts related to oil and natural gas revenues, product sales and gathering and processing sales, the ~~value~~Company’s ofother ~~oil and natural gas properties~~subsidiaries, ~~the~~including ~~value~~SRII ofOpco ~~pipeline equipment~~GP, ~~bad debts~~LLC, ~~goodwill,~~SRII ~~intangible assets~~Opco, ~~asset~~KFM ~~retirement~~and ~~obligations,~~its ~~derivative~~subsidiaries ~~contracts,~~Kingfisher ~~accounting~~STACK ~~for~~Oil ~~business combinations~~Pipeline, ~~federal~~LLC and ~~state~~Oklahoma ~~taxes,~~Produced ~~share-based~~Water ~~compensation~~Solutions, ~~and~~LLC ~~contingencies and litigation. We base our estimates on historical experience and various other assumptions that~~ are ~~believed~~not topart beof ~~reasonable under~~ the ~~circumstances.~~Chapter We11 ~~review~~cases ~~estimates~~at ~~and~~this ~~underlying assumptions on a regular basis~~time. ~~Actual~~ ~~results may differ from these estimates.~~

~~Cash~~Because of the default under the Alta Mesa RBL and ~~Cash~~2024 ~~Equivalents. We~~Notes ~~consider~~arising from our bankruptcy filing, we have reported all ~~highly~~of ~~liquid~~our ~~investments~~Upstream ~~purchased~~debt ~~with~~as ancurrent. ~~original~~We ~~maturity~~have ofno ~~three~~meaningful ~~months~~cash oravailable ~~less~~to us to bemeet our obligations apart from cash ~~equivalents~~held by our subsidiaries. ~~The~~As ~~Company~~a ~~maintains~~result ~~cash~~of ~~balances~~Alta atMesa’s ~~financial~~bankruptcy ~~institutions~~and inthe limitations imposed under the ~~United~~cash ~~States~~collateral ofagreement ~~America~~approved by the Bankruptcy Court, ~~which~~our atonly ~~times~~remaining ~~exceed~~source ~~federally~~of ~~insured~~liquidity ~~amounts~~is through KFM and SRII Opco. At ~~The~~August ~~Federal~~31, ~~Deposit~~2019, ~~Insurance~~SRII ~~Corporation~~Opco ~~provides~~had ~~insurance~~cash upon tohand of $~~250~~5.7 million and KFM had cash on hand of $13.8 million,~~000~~ ~~per~~as ~~depositor~~well as remaining borrowing capacity of $74.0 Wemillion. Access ~~monitor~~to the ~~financial~~remaining ~~condition~~capacity ofunder the ~~financial~~KFM ~~institutions~~Credit weFacility ~~use~~requires covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. Accordingly, we have ~~experienced~~determined nothat ~~losses~~it is appropriate to ~~date~~also ~~associated~~report ~~with~~all ~~these~~of ~~accounts~~our Midstream debt as current at March 31, 2019. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.

~~Restricted~~Recently ~~Cash. The~~Issued ~~Company~~Accounting ~~classifies~~Standards ~~cash~~Applicable ~~balances as restricted cash when cash is legally, contractually or otherwise restricted as~~ to withdrawal or usage. As of September 30, 2018, and December 31, 2017, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute or there is unclaimed property for pooling orders in Oklahoma. Us

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows (in thousands):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

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Index to Financial Statements

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

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

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

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

ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on the 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 to apply the standard as of January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities totaling $15.4 million each. There was no adjustment to beginning retained earnings.

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

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

Upon adoption, we selected the following practical expedients:

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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 March 31, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.3 years and the weighted-average discount rate applied was 14.3%.

Lease Costs



(in thousands)	Three Months Ended March 31, 2019
Operating lease cost	$	847
Variable lease cost	371
Short-term lease cost	2,584
Total lease cost	$	3,802

Reported in:
Lease operating expense	$	2,615
General and administrative expense	1,187
Total lease cost	$	3,802

Operating Lease Liability Maturities as of March 31, 2019

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Fiscal year	(in thousands)
Remainder of 2019	$	2,288
2020	3,081
2021	3,047
2022	3,108
2023	2,718
Thereafter	12,647
Total lease payments	26,889
Less: imputed interest	(11,704		)
Present value of operating lease liabilities	$	15,185

Current portion of operating lease liabilities	$	976
Operating lease liabilities, net of current portion	14,209
Present value of operating lease liabilities	$	15,185

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 4 — SUPPLEMENTAL CASH FLOW INFORMATION



	Successor						Predecessor
(in thousands)	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	3,527		$	1,092		$	1,145
Cash paid for income taxes, net of refunds	706			—			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	314			421			—
Increase (decrease) in accruals or payables for capital expenditures	(96,865		)	(37,152		)	4,896
Increase in withholding tax accruals for share-based compensation	142			—			—
Distribution of non-STACK assets, net of liabilities	—			—			43,482

The following table summarizes cash, cash equivalents and restricted cash in the statements of cash flows:

໿



	Successor				Predecessor
(in thousands)	March 31, 2019		March 31, 2018		February 8, 2018
Cash and cash equivalents	$	36,512	$	261,063	$	9,070
Restricted cash	798		1,295		1,275
Total cash, cash equivalents and restricted cash	$	37,310	$	262,358	$	10,345

NOTE 5 — RECEIVABLES

Accounts Receivable



(in thousands)	March 31, 2019			December 31, 2018
Production and processing sales and fees	$	48,865		$	51,004
Joint interest billings	18,224			18,147
Pooling interest⁽¹⁾	14,960			18,786
Allowance for doubtful accounts	(113		)	(95		)
Total accounts receivable, net	$	81,936		$	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)	March 31, 2019			December 31, 2018
Related party receivables	$	12,197		$	12,375
Allowance for doubtful accounts	(9,887		)	(9,034		)
Related party receivables, net	2,310			3,341

Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Total related party receivables, net	$	2,310		$	3,341

Management Services Agreement with High Mesa

Just prior to the Business Combination, we distributed the non-STACK oil and gas assets to High Mesa. High Mesa and certain of its subsidiaries agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the “High Mesa Agreement”) with HMI with respect to the non-STACK assets. Under the High Mesa Agreement, during the 180-day period following the Closing, we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods, unless terminated by either party upon at least 90-days written notice prior to renewal. HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

The parties subsequently agreed to terminate the High Mesa Agreement, 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 March 31, 2019, and December 31, 2018, approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9 million and $9.0 million as of March 31, 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

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with litigation relating to the non-STACK assets. As of March 31, 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

In September, 2017, we entered into a $1.5 million promissory note receivable with our affiliate, Northwest Gas Processing, LLC, whose obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bore interest, which could be paid-in-kind and added to the principal amount at a rate of 8% per annum. HMS defaulted under the terms of that promissory note 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 March 31, 2019 and December 31, 2018.

In addition, we have an $8.5 million 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 $8.5 million note. As of March 31, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.

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

NOTE 6 — PROPERTY AND EQUIPMENT



(in thousands)	March 31, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	69,739		$	74,217

Proved oil and gas properties	2,163,279			2,110,346
Accumulated depletion and impairment	(1,455,268		)	(1,421,226		)
Proved oil and gas properties, net	708,011			689,120
Total oil and gas properties, net	777,750			763,337
Other property and equipment
Land	5,600			5,600
Fresh water wells	27,742			27,366
Produced water disposal system	104,334			104,498
Gas processing plant and gathering lines	396,513			380,470
Office furniture, equipment and vehicles	3,772			3,703
Accumulated depreciation and impairment	(80,997		)	(77,368		)
Other property and equipment, net	456,964			444,269
Total property and equipment, net	$	1,234,714		$	1,207,606

Depletion and Depreciation Expense



	Successor				Predecessor
(in thousands)	Three Months Ended March 31, 2019		February 9, 2018 Through March 31, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	34,042	$	10,773	$	11,021
Midstream tangible asset depreciation	3,220		1,122		—
Other property and equipment depreciation	408		163		609
Total depletion and depreciation	$	37,670	$	12,058	$	11,630

Impairment

During the three months ended March 31, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment of our long-lived assets. Therefore, we did not conduct further analysis on the recognition of additional impairment.

NOTE 7 — DISCONTINUED OPERATIONS (Predecessor)

Alta Mesa distributed the non-STACK oil and gas assets and related liabilities to High Mesa immediately prior to the Business Combination. This distribution, including the results of operations of these assets and liabilities, is presented as discontinued operations during the Predecessor Period.

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Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bore simple interest at 10%. The Founder Notes were converted into an equity interest in High Mesa immediately prior to the Business Combination as they were considered part of the non-STACK distribution. The balance of the Founder Notes at the time of conversion was approximately $28.3 million, including accrued interest. Predecessor Period interest on the Founder Notes was $0.1 million.



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



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

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	Successor		Predecessor
	September 30, 2018		December 31, 2017
Cash and cash equivalents	$	32,185	$	3,660
Restricted cash	872		1,269
Cash from discontinued operations	—		61
Total cash, cash equivalents and restricted cash	$	33,057	$	4,990

Index to Financial Statements

~~Accounts Receivable.~~NOTE Our receivables arise primarily from (i) the sale of oil, natural gas and NGLs, (ii) joint interest owners’ properties in which we serve as the operator, and (iii) for services rendered to non-affiliated customers. Our customers are concentrated in the oil and gas industry which may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the industry. Accounts receivable are generally not collateralized. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable are stated at amounts due, net of an allowance for doubtful accounts.8 — DERIVATIVES

~~Accounts~~The ~~receivable~~following ~~consisted~~summarizes of the ~~following~~fair ~~(in~~value ~~thousands)~~and classification of our derivatives:

	Successor			Predecessor
		March 31, 2019
	September 30, 2018			December 31, 2017
Balance sheet location		Gross fair valueof assets		Gross liabilitiesoffset against assetsin the Balance Sheet			Net fairvalue of assetspresented inthe Balance Sheet
Oil, natural gas and natural gas liquids sales	$	54,978		$	26,916
		(in thousands)
Joint interest billings	44,548			13,821
Derivatives, current assets		$	6,525	$	(6,525	)	$	—
Pooling interest (1)	23,367			35,839
Derivatives, long-term assets		8,182		(7,721		)	461
Allowance for doubtful accounts	(65		)	(415		)
Total		$	14,707	$	(14,246	)	$	461
Total accounts receivable, net	$	122,828		$	76,161

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



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	$	11,582	$	(6,525	)	$	5,057
Derivatives, long-term liabilities	9,786		(7,721		)	2,065
Total	$	21,368	$	(14,246	)	$	7,122

Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We establish a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated. Our assessment is based upon several factors including, but not limited to, historical experience, the length of time an invoice has been outstanding, responses from customers relating to demands for payment and the current and projected financial condition of specific customers.



