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

¨ 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: 333-173751

_______________________________________

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

_______________________________________



Texas	20-3565150
(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)

Texas	20-3565150
(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

_______________________________________

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

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934. However, the registrant 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 would have been required to file such reports, as if it were subject to such filing requirements.)

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files.) Yes 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.

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x Smaller reporting company ¨ 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. ¨

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

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



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
None	None	None

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 Changes in Partners’ Capital	5
Condensed Consolidated Statements of Cash Flows	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3. Quantitative and Qualitative Disclosures about Market Risk	31
Item 4. Controls and Procedures	32
PART II - OTHER INFORMATION
Item 1. Legal Procedures	33
Item 1A. Risk Factors	33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3. Defaults Upon Senior Securities	33
Item 4. Mine Safety Disclosures	33
Item 5. Other Information	33
Item 6. Exhibits	34
Signatures	35

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.



2024 Notes -	$500 million aggregate principal amount of 7.875% senior unsecured notes due December 2024.
Alta Mesa RBL -	Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent.
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.
Bcfe -	One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids.
Boe -	One barrel of oil equivalent is determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in our business and represents the approximate ratio at energy content, and does not represent the price equivalency of natural gas to oil or natural gas liquids.
Boed -	One Boe per day.
Btu or British Thermal Unit -	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion -	The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil.
Condensate -	A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
DD&A -	Depreciation, depletion and amortization.
Developed acreage -	The number of acres that are allocated or assignable to productive wells or wells capable of production.
Developed oil and natural gas reserves -	Developed oil and natural gas reserves are reserves that can be expected to be recovered; through existing wells with existing equipment and operating methods or in which the cost of the related equipment is relatively minor compared to the cost of a new well.
Development costs -	Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas.
Development well -	A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential -	An adjustment to the market reference price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole -	A well found to be incapable of producing hydrocarbons in commercial quantities.
Dry hole costs -	Costs incurred in drilling an unsuccessful well, including plugging and abandonment costs.
Dth -	A dekatherm is a unit of energy used primarily to measure natural gas and is equal to 1,000,000 Btu.
Dthd -	1,000,000 Btu per day.
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.
Enhanced recovery -	The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

Table of Contents

໿Index to Financial Statements

	Page Number
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.
Glossary of Terms	3
Exploratory well -	A well drilled to find a new field or to find a new reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.
Cautionary Statement Regarding Forward-Looking Statements	4
Field -	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
PART I — FINANCIAL INFORMATION
Formation -	A layer of rock which has distinct characteristics that differs from adjacent rock.
Item 1. Financial Statements (unaudited)
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.
Condensed Consolidated Balance Sheets	6
Gross acres or gross wells -	The total acres or wells in which a working interest is owned.
Condensed Consolidated Statements of Operations	8
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 paying quantity of production.
Condensed Consolidated Statements of Changes in Partners’ Capital	9
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.
Condensed Consolidated Statements of Cash Flows	10
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.
Notes to Condensed Consolidated Financial Statements	11
Mbbl -	One thousand barrels of crude oil, condensate, natural gas liquids, or produced water.
Note 1 — Description of Business	11
Mbblsd -	One thousand barrels per day.
Note 2 — Summary of Significant Accounting Policies	11
MBoe -	One thousand boe.
Note 3 — Supplemental Cash Flow Information	15
MBoed -	One thousand boe per day.
Note 4 — Accounts Receivable	15
Mcf -	One thousand cubic feet of natural gas.
Note 5 — Business Combination	15
Mcfd -	One thousand cubic feet per day.
Note 6 — Property and Equipment	19
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.
Note 7 — Discontinued Operations (Predecessor)	19
Mcfed -	Mcfe per day.
Note 8 — Fair Value Measurements	21
MMBbl -	One million barrels of crude oil, condensate or natural gas liquids.
Note 9 — Derivative Financial Instruments	23
MMBtu -	One million British thermal units.
Note 10 — Asset Retirement Obligations	26
MMBtud -	One million British thermal units per day.
Note 11 — Long-Term Debt, Net	27
MMcf -	One million cubic feet of natural gas.
Note 12 — Accounts Payable and Accrued Liabilities	29
MMcfd -	One million cubic feet per day.
Note 13 — Commitments and Contingencies	29
Net acres -	The total acres a working interest owner has attributable to a particular number of acres, or a specified tract.
Note 14 — Significant Risks and Uncertainties	30
Net production -	Production that is owned by us after royalties and production attributable to other owners.
Note 15 — Partners' Capital	30
Net revenue interest -	A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interest.
Note 16 — Equity-based Compensation (Successor)	30
NGLs or natural gas liquids -	Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline.
Note 17 — Related Party Transactions	32
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.
Note 18 — Subsidiary Guarantors	32
NYMEX -	The New York Mercantile Exchange.
Note 19 — Subsequent Events	32
PDNP -	Proved developed non-producing reserves.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
PDP -	Proved developed producing reserves.
Item 3. Quantitative and Qualitative Disclosures about Market Risk	46
Predecessor Period	The period from January 1, 2018 through February 8, 2018.
Item 4. Controls and Procedures	46
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	46
Item 1A. Risk Factors	46
Item 5. Other Information	46
Item 6. Exhibits	47
Signatures	48