	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

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



Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	7,799	$	(6,089	)	$	1,710
Derivatives, long-term liabilities	5,143		(4,963		)	180
Total	$	12,942	$	(11,052	)	$	1,890

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

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



	Successor						Predecessor
Derivatives not designated as hedges	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives -
Oil	$	(21,669	)	$	(21,944	)	$	4,796
Natural gas	(2,108		)	(67		)	1,867
Total gain (loss) on derivatives	$	(23,777	)	$	(22,011	)	$	6,663

~~Proved~~Other ~~Oil~~receivables ~~and~~at ~~Natural Gas Properties~~March —31, ~~Costs~~2019 ~~incurred to obtain access to proved reserves~~ and ~~to provide facilities for extracting~~December 31, ~~treating,~~2018 ~~gathering,~~include ~~and~~$0.3 ~~storing~~million ~~oil~~ and ~~natural gas are capitalized~~$1.3 ~~All costs incurred to drill and equip successful exploratory wells~~million, ~~development wells~~respectively, ~~development-type~~of ~~stratigraphic~~derivative ~~test~~positions ~~wells,~~scheduled ~~and~~to ~~service~~be ~~wells,~~settled ~~including~~in ~~unsuccessful~~the ~~development~~next ~~wells, are capitalized~~month.

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~~Other~~Index Property, Plant and Equipment — Other property, plant and equipment, such as land, buildings, plant equipment, assets associated with salt water disposal, office furniture and equipment and vehicles, are recorded at cost, or fair value, if impaired. Maintenance, repairs and minor renewals are expensed as incurred. Plant and equipment includes costs incurred to ~~build~~Financial ~~a cryogenic natural gas processing facility along with natural gas gathering pipelines and compression, including rights of way, and a crude oil gathering system and crude oil storage facility.~~Statements

~~Impairment — Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves resulting from acquisitions.~~ We ~~assess~~had ~~unproved properties acquired after~~ the ~~Business~~following ~~Combination~~call ~~for impairment on a quarterly basis~~ and ~~would~~put ~~recognize~~derivatives ~~a loss~~ at the time of impairment in our consolidated statement of operations by providing an impairment allowance against unproved properties. In determining whether an unproved property is impaired we consider numerous factors includingMarch 31, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, natural gas and NGL reserves, future commodity prices and future costs to produce the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. No impairment of unproved properties was recognized in the Successor Periods or the Predecessor Periods.2019:

OIL

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



	Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	137,500	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	2,035,000	66.31		75.20		56.50
Long Put Options	2,172,500	53.80		62.00		50.00
Short Put Options	2,172,500	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	1,017,600	63.95		73.80		59.55
Long Put Options	1,566,600	56.81		62.50		50.00
Short Put Options	1,566,600	42.81		50.00		37.50
2021
Collar Contracts
Short Call Options	279,750	63.51		63.75		63.35
Long Put Options	279,750	55.00		55.00		55.00
Short Put Options	279,750	43.00		43.00		43.00

NATURAL GAS

Our evaluation of the Company’s proved properties resulted in no impairment in the Successor Periods, the 2018 Predecessor Period and the three months ended September 30, 2017 (Predecessor). For the 2017 Predecessor Period, the evaluation of proved properties resulted in an impairment charge of $1.2 million.



	Volume in	Weighted			Range
Settlement Period and Type of Contract	MMBtu	Average			High			Low
2019
Price Swap Contracts	11,030,000	$	2.67		$	2.72		$	2.64
Basis Swap Contracts	16,050,000	(0.73		)	(0.49		)	(0.93		)
Collar Contracts
Short Call Options	1,525,000	3.19			3.20			3.17
Long Put Options	1,525,000	2.70			2.70			2.70
Short Put Options	1,525,000	2.20			2.20			2.20
2020
Price Swap Contracts	1,284,000	2.54			2.54			2.54
Basis Swap Contracts	910,000	(0.49		)	(0.49		)	(0.50		)
Collar Contracts
Short Call Options	3,874,500	3.19			3.69			2.77
Long Put Options	10,749,500	2.59			3.00			2.50
Short Put Options	9,696,000	2.10			2.50			2.00
2021
Collar Contracts
Short Call Options	540,000	3.25			3.25			3.25
Long Put Options	2,790,000	2.62			2.65			2.50
Short Put Options	2,250,000	2.15			2.15			2.15

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

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

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

For the three months ended September 30, 2018 (Successor) and 2017 (Predecessor), DD&A expense related to oil and natural gas properties was $44.6 million and $22.8 million, respectively. DD&A expense related to oil and natural gas properties was $81.5 million, $11.2 million, and $59.4 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. DD&A expense related to our midstream tangible assets was $1.4 million and $4.5 million for the three

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~~months~~Index ~~ended~~to ~~September 30,~~Financial ~~2018 (Successor) and the Successor Period, respectively. There was no such DD&A expense for midstream assets for the 2018 and 2017 Predecessor Periods.~~Statements

~~Leasehold~~We ~~improvements~~had ~~to offices are depreciated using~~ the ~~straight-line~~following ~~method~~basis ~~over~~swaps ~~the~~at ~~life~~March 31, of the lease. Other property and equipment is depreciated using the straight-line method over periods ranging from three years to seven years. Our midstream assets are depreciated using the straight-line method over their expected useful lives. The Company uses estimated lives of 35 years for its processing plant and pipelines.2019:

For the three months ended September 30, 2018 (Successor) and 2017 (Predecessor), depreciation expense for other property, plant and equipment was $1.8 million and $1.4 million, respectively. Depreciation expense for non-oil and natural gas properties was $2.3 million, $0.6 million, and $3.8 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.



Total Gas Volumes in MMBtu⁽¹⁾over Remaining Term	Reference Price 1 ⁽¹⁾	Reference Price 2 ⁽¹⁾	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
13,450,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '19	—	Dec '19	(0.70		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
2,140,000	San Juan	NYMEX Henry Hub	Jan '19	—	Oct '19	(0.81		)

~~See Note 9 — Intangible Assets for information related to amortization of our intangible assets.~~________________

~~Exploration~~(1) ~~Expense. Exploration~~Represents ~~expenses,~~short ~~other~~swaps ~~than~~that ~~exploration~~fix ~~drilling~~the ~~costs,~~basis ~~are~~differentials ~~charged~~between ~~to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs~~OneOK, ~~expired~~Tex/OKL ~~leases,~~Panhandle ~~delay~~Eastern ~~rentals,~~Pipeline ~~gains or losses on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, or~~ (“~~suspended~~PEPL” ~~on the balance sheet pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful~~), ~~the~~San ~~cost~~Juan ~~of the well is expensed. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well~~ and ~~sufficient~~NYMEX ~~progress~~Henry ~~in assessing the reserves and the economic and operating viability of the project is being made~~Hub. ~~Assessments of such capitalized costs are made quarterly.~~

~~Equity~~During ~~Method~~September of2019, ~~Accounting. We account for investments that~~ we doclosed ~~not~~out ~~control,~~all ~~but~~open ~~have~~derivative ~~the~~positions ~~ability~~with toeach ~~exercise significant influence using the equity method~~ of ~~accounting. Under this method,~~ our ~~equity~~7 ~~investments~~counterparties ~~are~~resulting ~~originally~~in ~~recorded at our acquisition cost, which approximates fair value, increased by our proportionate share of the investee’s~~ net ~~income~~proceeds ~~and by contributions made, and decreased by our proportionate share~~ of ~~the~~approximately ~~investee’s~~$4 ~~net losses~~million, ~~and~~which bywe ~~distributions~~applied ~~received.~~against ~~Our income from equity investments also includes amortization expense associated with the difference in basis, if any, between the initial carrying value of~~ our ~~equity~~outstanding ~~investments~~borrowings inunder ~~our consolidated balance sheets and our proportionate share of~~ the ~~underlying~~Alta ~~net~~Mesa ~~assets of our investee~~RBL.

~~Deferred~~NOTE 9 — ~~financing~~ACCOUNTS ~~costs. Deferred~~PAYABLE ~~financing~~AND ~~costs~~ACCRUED reflect fees paid to lenders and third parties that are directly related to the establishment of revolving credit facility agreements or the issuance of senior secured notes. Costs related to the establishment of the current Alta Mesa and Kingfisher secured revolving credit facilities have been deferred in other noncurrent assets and are being amortized over the term of each facility as additional interest expense. During the Predecessor Periods, costs associated with the issuance of senior secured notes were deferred as a reduction in the value of the outstanding debt and are being amortized as additional interest expense. LIABILITIES

Acquisitions. Business combinations are accounted for using the acquisition method of accounting. Accordingly, the results of operations of the acquired businesses (Alta Mesa and Kingfisher) are included in our consolidated statements of operations from the closing date of the acquisitions, except in the case of our acquisition of Alta Mesa, as that entity was deemed to be our Predecessor for accounting purposes. The total cost of each acquisition is allocated to tangible and intangible assets acquired and liabilities assumed based on their estimated fair values at the time of the acquisition.໿

Goodwill (Successor). Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. Under ASC 350, Intangibles – Goodwill and Other (“ASC 350”), goodwill is not amortized but is subject to periodic impairment testing. ASC 350 requires that an entity assign its goodwill to reporting units and test each reporting unit’s goodwill for impairment at least on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Our reporting units for goodwill impairment evaluation purposes are the Exploration & Production and Midstream business segments. Our evaluation of goodwill for impairment, will be performed annually as of October 1 of each year. During the first quarter of 2018, the Company elected to early adopt Accounting Standards Update (“ASU”) No. 2017-04, Intangibles - Goodwill and Other, Simplifying the Test for Goodwill Impairment. This new guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Accordingly, any identified impairment of goodwill will be recognized as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. During each annual evaluation, we will first assess qualitative factors to determine whether the existence of events or circumstances has led to a determination that it is more likely than not that the fair value of a reporting unit is less than



(in thousands)	March 31, 2019		December 31, 2018
Accounts payable	$	11,074	$	20,422

Accruals for capital expenditures	51,951		139,904
Revenue and royalties payable	42,591		50,241
Accruals for operating expenses	18,853		21,830
Accrued interest	15,175		2,477
Derivative settlements	49		109
Other	8,989		12,456
Total accrued liabilities	137,608		227,017
Accounts payable and accrued liabilities	$	148,682	$	247,439

NOTE 10 — ASSET RETIREMENT OBLIGATIONS



	Successor						Predecessor
(in thousands)	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 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	313			421			—
Liabilities settled	(151		)	(166		)	(63		)
Revisions to estimates	—			300			63
Accretion expense	229			102			39
Balance, end of period	11,943			6,655			10,508
Less: Current portion	48			622			33
Long-term portion	$	11,895		$	6,033		$	10,475

NOTE 11 — DEBT

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~~its~~Index carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is less than its carrying amount, we are required to ~~perform~~Financial ~~a quantitative goodwill impairment test.~~ Statements

As a result of the Business Combination, we recognized goodwill in the Midstream segment during the Successor Period. There was no goodwill prior to the Business Combination. Based mainly on declines in the Company’s stock price and market capitalization during the quarter ended September 30, 2018, we elected to perform a quantitative assessment to determine if the $699.9 million of goodwill in the Midstream segment was impaired as of the end of the period. Our assessment included a calculation of the present value of estimated future discounted cash flows, a calculation of the value of the Midstream segment based on a market participant multiple applied to 2019 estimated earnings before interest, taxes, depreciation and amortization (EBITDA) and a calculation of the value of the Midstream segment based on estimated future discounted cash flows plus a market participant multiple applied to terminal EBITDA at the end of a five-year period. The cash flows used in the model were determined based on expected growth in production volumes of the Company’s Exploration & Production segment, much of which is dedicated to the Midstream segment’s gathering and processing facilities, the inclusion of earnings from the transfer of salt water disposal assets from the Exploration & Production segment to the Midstream segment that occurred in the fourth quarter of 2018 (See Note 22 — Subsequent Events for further information), earnings associated with the expected completion of the Cimarron Express Pipeline joint venture in mid-2019 and anticipated growth from third parties’ production dedicated to the Midstream segment’s gathering and processing facilities. Each scenario modeled indicated there was no impairment of goodwill as of September 30, 2018. The Company also analyzed the impact that changes in our assumptions would have on the estimated value of the Midstream segment by increasing and decreasing the discount rate, increasing and decreasing the exit EBITDA multiples and increasing and decreasing the terminal growth rate assumptions. No goodwill impairment was determined under any of the varying scenarios analyzed by the Company as of September 30, 2018. Each of our assumptions regarding earnings, cash flows and discount rates are based mainly on Level 3 unobservable inputs. Should the expected long-term growth in earnings and cash flows for the Midstream segment not occur due to adverse changes in commodity prices or market conditions or the inability of the Company to execute on its growth strategy, goodwill for the Midstream segment could become impaired in some future period.



(in thousands)	March 31, 2019		December 31, 2018
Alta Mesa RBL	$	278,000	$	161,000
KFM Credit Facility	183,000		174,000
2024 Notes	500,000		500,000
Unamortized premium on 2024 Notes	27,892		29,123
Total debt, net	988,892		864,123
Less: Current portion	988,892		690,123
Long-term debt, net	$	—	$	174,000

~~Intangible~~Alta ~~Assets~~Mesa (Successor). In connection with the acquisition of Kingfisher, the Company recorded the estimated fair value of acquired customer contracts and related customer relationships as intangible assets, which were valued using the income approach, and are presented as Intangible Assets, net in the accompanying consolidated balance sheet of the Successor. These intangible assets, all of which relate to the Midstream segment, have definite lives and are subject to amortization utilizing an accelerated attrition method over their economic lives. The weighted average remaining amortization period for our intangible assets at September 30, 2018 was 12 years. We assess intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If required, an impairment would be recognized in the consolidated statements of operations to reduce the carrying amount of an intangible asset to its fair value. No impairment was identified as of September 30, 2018.RBL

~~Asset~~In ~~Retirement~~April ~~Obligations. We~~2019, ~~recognize~~our ~~liabilities~~borrowing ~~for~~base under the ~~future~~Alta ~~costs~~Mesa ofRBL ~~dismantlement~~was ~~and~~reduced ~~abandonment~~from of$400.0 ~~our~~million ~~wells,~~to ~~facilities~~$370.0 million, ~~and~~leaving ~~other~~us ~~tangible~~with ~~long-lived~~no ~~assets~~meaningful ~~along~~remaining ~~with~~capacity anavailable ~~associated~~thereunder ~~increase~~at inthat ~~the~~time. ~~carrying~~In ~~amount~~August of2019, the ~~related~~Alta ~~long-lived~~Mesa ~~asset. The~~RBL ~~fair~~lenders ~~values~~exercised oftheir ~~new~~ability ~~asset~~to ~~retirement~~make ~~obligations~~an ~~are~~optional ~~estimated~~redetermination ~~using~~of ~~expected~~our ~~future~~borrowing ~~costs~~base ~~discounted~~ahead toof ~~present~~the ~~value. The~~regular ~~cost~~redetermination ofscheduled ~~the~~in ~~tangible~~October ~~asset~~2019, ~~including~~and ~~the~~via ~~asset~~this ~~retirement~~redetermination, ~~cost~~our borrowing base was reset to $200.0 million, iseffective ~~depleted~~August ~~over~~13, ~~the~~2019. As ~~useful~~our ~~life~~combined borrowings and letters of credit outstanding exceeded the ~~asset. Accretion~~new ~~expense~~borrowing isbase ~~recognized~~amount asby ~~the~~$162.4 ~~discounted~~million, ~~liability~~we ishad ~~accreted~~five months, beginning September 2019, to ~~its~~make ~~expected~~ratable ~~settlement~~monthly ~~value~~payments of $32. ~~Asset~~5 ~~retirement~~million ~~obligations~~to ~~are~~cause ~~subject~~utilization to ~~revision~~be ~~primarily~~less ~~for~~than ~~changes~~or ~~related~~equal to the ~~estimated~~borrowing ~~timing~~base. As ~~and~~indicated ~~cost~~in our discussion of ~~abandonment~~going concern, we and Alta Mesa filed for bankruptcy protection prior to making these payments.

~~Asset~~The ~~retirement~~Alta ~~obligations~~Mesa ~~for~~RBL ~~the~~has ~~Company’s~~two ~~midstream~~covenants ~~processing~~that ~~and pipeline facilities generally become firm at the time the facilities~~ are ~~permanently~~tested shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured due to the uncertainty associated with the future settlement dates of such obligations. As such, no obligation has been established for our midstream assets as of September 30, 2018. quarterly:

~~Bond~~• ~~Premium~~a onratio ~~Senior Unsecured Notes. In connection with the Business Combination, the Company estimated the fair value~~ of Alta Mesa’s ~~$500.0~~current ~~million senior~~assets ~~unsecured~~to ~~notes~~current atliabilities, ~~$533.6~~inclusive ~~million as~~ of ~~the~~specified ~~acquisition~~adjustments, ~~date. The amount in excess~~ of ~~the~~not ~~original~~less ~~principal~~than ~~balance~~1.0 ~~was recorded as a bond premium, which is being amortized as a reduction~~ to ~~interest expense~~1. 0; and

~~Derivative~~• ~~Financial~~a ~~Instruments. We~~ratio ~~use derivative contracts to economically hedge the effects~~ of ~~fluctuations~~Alta inMesa’s ~~the~~consolidated ~~prices~~debt ofto ~~oil,~~its ~~natural~~consolidated ~~gas~~Adjusted ~~and~~EBITDAX ~~natural gas liquids. We account for such derivative instruments in accordance with ASC 815, Derivatives and Hedging~~ (the “~~ASC~~leverage ~~815~~ratio”), ~~which~~of ~~establishes~~not ~~accounting~~greater ~~and~~than ~~disclosure~~4.0 ~~requirements for derivative instruments and requires them~~ to ~~be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 7 — Fair Value Measurements for information on fair value)~~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 Alta Mesa 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 award affiliate contracts. Our bankruptcy filing did not constitute an event of default under the KFM Credit Facility.

At March 31, 2019, remaining borrowing capacity under the KFM Credit Facility totaled $117.0 million, however, access to the remaining capacity requires covenant compliance on a pro forma basis for any new borrowings. As discussed above regarding our ability to continue as a going concern and as a result of our and Alta Mesa’s bankruptcy, our only remaining source of liquidity is through our subsidiaries, including KFM. Based on our cash flow needs to meet our financial obligations, we believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020.

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

~~Income~~2024 Taxes (Successor). Income taxes and uncertain tax positions are accounted for in accordance with ASC 740, Accounting for Income Taxes (“ASC 740”). Deferred income taxes are provided for the temporary differences between the bases of assets and liabilities for financial reporting and income tax purposes. We classify deferred tax assets and liabilities as noncurrent in our consolidated balance sheet as of September 30, 2018 in accordance with ASU No. 2015-17, Income Taxes (Topic 740), Balance Sheet Classification of Deferred Taxes.Notes

~~Tax~~We ~~positions~~have ~~meeting~~estimated the ~~more-likely-than-not~~fair ~~recognition~~value ~~threshold~~of ~~are~~the ~~measured~~2024 ~~pursuant~~Notes to ~~the~~be ~~guidance set forth in ASC 740~~$194.9 Wemillion ~~assess~~at ~~the~~March 31, ~~ability~~2019, towhich ~~realize~~is ~~our~~based ~~deferred tax assets~~ on atheir ~~quarterly~~most ~~basis.~~recent Atrading ~~valuation~~values, ~~allowance~~which is ~~established~~a toLevel ~~reduce~~1 ~~deferred tax assets to the amount expected to be realized when it is determined that it is more likely than not that some or all of the deferred tax assets are not realizable~~determination.