2ii

Table of Contents

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

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



Productive well -	A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Proved developed reserves -	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and can be expected to be recovered through extraction technology installed and operational at the time of the reserve estimate.
Proved properties -	Properties with proved reserves.
Proved reserves -	Quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs, and under existing economic conditions, operating methods and government regulations.
Proved undeveloped reserves ("PUD") -	Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make the well producible. Such reserves may be established if new proved developed reserves exist and they are expected to contain economically producible oil or gas on the basis of available geoscience and engineering data.
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 -	Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Reservoir -	A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
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.
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 is often expressed in terms of acres, e.g., 40-acre 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.
Stratigraphic test well -	A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
Success rate -	The percentage of wells drilled which produce hydrocarbons in commercial quantities.
Successor Period -	The period from February 9, 2018 through December 31, 2018, and all periods thereafter.
Undeveloped acreage -	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Unit -	The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
Unproved properties -	Properties with no proved reserves.
VWAP -	Volume weighted average price.

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 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 royaltyiii

Table of Contents

Index to Financial Statements



Waterflood -	The injection of water into an oil reservoir to “sweep” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically, an enhanced recovery process.
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.

Table of Contents

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~~Part ~~2017~~II, Item 1A of our Annual Report on Form 10-K ~~and~~for ~~Part~~the ~~II,~~year ~~Item~~ended December 1A31, ~~of this report~~2018. 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~~and ofour ~~the~~parent’s ~~Business~~ability ~~Combination, as defined in Note 5 of the accompanying Notes~~ to ~~Condensed~~continue ~~Consolidated~~as ~~Financial~~a ~~Statements~~going concern;

• the ~~future~~sufficiency ~~financial~~of ~~performance~~our ofliquidity ~~the~~position ~~combined~~to ~~company~~ensure ~~following~~financial ~~the~~flexibility ~~Business~~and ~~Combination~~fund our operations and capital expenditures;


•	our ability to comply with or otherwise obtain waivers of the covenants in our debt agreements;


•	our business strategy;


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

• our estimated purchase price and purchase price allocations;


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

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

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

• ~~our~~future ~~financial~~oil ~~strategy, liquidity~~ and ~~capital~~gas ~~required for our development program~~prices;

• ~~future~~the ~~oil~~supply and ~~natural~~demand ~~gas~~for ~~prices~~our production;

• the ~~supply~~timing and ~~demand~~amount ~~for~~of ~~crude~~our ~~oil,~~future ~~natural gas, and natural gas liquids~~production;