~~The~~Alta ~~Company~~Mesa’s isfiling ~~also~~of ~~subject to~~ the ~~Texas~~Bankruptcy ~~margin~~Petitions ~~tax,~~constituted ~~which~~an isevent ~~considered~~of adefault ~~state~~under ~~income~~the ~~tax,~~2024 ~~and~~Notes isthat ~~included~~accelerated inAlta ~~“Income~~Mesa’s ~~tax~~obligations ~~provision~~thereunder. Under ~~(benefit)”~~the onBankruptcy Code, the ~~consolidated~~holders ~~statements~~ of ~~operations.~~the ~~The~~2024 ~~Company~~Notes ~~records~~are ~~state~~stayed ~~income~~from ~~tax~~taking ~~(current~~any ~~and~~action ~~deferred)~~against ~~based~~Alta onMesa ~~taxable income,~~ as ~~defined~~a ~~under~~result ~~the~~of ~~rules~~an ~~for~~event ~~the~~of ~~margin tax~~default.

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

We have considered our exposure under the standard at both the federal and state tax levels. We did not record any liabilities for uncertain tax positions as of September 30, 2018 or December 31, 2017. We record income tax-related interest and penalties, if any, as a component of income tax expense. We did not incur any material interest or penalties on income taxes for the Successor Period.



Fiscal year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	461,000
Thereafter	500,000
	$	961,000

Based upon our going concern conclusions and the default associated with Alta Mesa’s ~~tax~~bankruptcy ~~returns~~filing, ~~for~~we believe that our indebtedness under the ~~years~~Alta ~~ended~~Mesa ~~December~~RBL and our 2024 Notes should be reported as current liabilities despite their scheduled maturities shown above. We have reported our Alta Mesa RBL debt and our 2024 Notes as current at March 31, ~~2014~~2019. We ~~and~~have ~~forward~~no ~~remain~~meaningful ~~open~~cash ~~for~~available ~~examination~~to us to meet our obligations apart from cash held by our subsidiaries. ~~None~~As a result of ~~the~~Alta ~~Company~~Mesa’s ~~federal~~bankruptcy orand ~~state~~the ~~tax~~limitations ~~returns~~imposed ~~are~~under ~~currently~~the ~~under~~cash ~~examination~~collateral agreement approved by the ~~relevant~~Bankruptcy ~~authorities~~Court, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.8 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. Accordingly, we have determined that it is appropriate to also report all of our Midstream debt as current at March 31, 2019.

~~Income Taxes (Predecessor).~~NOTE ~~Alta~~12 — ~~Mesa~~COMMITMENTS ~~historically~~AND ~~elected to be treated as an individual partnership for tax purposes~~ CONTINGENCIES

~~under~~There ~~the~~have ~~provisions~~been ofno ~~the~~material ~~Internal~~developments ~~Revenue~~during ~~Code~~the offirst ~~1986,~~quarter asof ~~amended. Accordingly,~~2019 ~~items~~in ofrelation ~~income,~~to ~~expense,~~our ~~gains~~commitments and ~~losses~~contingencies ofas ~~the~~compared ~~Predecessor~~to ~~flowed~~our ~~through~~discussion toof ~~the~~those ~~partners~~matters ~~and~~in ~~were~~our ~~taxed~~2018 at10-K. The ~~the~~commencement ~~partner~~of ~~level.~~the ~~Accordingly,~~Chapter no11 ~~tax~~proceedings ~~provision~~automatically ~~for~~stayed ~~federal~~certain ~~income~~actions ~~taxes~~against isthe ~~included~~Company, inincluding the ~~consolidated~~matters ~~financial~~discussed ~~statements~~in ofour ~~the~~2018 ~~Predecessor~~10-K.

~~Predecessor~~NOTE net income (loss) for financial statement purposes differed significantly from taxable income (loss) reported to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under Alta Mesa’s amended and restated partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes could not be readily determined as some tax basis differences are determined at the partner level and Alta Mesa did not have access to information about each unitholder’s tax attributes in Alta Mesa. However, with respect to Alta Mesa, the Predecessor’s book basis in its net assets exceeded Alta Mesa’s net tax basis by $333.2 million at December13 ~~31,~~— ~~2017.~~SIGNIFICANT CONCENTRATIONS

~~Revenue~~During ~~Recognition. We~~most ~~recognize~~of ~~oil~~the first quarter of 2019 and throughout 2018, ~~natural~~ARM Energy Management, LLC (“ARM”) marketed our oil, gas and ~~natural~~NGLs ~~gas~~for ~~liquids~~a ~~revenues~~marketing ~~when~~fee ~~products~~that is deducted from sales proceeds collected by ARM from purchasers. The sales are ~~delivered~~generally atmade aunder ~~fixed~~short-term orcontracts ~~determinable~~with ~~price~~month-to-month pricing based on published regional indices, ~~title~~adjusted ~~has~~for ~~transferred~~transportation, location and ~~collectability~~quality. In isMarch ~~reasonably~~2019, ~~assured.~~in Wepreparation ~~use~~for handling oil and NGL marketing responsibilities internally, we began receiving payments for the ~~sales~~sale ~~method~~of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. As of ~~accounting~~June ~~for~~1, ~~recognition~~2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of ~~natural~~our gas ~~imbalances~~marketing agreement with ARM through November 30, 2019.

~~Gathering~~ARM ~~and~~also ~~processing~~provides ~~revenues~~us ~~are~~with ~~generated~~strategic byadvice, ~~charging~~execution ~~fees on a per unit basis for gathering crude oil~~ and ~~natural~~reporting ~~gas and processing natural gas. The Company recognizes revenue when~~ services ~~have~~with ~~been~~respect ~~rendered,~~to ~~the~~our ~~prices~~derivatives ~~are fixed or determinable and collectability is reasonably assured~~activities. In ~~addition, revenue from sales of crude oil, natural gas and natural gas~~

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~~liquids~~Index ~~is recognized when title passes~~ to ~~the~~Financial ~~customer, which is when risk of ownership passes to the customer and physical delivery occurs, the price of the product is fixed or determinable and collectability is reasonably assured.~~Statements

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



	Successor				Predecessor
(in thousands)	Three Months Ended March 31, 2019		February 9, 2018 Through March 31, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	93,391	$	41,216	$	28,757

Marketing and management fees paid to ARM	$	697	$	—	$	—
Fees paid to ARM for services relating to our derivatives	193		74		66
Total fees paid to ARM	$	890	$	74	$	66

~~Fair~~Receivables ~~Value~~from ofARM ~~Financial~~for ~~Instruments. The~~sales ~~fair~~on ~~values~~our ofbehalf ~~cash,~~were ~~accounts~~$13.0 ~~receivable~~million and ~~current liabilities approximate book value due to their short-term nature~~$43.8 ~~The~~million ~~fair~~as ~~value~~ of ~~long-term~~March 31, ~~debt~~2019 ~~under the Alta Mesa~~ and ~~Kingfisher~~December 31, ~~senior~~2018, ~~secured~~respectively, ~~revolving~~which credit facilities is not considered to be materially different from carrying value due to short-term variable market rates of interest applicable to outstanding borrowings under each facility. Derivative financial instruments are ~~carried~~reflected atin ~~fair~~accounts ~~value.~~receivable ~~For further information~~ on ~~fair~~our ~~values~~balance ~~of financial instruments see Note 7 — Fair Value Measurements and Note 12 — Long-Term Debt, Net~~sheets.

~~Earnings~~We ~~(Loss)~~believe ~~Per~~that ~~Share. Basic~~the ~~earnings (~~loss) ~~per~~of ~~share~~any isof ~~calculated~~our bycustomers, ~~dividing~~or ~~earnings~~of ~~(loss)~~our ~~available~~marketing toagent ~~common~~ARM, ~~stockholders~~would bynot ~~the~~have ~~weighted~~a ~~average~~material ~~number~~adverse ofeffect ~~shares~~on ~~outstanding~~us ~~during~~because ~~each~~alternative ~~period~~purchasers are readily available.

~~The~~NOTE ~~Company~~14 ~~uses~~— ~~the “if~~EQUITY-~~converted”~~BASED ~~method~~COMPENSATION to determine the potential dilutive effect of exchanges of outstanding SRII Opco Common Units and corresponding shares of its outstanding Class C Common Stock, and the treasury stock method to determine the potential dilutive effect of its outstanding warrants, restricted stock, restricted stock units and stock options.(Successor)

~~The~~Stock ~~following~~compensation ~~table~~expense ~~reflects~~recognized ~~the~~was ~~net~~as ~~income attributable to common stockholders and the earnings per share for the periods indicated based on a weighted average number of common shares outstanding for each period~~follows:

໿



	Successor				Predecessor
(in thousands)	Three Months Ended March 31, 2019		February 9, 2018 Through March 31, 2018		January 1, 2018 Through February 8, 2018
Stock options	$	1,239	$	1,065	$	—
Restricted stock awards	1,433		1,233		—
Performance-based restricted stock units	7		1,168		—
Total compensation expense	$	2,679	$	3,466	$	—

	Successor
	Three Months Ended September 30, 2018		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	$	7,135	$	(12,544	)
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	$	12,004	$	(17,771	)
Weighted average Class A common shares outstanding (Basic)	178,078,132		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)	310,537,832		233,371,618
Earnings (loss) per common share attributable to AMR common stockholders:
Basic	$	0.04	$	(0.07	)
Diluted	$	0.04	$	(0.08	)

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

~~For~~The ~~the~~performance ~~three~~targets ~~months~~for ~~ended~~the ~~September 30,~~2019 ~~2018~~tranche ~~(Successor),~~were ~~approximately~~established ~~63.0~~in ~~million~~March ~~warrants~~2019 and ~~6.6 million equity awards~~572,990 ~~consisting~~PSUs ofwere ~~stock~~deemed ~~options,~~granted ~~restricted~~at ~~stock~~that ~~and~~time. The ~~restricted~~fair ~~stock~~value ~~units,~~of ~~were excluded from~~ the ~~calculation~~2019 oftranche ~~diluted~~granted ~~earnings~~was $0.27 per ~~share~~unit, aswhich ~~their~~will ~~effect~~be ~~would~~recognized ~~have~~as ~~been~~expense ~~anti-dilutive. During~~over the ~~Successor~~remainder ~~Period~~of 2019, ~~approximately~~subject ~~63.0~~to ~~million~~continued ~~warrants and 6~~employment.0

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 15 — 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 $36,000 and $28,000 for the period February 9, 2018 through March 31, 2018 and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses.

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~~million~~Index ~~equity~~to ~~awards,~~Financial ~~consisting of stock options, restricted stock and restricted stock units, were excluded from the calculation of diluted earnings per share as their effect would have been anti-dilutive.~~ Statements

~~During~~David ~~the Successor Period~~McClure, ~~the~~AMR’s ~~limited~~former ~~partners~~Vice President of ~~SRII~~Facilities ~~Opco~~and ~~became~~Infrastructure, ~~eligible~~and tothe ~~exchange their Common Units~~ son-in-law ~~SRII Opco and their related shares~~ of ~~Class~~our Cformer ~~common~~President ~~stock~~and ~~for~~Chief ~~Class~~Executive AOfficer, ~~common~~Harlan ~~shares~~H. ofChappelle, ~~the~~received ~~Company. A~~ total ofcompensation 29of $768,~~411~~860,~~236 Common Units became eligible for exchange on May 10~~ $970, ~~2018~~ 197 and $28,874 during the 2019 ~~remaining 175~~Quarter,~~510,652~~ ~~became~~the ~~eligible~~period ~~for~~February ~~exchange on August 8~~9, 2018~~. Under~~ ~~the~~through ~~if-converted~~March ~~method~~31, ~~the~~2018 ~~weighted~~and ~~average~~the ~~number~~Predecessor ofPeriod, ~~Class~~respectively. AThese ~~common~~amounts ~~shares~~are ~~that became eligible for issuance upon conversion of the Common Units have been~~ included in ~~the~~general ~~calculation~~and ofadministrative ~~diluted~~expense. ~~earnings per share~~Mr. At ~~September~~McClure ~~30,~~separated ~~2018,~~from ~~all 204,921,888 outstanding Common Units of SRII Opco and~~ the ~~related~~Company ~~shares~~in ofFebruary ~~Class C common stock were eligible for exchange into our Class A common shares~~2019. ~~Had such shares been exchanged, our total Class A common shares outstanding at September 30, 2018 would have been 380,879,071.~~

~~Comprehensive~~David ~~Income.~~Pepper, ~~During~~Surface ~~the~~Land ~~Successor~~Manager ~~Periods~~for KFM, and the ~~Predecessor~~cousin ~~Periods,~~of ~~the~~our ~~Company~~Vice ~~had~~President noof ~~components~~Land ofand ~~other~~Business ~~comprehensive~~Development, ~~income. Accordingly~~David Murrell, received total ~~comprehensive~~compensation ~~income~~of ~~for~~$70,180, ~~each~~$112,761 ~~period~~and ~~was~~$67,322 ~~equal~~during to the ~~amount~~2019 ofQuarter, ~~net~~the ~~income~~period ~~(loss)~~February ~~for~~9, ~~those~~2018 ~~same~~through ~~periods~~March as31, ~~reflected~~2018 inand the ~~accompanying~~Predecessor ~~consolidated~~Period, ~~statements~~respectively. ofThese ~~operations~~amounts are included in general and administrative expense.

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

AtIn 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 ~~date~~“JDA”), with BCE, a fund advised by Bayou City, to fund a portion of ~~the~~our ~~issuance~~drilling operations and to allow us to accelerate development of ~~these~~our ~~consolidated~~STACK ~~financial~~acreage. The ~~statements~~JDA established a development plan of 60 wells in three tranches, ~~management~~and ~~considers~~provides opportunities for an additional 20 wells. Pursuant to the ~~Company~~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 ~~going~~15% ~~concern~~internal rate of return on the wells within a tranche and ~~has~~automatically ~~prepared~~further ~~these~~reduced ~~consolidated~~to ~~financial~~12.5% ~~statements~~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 ~~going~~number ~~concern~~of ~~basis~~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 March 31, 2019, 61 joint wells have been drilled or spudded. At March 31, 2019 and December 31, 2018, $4.5 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 March 31, 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.

Recent Accounting Pronouncements Issued But Not Yet Adopted. 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 consolidated statement of cash flows in the same line as payments made for fees associated with the hosting element. The Company is required to adopt this new standard for fiscal years beginning after December 15, 2019, although early adoption is permitted. The Company is currently evaluating the impact of this new standard on its consolidated financial position and results of operations and has not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

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

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

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

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~~retrospective~~Index ~~adoption, meaning the standard is applied only~~ to ~~the~~Financial ~~most current period presented. We expect to adopt ASU 2014-09 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.~~ Statements

WeNOTE ~~are~~16 ~~continuing~~— ~~our~~BUSINESS ~~review~~SEGMENT of contracts for each of our revenue streams and evaluating the impact on our consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09, as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our revenues and expenses under the new gross-versus-net presentation guidance and on our current accounting policies, including the need to make changes to relevant accounting policies and internal controls, if needed. Based on assessments performed to date, we do not expect ASU 2014-09 to have an effect on the timing of revenue recognition or our financial position. In addition, we currently expect the impact regarding gross-versus-net presentation to involve certain presentation changes specifically related to natural gas processing revenues and expenses; however, the impact of such presentation changes will not impact our consolidated operating income, net income or cash flows.INFORMATION

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



	Three Months Ended March 31, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	86,363		$	—		$	—		$	86,363
Natural gas	18,450			—			—			18,450
Natural gas liquids	11,216			—			—			11,216
Sales of gathered production	—			9,560			—			9,560
Midstream revenue	—			22,376			(15,221		)	7,155
Segment sales revenue	116,029			31,936			(15,221		)	132,744
Other revenue	568			7,681			(5,164		)	3,085
Operating revenue	116,597			39,617			(20,385		)	135,829
Gain on sale of assets	1,483			—			—			1,483
Gain (loss) on derivatives	(23,777		)	—			—			(23,777		)
Total revenue	94,303			39,617			(20,385		)	113,535
Operating expenses
Lease operating	25,108			—			(5,164		)	19,944
Transportation, processing and marketing	17,761			2,063			(15,221		)	4,603
Midstream operating	—			6,151			—			6,151
Cost of sales for purchased gathered production	—			9,695			—			9,695
Production taxes	5,483			—			—			5,483
Workovers	197			116			—			313
Exploration	2,054			—			—			2,054
Depreciation, depletion, and amortization	34,675			3,224			—			37,899
General and administrative	20,947			8,063			508			29,518
Total operating expenses	106,225			29,312			(19,877		)	115,660
Operating income	(11,922		)	10,305			(508		)	(2,125		)
Other income (expense)
Interest expense	(12,830		)	(2,630		)	—			(15,460		)
Interest income	27			4			20			51
Equity in earnings of unconsolidated subsidiaries	—			99			—			99
Total other income (expense), net	(12,803		)	(2,527		)	20			(15,310		)
Income (loss) from continuing operations before income taxes	(24,725		)	7,778			(488		)	(17,435		)

Interest expense	12,830			2,630			—			15,460
Depreciation, depletion and amortization	34,675			3,224			—			37,899
Exploration	2,054			—			—			2,054
Loss on unrealized hedges	24,142			—			—			24,142
Equity-based compensation	1,661			1,018			—			2,679
Severance costs	3,975			1,896			—			5,871
Adjusted EBITDAX	$	54,612		$	16,546		$	(488	)	$	70,670

Equity method investment at period end	$	—		$	1,199		$	—		$	1,199
Capital expenditures	133,077			28,271			—			161,348
Total assets at period end	949,391			446,370			(12,450		)	1,383,311

The standard provides several optional practical expedients in transition. We expect to elect the “package of practical expedients”, which permits us to forgo reassessment of our prior conclusions about lease identification, lease classification and initial direct costs for leases entered into prior to the effective date. We also expect to elect the land easement relief which permits us to forgo reassessment of existing or expired land easements not previously accounted for under ASC 840. Additionally, we expect to elect the practical expedient to not provide comparative reporting periods and therefore financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. We do not expect to elect the use-of-hindsight practical expedient.

At this time, we are evaluating the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and implementation of ASU 2016-02 is expected to have an impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months. The adoption may also result in a change in the amount of lease expense recorded on our consolidated statements of operations, as well as add additional disclosures. We expect our implementation work team will complete its evaluation of this new standard by the end of 2018.

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

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

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

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~~NOTE~~Index 3to —Financial ~~SUPPLEMENTAL CASH FLOW INFORMATION~~Statements

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



	February 9, 2018 Through March 31, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations			Total
Revenue
Oil	$	40,278		$	—		$	—		$	40,278
Natural gas	5,210			—			—			5,210
Natural gas liquids	4,714			—			—			4,714
Sales of gathered production	—			10,610			(6,737		)	3,873
Midstream revenue	—			7,822			(4,562		)	3,260
Segment sales revenue	50,202			18,432			(11,299		)	57,335
Other revenue	555			—			—			555
Operating revenue	50,757			18,432			(11,299		)	57,890
Gain on sale of assets	5,139			—			—			5,139
Gain (loss) on derivatives	(22,011		)	—			—			(22,011		)
Total revenue	33,885			18,432			(11,299		)	41,018
Operating expenses
Lease operating	8,317			—			—			8,317
Transportation, processing and marketing	5,583			2,338			(4,562		)	3,359
Midstream operating	—			587			—			587
Cost of sales for purchased gathered production	—			10,546			(6,737		)	3,809
Production taxes	1,415			—			—			1,415
Workovers	1,245			—			—			1,245
Exploration	1,585			—			—			1,585
Depreciation, depletion, and amortization	11,038			4,641			—			15,679
General and administrative	34,654			2,173			925			37,752
Total operating expenses	63,837			20,285			(10,374		)	73,748
Operating income	(29,952		)	(1,853		)	(925		)	(32,730		)
Other income (expense)
Interest expense	(5,196		)	(248		)	—			(5,444		)
Interest income	546			—			—			546
Total other income (expense), net	(4,650		)	(248		)	—			(4,898		)
Income (loss) from continuing operations before income taxes	(34,602		)	(2,101		)	(925		)	(37,628		)

Interest expense	5,196			248			—			5,444
Depreciation, depletion and amortization	11,038			4,641			—			15,679
Exploration	1,585			—			—			1,585
Loss on unrealized hedges	18,036			—			—			18,036
Equity-based compensation	2,771			42			656			3,469
Business Combination related expense	23,717			—			—			23,717
Adjusted EBITDAX	$	27,741		$	2,830		$	(269	)	$	30,302

Capital expenditures	$	129,310		$	3,745		$	—		$	133,055
Total assets at period end	2,828,349			1,415,496			(275		)	4,243,570

໿

	Successor			Predecessor
	February 9, 2018			January 1, 2018		Nine
	Through			Through		Months Ended
	September 30, 2018			February 8, 2018		September 30, 2017
Supplemental cash flow information:
Cash paid for interest	$	24,950		$	1,145	$	25,675
Cash paid for income taxes	1,573			—		—
Non-cash investing and financing activities:
Increase in asset retirement obligations	4,652			—		3,778
Asset retirement obligations assumed, purchased properties	—			—		705
Increase in accruals or payables for capital expenditures	41,069			4,712		41,322
Distribution of non-STACK (assets) net liability	—			33,102		—
Equity issued in Business Combination	2,067,393			—		—
Release of Common stock from possible redemption	966,384			—		—
Exchange of Class B common stock to Class A	3			—		—
Tax effect of redemption of noncontrolling interests in SRII Opco for Class A common shares and other	(905		)	—		—
Increase in accounts receivable for sale of assets	(524		)	—		—

NOTE 4 — BUSINESS COMBINATION

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

Pursuant to the Contribution Agreements, SRII Opco acquired (a) (i) all of the limited partner interests in Alta Mesa and (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa GP, ((i) and (ii) collectively, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The acquisition of Alta Mesa and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “Business Combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.” SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco, is a wholly owned subsidiary of AMR. As a result of the Business Combination, our only significant asset is our ownership of an approximate 46.2% partnership interest in SRII Opco. SRII Opco owns all of the economic interests in each of Alta Mesa and Kingfisher.

At the closing of the Business Combination:

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

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

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•Index ~~the Company caused SRII Opco~~ to ~~issue~~Financial 213,402,398 SRII Opco Common Units (approximately 55.8%) to the Contributors in exchange for the ownership interests in Alta Mesa, Alta Mesa GP and Kingfisher that were contributed to SRII Opco by the Contributors;Statements

•Item 2. ~~the~~Management’s ~~Company~~Discussion ~~agreed~~and toAnalysis ~~cause~~of ~~SRII~~Financial ~~Opco~~Condition ~~to issue up to 59,871,031 SRII Opco Common Units to the AM Contributor~~ and ~~the~~Results ~~KFM Contributor if the earn-out consideration provided for in the Contribution Agreements is earned by the AM Contributor or the KFM Contributor pursuant to the terms~~ of ~~the Contribution Agreements;~~Operations

•The following discussion and analysis should be read in conjunction with the ~~Company~~condensed ~~issued~~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 ~~each~~such differences include, but are not limited to, the impact of the ~~Contributors~~Chapter a11 ~~number~~proceedings on our business, the volatility of ~~shares~~oil and gas prices, production timing and volumes, our ability to continue as a going concern, estimates of ~~Class~~proved Creserves, ~~common~~operating ~~stock~~costs and capital expenditures, ~~par~~economic ~~value~~and ~~$0.0001~~competitive ~~per~~conditions, ~~share~~regulatory ~~(the~~changes and other uncertainties, as well as those factors discussed in “~~Class~~Cautionary CStatement ~~Common~~Regarding ~~Stock~~Forward-Looking Statements”), ~~equal~~at to the ~~number~~beginning of this Quarterly Report and in the ~~SRII~~sections ~~Opco~~titled ~~Common~~“Risk ~~Units~~Factors” ~~received~~in bythis ~~each~~Quarterly ~~such~~Report ~~Contributor~~and atin our 2018 10-K, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the ~~closing;~~forward-looking events discussed may not occur.

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

•We ~~SRII~~are ~~Opco~~an ~~entered~~independent ~~into~~exploration anand ~~amended~~production company focused on the acquisition, development, exploration and ~~restated~~exploitation ~~voting~~of ~~agreement~~unconventional ~~with~~onshore oil and natural gas reserves in the ~~owners~~eastern portion of the ~~remaining~~Anadarko ~~10%~~Basin ~~voting~~in ~~interests~~Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa GPconducts ~~whereby~~our ~~such~~Upstream ~~other~~activities ~~owners~~and ~~agreed~~owns toour ~~vote~~proved ~~their~~and ~~interests~~unproved oil and gas properties located in ~~Alta~~an ~~Mesa~~area GPof the Anadarko Basin commonly referred to as ~~directed~~the STACK. We generate upstream revenue principally by ~~SRII~~the ~~Opco~~production and sale of oil, gas and NGLs. We also operate in the Midstream segment through KFM. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The KFM assets are integral to our Upstream operations, which we conduct in the same region, and they are strategically positioned to provide similar services to other producers in the area.

~~Holders~~As of ~~AMR’s Class~~March C31, ~~Common Stock~~2019, ~~together~~we ~~with~~have ~~holders~~a ofhighly ~~Class A~~contiguous ~~Common~~position ~~Stock~~of approximately 137,000 ~~voting~~net asacres ain ~~single~~the ~~class~~up-dip, ~~have~~naturally-fractured oil portion of the ~~right~~STACK toprimarily ~~vote~~in oneastern ~~all~~Kingfisher ~~matters~~and ~~properly~~southeastern ~~submitted~~Major tocounties ain ~~vote~~Oklahoma. ofOur drilling locations primarily target the ~~stockholders~~Osage, ~~but~~Meramec ~~holders~~and Oswego formations. After the Business Combination, we conducted development activities using a spacing array of ~~Class C~~6 ~~Common~~to ~~Stock~~10 ~~are~~wells ~~not~~per ~~entitled~~section and running up to ~~any~~9 ~~dividends~~rigs orat ~~liquidating~~the ~~distributions~~peak ~~from~~activity uslevel. ~~After~~In alate ~~specified~~2018, ~~period~~our ofproduction ~~time~~across ~~following~~the ~~Closing,~~acreage evidenced that the ~~Contributors~~well ~~will~~spacing ~~generally~~was ~~have~~not delivering the ~~right~~well tolevel ~~cause~~production ~~SRII~~that ~~Opco~~we toexpected. ~~redeem~~During ~~all~~January or2019, awe ~~portion~~suspended ofour ~~their~~development ~~SRII~~program ~~Opco~~to ~~Common~~allow ~~Units~~our innew ~~exchange~~management ~~for~~team ~~shares~~to ofconduct a full operational and economic review. We restarted our ~~Class A~~development ~~Common~~program ~~Stock~~in ~~or,~~March at2019 ~~SRII~~with ~~Opco’s~~a ~~option,~~less andense ~~equivalent~~spacing ~~amount~~pattern of ~~cash~~up to five wells per section. ~~However~~In addition, we ~~may,~~have atworked to improve our ~~option~~economic returns by reducing well costs, ~~effect~~general aand ~~direct~~administrative ~~exchange~~expense ofand ~~cash~~other oroperating ~~Class A~~expense. We ~~Common~~have ~~Stock~~operated ~~for~~2 ~~such~~rigs ~~SRII~~since ~~Opco~~restarting ~~Common~~the ~~Units~~program, inhowever, ~~lieu~~because of ~~such~~our abankruptcy ~~redemption~~filing byin ~~SRII~~September ~~Opco.~~2019, ~~Upon~~we ~~the~~expect ~~future~~to ~~redemption~~cease orall ~~exchange~~development ofactivities, ~~SRII~~other ~~Opco~~than ~~Common~~any ~~Units~~that ~~held~~may be approved by athe ~~Contributor~~Court, aas ~~corresponding~~early ~~number~~as ofOctober ~~shares~~2019, ofuntil ~~Class C~~our ~~Common~~bankruptcy ~~Stock~~can ~~will~~ be ~~canceled~~resolved.

~~During the second quarter of 2018, equity owners of the KFM Contributor elected to redeem 9,588,764 of its SRII Opco Common Units for an equal number of shares of Class A Common Stock.~~ We ~~elected~~anticipate tothat ~~complete~~bankruptcy ~~this~~proceedings ~~redemption~~involving ~~through~~us aand ~~direct~~Alta ~~exchange,~~Mesa ~~whereby~~may ~~the~~reduce ~~9,588,764~~development ~~SRII~~by ~~Opco~~Alta ~~Common~~Mesa ~~Units~~that ~~are~~could ~~now~~result ~~owned~~in byless ~~us,~~gathering ~~and~~volumes wefor ~~issued 9~~KFM,~~588,764~~ ~~shares~~which ofwill ~~our~~adversely ~~Class~~impact ~~A Common Stock to equity owners of the~~ KFM’s ~~Contributor and canceled 9~~revenue,~~588,764~~ ~~shares~~EBITDA ofand ~~our~~operating ~~Class~~cash Cflows. ~~Common~~During ~~Stock. Additionally~~bankruptcy, aswe ~~described~~will ~~further~~be independent ~~Note~~on 16liquidity ~~— Stockholders’~~provided ~~Equity~~by ~~and~~our ~~Partners’~~solvent ~~Capital~~subsidiaries, ~~during~~including ~~the third quarter of 2018~~KFM, weto ~~sold~~meet ~~3,101,510 of~~ our ~~Common~~financial ~~Units~~obligations, inwith ~~SRII~~such ~~Opco~~availability tosubject ~~SRII Opco~~ to ~~fund~~approval ~~purchases~~by ofKFM’s anBoard ~~equivalent number~~ of ~~our~~Directors ~~Class~~and Acontinued ~~common~~compliance ~~shares. As~~under ~~a result of these transactions, at September 30, 2018, we own 46.2% of~~ the ~~limited~~KFM ~~partner~~Credit ~~interests in SRII Opco~~Facility.

Pursuant to the AMBusiness ~~Contribution~~Combination, ~~Agreement~~we ~~and~~recorded the ~~KFM~~acquired ~~Contribution~~assets ~~Agreement,~~and ~~for~~liabilities aat ~~period~~their ofestimated ~~seven~~fair ~~years~~values ~~following~~on the closing, ~~the~~date. This AMresulted ~~Contributor~~in ~~and~~our ~~the~~financial ~~KFM~~presentation ~~Contributor~~being ~~may~~separated beinto ~~entitled~~two todistinct ~~receive~~periods, ~~additional~~the ~~SRII~~period ~~Opco~~before ~~Common~~the ~~Units~~Business Combination (~~and~~“Predecessor ~~acquire~~Period”) aand ~~corresponding~~the ~~number~~period ofafter ~~shares~~the ofBusiness ~~AMR’s~~Combination ~~Class C~~(“Successor ~~Common Stock~~Period”). asThe ~~earn-out~~Company’s ~~consideration~~financial ifpresentation ~~the~~reflects ~~20-day~~Alta ~~volume-weighted~~Mesa ~~average~~as ~~price~~the (“~~20-Day VWAP~~Predecessor”) offor ~~our~~the ~~Class~~period January A1, ~~Common~~2018 ~~Stock~~to ~~equals~~February 8, or2018. ~~exceeds~~The Company, including the ~~following~~consolidated ~~prices~~results ~~(each~~of ~~such~~Alta ~~payment~~Mesa and KFM, anis ~~“Earn-Out~~the ~~Payment~~“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 March 31, 2019, in comparison to (i) the results of our Upstream and Midstream segments for the period February 9, 2018 through March 31, 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.

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

໿

Neither the AM Contributor nor the KFM Contributor will be entitled to receive a particular Earn-Out Payment on more than one occasion and, if on a particular date, the 20-Day VWAP entitles the AM Contributor or the KFM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor and/or the KFM Contributor will each be entitled to receive each such Earn-Out Payment. The AM Contributor and the KFM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of our assets, if the consideration paid to holders of Class A Common Stock in connection with such a liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.

We also contributed $560 million in net cash to Alta Mesa at the closing. Our source for these funds was from the sale of our securities to investors in a public offering and in private placements. Alta Mesa used a portion of the amount to repay its outstanding balance under its Alta Mesa Credit Facility described in Note 12 — Long-Term Debt, Net.

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

~~The~~We ~~Business~~distributed ~~Combination~~our ~~has~~non-STACK ~~been~~oil ~~accounted for using the acquisition method. The acquisition method of accounting is based on FASB ASC 805, Business Combination (“ASC 805”),~~ and ~~uses~~gas ~~the fair value concepts defined in FASB ASC 820, Fair Value Measurements (“ASC 820”). ASC 805 requires, among other things, that our~~ assets ~~acquired~~ and liabilities ~~assumed be recognized at their fair values as of the acquisition date by the Company. We have not completed the detailed valuation studies necessary~~ to ~~arrive~~High atMesa ~~the~~in ~~final~~connection ~~determination~~with of the ~~fair~~closing ~~value~~ of the ~~assets acquired, the liabilities assumed and the related allocations of the purchase price in the~~ Business Combination. AsWe areport ~~result,~~ the ~~values~~non-STACK ofoil ~~certain~~and ofgas ~~our long-term~~ assets and liabilities ~~are preliminary in nature and are subject to change~~ as ~~additional~~discontinued ~~information~~operations ~~becomes~~during ~~available and as additional analysis is performed. Pursuant to ASC 805, finalization of~~ the ~~values~~Predecessor ~~is to be completed within one year of the acquisition date~~Period.

~~Preliminary~~Outlook, ~~Estimated~~Market ~~Purchase~~Conditions ~~Price~~and ~~for~~Commodity ~~Alta Mesa~~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 ~~preliminary~~success ~~estimated~~of ~~purchase~~our ~~price~~business ~~consideration~~is ~~for~~significantly ~~Alta~~affected ~~Mesa~~by ~~was~~the asprice ~~follows~~of (oil due to its weighting in ~~thousands):~~our production profile.

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

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

~~(1)~~During ~~The~~2019, ~~measurement~~our ~~period~~board ~~adjustment relates to the issuance~~ of ~~1,197,934~~directors ofhas ~~additional~~established ~~SRII Opco Common Units, valued at approximately $7.90 per unit, to~~ the AMfollowing ~~Contributor~~operating ~~based~~measures onas akey ~~final~~performance ~~closing~~indicators ~~statement~~for ~~agreed~~executive tomanagement bycompensation ~~the~~and ~~parties during~~ the ~~three~~Company ~~months~~as ~~ended~~a ~~June 30, 2018 (Successor).~~whole:

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

~~(3)~~• AtGeneral ~~closing, the Riverstone Contributor received consideration of 20,000,000 SRII Opco Common Units~~ and ~~the~~administrative AMcosts ~~Contributor~~(excluding ~~received~~strategic consideration of 138,402,398 SRII Opco Common Units. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity.costs);

~~(4)~~• ~~For~~Lease aoperating period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of Class C Common Stock) if the 20-day VWAP of our Class A Common Stock equals or exceeds the specified prices pursuant to the AM Contribution Agreement. Pursuant to ASC 805 and ASC 480, Distinguishing Liabilities from Equity (“ASC 480”), we have determined that the fair value of the earn-out consideration was approximately $284.1 million, which was classified as equity. The fair value of the contingent equity earn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to the Company (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining contractual term of the contingent liability earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.expense;

~~(5)~~• ~~Settlement~~Well ofdrilling ~~preexisting~~and ~~working~~completion ~~capital~~costs; ~~balances between Alta Mesa~~ and ~~Kingfisher.~~


•	Adjusted EBITDA or EBITDAX.

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

Going concern

We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration a number of factors that were previously disclosed in our 2018 10-K. Most significantly, we have seen significant reductions to our borrowing base under the Alta Mesa RBL in 2019. On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced by $30 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $62.3 million.

If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Debtors filed Bankruptcy Petitions for reorganization under the Bankruptcy Code in Bankruptcy Court. The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re

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~~Preliminary~~Index ~~Estimated~~to ~~Purchase~~Financial ~~Price Allocation for Alta Mesa~~Statements

~~The~~Alta ~~allocation~~Mesa ofResources, ~~the~~Inc., ~~preliminary~~et. ~~estimate~~al., ofCase ~~the~~No. ~~purchase~~19-35133. ~~consideration~~The Debtors will continue to operate their businesses as “debtors-in-possession” under the ~~assets~~jurisdiction ~~acquired~~of ~~and~~the ~~liabilities~~Bankruptcy ~~assumed~~Court and in accordance with the ~~acquisition~~applicable provisions of ~~Alta~~the ~~Mesa~~Bankruptcy ~~was~~Code asand ~~follows~~orders ~~(in~~of ~~thousands):~~the Bankruptcy Court.

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

	February 9, 2018 (As initially reported)		Measurement Period Adjustment (1)			February 9, 2018 (As adjusted)
Estimated Fair Value of Assets Acquired (2)
Cash, cash equivalents and short term restricted cash	$	10,345	$	—		$	10,345
Accounts receivable	101,745		—			101,745
Other receivables	1,222		—			1,222
Receivables due from related party	907		—			907
Prepaid expenses and other current assets	1,405		—			1,405
Derivative financial instruments	352		—			352
Property and equipment: (3)
Oil and natural gas properties, successful efforts	2,314,858		(1,479		)	2,313,379
Other property and equipment, net	43,318		—			43,318
Notes receivable due from related party	12,454		—			12,454
Deposits and other long-term assets	10,286		—			10,286
Total fair value of assets acquired	2,496,892		(1,479		)	2,495,413
Estimated Fair Value of Liabilities Assumed (2)
Accounts payable and accrued liabilities	210,867		(10,946		)	199,921
Advances from non-operators	6,803		—			6,803
Advances from related party	47,506		—			47,506
Asset retirement obligations (3)	5,998		—			5,998
Derivative financial instruments	11,585		—			11,585
Long-term debt (4)	667,700		—			667,700
Other long-term liabilities	5,066		—			5,066
Total fair value of liabilities assumed	955,525		(10,946		)	944,579
Total consideration and fair value	$	1,541,367	$	9,467		$	1,550,834

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

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

~~(1)~~Because ~~The~~of ~~measurement~~the ~~period~~default ~~adjustments~~under ~~are~~the ~~recognized~~Alta inMesa RBL and 2024 Notes arising from our bankruptcy filing, we have reported all of our Upstream debt as current. We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the ~~reporting~~limitations ~~period~~imposed inunder ~~which~~the cash collateral agreement approved by the ~~adjustments~~Bankruptcy ~~were~~Court, ~~determined~~our only remaining source of liquidity is through KFM and ~~calculated~~SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.8 million, as ifwell as remaining borrowing capacity of $74.0 million. Access to the ~~accounting~~remaining ~~had~~capacity ~~been~~under ~~completed~~the atKFM Credit Facility requires covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the ~~acquisition~~maintenance ~~date~~covenants as early as the first quarter of 2020. Accordingly, we have determined that it is appropriate to also report all of our Midstream debt as current at March 31, 2019. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.

~~(2)~~Delisting ~~The~~from ~~assets~~Stock ~~acquired and liabilities assumed relate to Alta Mesa’s STACK assets.~~Exchange

~~(3)~~As ~~The~~a ~~estimated~~result ~~fair values~~ of ~~oil~~our ~~and~~failure ~~natural~~to ~~gas~~comply ~~properties~~with ~~and~~the ~~asset~~NASDAQ ~~retirement~~continued ~~obligations~~listing ~~were~~requirements, ~~determined~~trading ~~using~~of ~~valuation~~our ~~techniques~~common ~~that~~stock ~~convert~~and ~~future~~warrants ~~cash~~will ~~flows~~be tosuspended aat ~~single discounted amount and involve~~ the ~~use~~opening of ~~certain~~business ~~inputs~~on ~~that~~September ~~are not observable in the market (Level 3 inputs). Significant inputs include~~24, ~~but~~2019 ~~are not limited to recoverable reserves, production rates, future operating~~ and ~~development~~will ~~costs,~~be ~~future~~removed ~~commodity~~from ~~prices,~~listing ~~appropriate risk-adjusted discount rates,~~ and ~~other~~registration ~~relevant~~on ~~data~~NASDAQ. The ~~These~~Company ~~inputs~~expects ~~required~~the ~~significant~~common ~~judgments~~stock and ~~estimates~~warrants byto ~~management~~be attraded over the ~~time~~counter ofunder the ~~valuation.~~trading ~~Actual~~symbols ~~results~~“AMRQ” ~~may~~and ~~vary~~“AMRWWQ”, ~~from these estimates~~respectively.

(4) Represents the approximate fair value as of the acquisition date of Alta Mesa’s $500.0 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million, based on Level 1 inputs, and outstanding borrowings under the Alta Mesa Credit Facility (described in Note 12 — Long Term Debt, Net) of approximately $134.1 million as of the acquisition date.Derivatives

The objective of our hedging program is to produce, over time, relative revenue stability. However, in the short-term, both settlements and fair value changes in our derivatives can significantly impact our results of operations, and we expect these gains and losses to continue to reflect the impact of changes in oil and gas prices. Our derivatives are reported at fair value and are sensitive to changes in the price of oil and gas. Changes in derivatives are reported as gain (loss) on derivatives, which include both the unrealized increase and decrease in their fair value, as well as the effect of realized settlements during the period. During September 2019, we closed out all open derivative positions with each of our 7 counterparties resulting in net proceeds of approximately $4 million, which we applied against our outstanding borrowings under the Alta Mesa RBL.

Impairments

No long-lived asset impairments were recognized during three months ended March 31, 2019. However, in late 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

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~~Preliminary~~Index ~~Estimated~~to ~~Purchase~~Financial ~~Price for Kingfisher~~Statements

The ~~estimated~~primary ~~preliminary~~factors ~~purchase~~affecting ~~price~~our ~~consideration~~production ~~for~~levels, ~~Kingfisher~~which ~~was~~may asbe ~~follows~~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. We attempt to overcome this natural decline primarily through development of our existing undeveloped resources, well recompletions and other enhanced recovery methods. 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. Our ability to add reserves through drilling and other development techniques is dependent on current market conditions and our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in ~~thousands):~~drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenue and, as a result, our cash flow from operations.

໿RESULTS OF OPERATIONS

໿For the Three Months Ended March 31, 2019 Compared to the Periods February 9, 2018 Through March 31, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor)

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

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 three months ended March 31, 2019 as the “2019 Quarter” and to the combined Predecessor Period and Successor Period from February 9, 2018 through March 31, 2018 as the “2018 Quarter.”

_________________

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

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

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

(4) Pursuant to ASC 805 and ASC 480, the Kingfisher earn-out consideration has been valued at fair value as of the Closing Date and has been classified in stockholders’ equity. The fair value of the contingent equity earn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs using the fair value hierarchy. The key inputs included the quoted market price for the Company’s Class A Common Stock, market volatility of a peer group of companies similar to the Company (due to the lack of trading activity in the Company’s Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining contractual term of the contingent liability earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.

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

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~~Preliminary~~Index ~~Estimated~~to ~~Purchase~~Financial ~~Price Allocation for Kingfisher~~Statements

~~The~~Upstream ~~allocation~~Segment ~~of the preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed in the acquisition of Kingfisher was as follows (in thousands):~~Results

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

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:

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



	Successor						Predecessor
(in thousands, except per unit data)	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Net production:
Oil (Mbbl)	1,619			651			494
Natural gas (MMcf)	5,831			2,248			1,609
NGLs (Mbbl)	795			223			151
Total (MBoe)	3,386			1,249			914

Average net daily production volumes:
Oil (Mbbld)	18.0			12.8			12.7
Natural gas (MMcfd)	64.8			44.1			41.2
NGLs (Mbbld)	8.8			4.4			3.9
Total (MBoed)	37.6			24.5			23.4

Average sales prices:
Oil (per bbl)	$	53.34		$	61.84		$	62.68
Effect of realized derivatives settlements (per bbl)	1.08			(7.93		)	(6.44		)
Oil, after hedging (per bbl)	$	54.42		$	53.91		$	56.24
Percentage of unhedged realized oil price to NYMEX oil price	97		%	99		%	99		%

Natural gas (per Mcf)	$	3.16		$	2.32		$	2.66
Effect of realized derivatives settlements (per Mcf)	(0.24		)	0.25			0.94
Natural gas, after hedging (per Mcf)	$	2.92		$	2.57		$	3.60

NGLs (per bbl)	$	14.11		$	21.18		$	26.41
Effect of realized derivatives settlements (per bbl)	—			—			—
NGLs, after hedging (per bbl)	$	14.11		$	21.18		$	26.41

Revenue
Oil sales	$	86,363		$	40,278		$	30,972
Natural gas sales	18,450			5,210			4,276
NGL sales	11,216			4,714			4,000
Total sales	$	116,029		$	50,202		$	39,248

~~(2)~~Oil ~~The~~revenue ~~estimated~~for ~~fair~~the ~~values~~2019 ofQuarter ~~crude~~increased ~~oil,~~compared ~~natural~~to ~~gas~~the ~~and~~2018 ~~NGL~~Quarter ~~gathering,~~due ~~processing and storage assets are determined using valuation techniques that convert future cash flows~~ to aan increase in ~~single~~production ~~discounted~~in ~~amount~~the ~~and~~2019 ~~involved~~Quarter, ~~the~~partially ~~use~~offset ofby ~~certain~~lower ~~inputs~~average ~~that~~sales ~~are~~prices. ~~not~~The increase in ~~observable~~production in the ~~market~~2019 ~~(Level~~Quarter 3was ~~inputs).~~due ~~These~~to ~~valuations~~the ~~required~~extensive ~~significant~~development ~~judgments~~program ~~and~~conducted ~~estimates~~following ~~by management at~~ the ~~time~~Business ~~of the valuation~~Combination. ~~Actual results may vary from these estimates.~~

~~(3)~~Natural ~~The~~gas ~~identifiable~~revenue ~~intangible~~for ~~assets~~the ~~acquired~~2019 ~~are~~Quarter ~~primarily~~increased compared ~~related~~ to ~~customer~~the ~~relationships~~2018 ~~held~~Quarter bydue ~~Kingfisher prior~~ to ~~Closing~~an ~~and~~increase ~~are~~in ~~reflected~~production atin ~~their~~the ~~estimated~~2019 ~~fair~~Quarter ~~values~~ as ~~of the acquisition date determined using valuation techniques that convert future cash flows to~~ a ~~single~~result ~~discounted amount and involve the use~~ of ~~certain inputs that are not observable in~~ the ~~market~~extensive ~~(Level~~development 3program ~~inputs).~~during ~~These~~2018 ~~valuations required significant judgments~~ and ~~estimates~~higher byprevailing ~~management~~market ~~at the time of the valuation~~prices.

(4) Goodwill reflected in the preliminary purchase price allocation includes expected synergies, including future cost efficiencies with continual flow of activity of Alta Mesa production into the Kingfisher processing facility as the basin expands, as well as other benefits that are expected to be generated.

Unaudited Pro Forma Operating Results

The following unaudited pro forma combined financial information has been prepared as if the Business Combination and other related transactions had taken place on January 1, 2017.

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

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

໿NGL revenue for the 2019 Quarter increased compared to the 2018 Quarter due to an increase in production in the 2019 Quarter, partially offset by lower average prices. The increase in production volume was primarily due to the impact of our extensive 2018 development activities.

	Three Months Ended September 30, 2017			January 1, 2018 Through February 8, 2018		Nine Months Ended September 30, 2017
	(in thousands)
Total operating revenues	$	80,140		$	49,500	$	230,763
Net income (loss)	(18,514		)	3,435		23,521
Net income (loss) attributable to Alta Mesa Resources, Inc. stockholders	(6,046		)	1,274		8,260
Basic net income (loss) per share	(0.04		)	0.01		0.05
Diluted net income (loss) per share	(0.04		)	0.01		0.05

Gain (loss) on sale of assets for the 2019 Quarter 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 Quarter.

~~NOTE 5 — PROPERTY, PLANT AND EQUIPMENT~~Derivatives

Property, plant and equipment consisted of the following (in thousands):



	Successor						Predecessor
(in thousands)	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives:
Oil	$	1,745		$	(4,530	)	$	(3,819	)
Natural gas	(1,380		)	555			1,523
Total realized gains (losses)	365			(3,975		)	(2,296		)
Unrealized gains (losses)	(24,142		)	(18,036		)	8,959
Total gain (loss) on derivatives	$	(23,777	)	$	(22,011	)	$	6,663

	Successor			Predecessor
	September 30, 2018			December 31, 2017
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	865,695		$	84,590
Accumulated impairment of unproved properties	—			—
Unproved properties, net	865,695			84,590
Proved oil and natural gas properties	1,913,526			1,061,105
Accumulated depreciation, depletion, amortization and impairment	(81,464		)	(251,065		)
Proved oil and natural gas properties, net	1,832,062			810,040
TOTAL OIL AND NATURAL GAS PROPERTIES, net	2,697,757			894,630
OTHER PROPERTY, PLANT AND EQUIPMENT
Land	5,600			2,912
Salt water disposal system	88,176			30,990
Plant and equipment	311,354			—
Office furniture and equipment and vehicles	3,129			20,008
Accumulated depreciation	(6,835		)	(21,770		)
OTHER PROPERTY, PLANT AND EQUIPMENT, net	401,424			32,140
TOTAL PROPERTY, PLANT AND EQUIPMENT, net	$	3,099,181		$	926,770

Increases in commodity prices during the 2019 Quarter, which outpaced increases during the 2018 Quarter, largely drove the higher unrealized losses on our outstanding derivatives.

~~NOTE~~Operating ~~6 — DISCONTINUED OPERATIONS (Predecessor)~~Expenses

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

Filing Compare · Alta Mesa Resources, Inc. /DE