• ~~the~~our ~~timing~~hedging strategy and ~~amount~~ability ofto ~~future~~continue ~~production~~hedging ofexpected ~~oil and natural gas~~results;

• our hedging strategy and results;

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


•	competition and government regulation;


•	our ability to obtain permits and governmental approvals;

• expected or anticipated changes in the Oklahoma forced pooling system;

• pending legal, regulatory and environmental matters and litigation;

• 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 liquidity and access to capital;


•	our ability to hire, train or retain qualified personnel;


•	general economic conditions;

• ~~our~~operating ~~future~~hazards ~~operating~~and ~~results,~~other ~~including~~risks ~~initial~~incidental ~~production~~to ~~values~~transporting, storing, gathering and ~~liquid~~processing ~~yields~~natural ingas, ~~our~~natural ~~type~~gas ~~curve~~liquids, ~~areas~~and crude oil;

• ~~the~~our ~~costs,~~future ~~terms~~operating ~~and~~results, ~~availability~~including ofproduction ~~gathering~~levels, ~~processing,~~initial ~~fractionation~~production rates and ~~other~~yields ~~midstream~~in ~~services;~~our ~~and~~type curve areas;

• ~~our~~the ~~plans~~costs, ~~objectives,~~terms ~~expectations~~ and ~~intentions~~availability ~~contained~~of inmidstream ~~this report that are not historical.~~services;

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~~that ~~gas liquids. These risks include, but~~ are not ~~limited~~historical; ~~to, commodity price volatility, low prices for oil, natural gas~~ and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties and the other risks described under “Item 1A. Risk Factors” in our 2017 Annual Report on Form 10-K and in this report.

4• our ability to collect receivables from High Mesa.

We caution you that any forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, commodity price volatility, global economic conditions, including supply and demand levels for oil, gas and NGLs, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, liabilities resulting from litigation or the SEC investigation, difficulties in obtaining necessary approvals and permits, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, cyber-attacks,

Table of Contents

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

~~Should~~failure ~~one~~to orrealize ~~more~~expected ofvalue ~~the~~creation ~~risks~~from orproperty ~~uncertainties~~acquisitions, ~~described~~title indefects, ~~the~~limited ~~2017~~control ~~Annual~~over ~~Report~~non-operated onproperties, ~~Form~~and ~~10-K~~the orother ~~this~~risks ~~report~~described ~~occur,~~in orItem ~~should~~1A. ~~underlying~~Risk ~~assumptions~~Factors ~~prove~~of ~~incorrect,~~ our ~~actual~~Annual ~~results~~Report ~~and~~on ~~plans~~Form ~~could~~10-K ~~differ~~for ~~materially~~the ~~from~~year ~~those~~ended ~~expressed~~December in31, ~~any~~2018 ~~forward-looking~~(the ~~statements~~“2018 10-K”).

~~Except~~Estimating reserve quantities of oil, natural gas and NGLs is complex, inexact and relies on interpretations of geologic, geophysical, engineering and production data. The extent, quality, reliability and interpretation of these data can vary. The process also requires making a number of economic assumptions, such as ~~otherwise~~sales ~~required~~prices, bythe ~~applicable~~relative ~~law~~mix of oil, wenatural ~~disclaim~~gas ~~any~~and ~~duty~~NGLs tothat ~~update~~will ~~any~~be ~~forward-looking~~ultimately ~~statements~~produced, ~~all~~drilling and operating costs, capital expenditures, the effect of ~~which~~government ~~are~~regulation, ~~expressly~~taxes ~~qualified~~and byavailability of funds. Future prices received for production and costs may vary, perhaps significantly, from the ~~statements~~assumptions used in ~~this~~our ~~section~~estimates. In addition, tothe ~~reflect~~results ~~events~~of ordrilling, ~~circumstances~~testing ~~occurring~~and ~~after~~production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the ~~date~~schedule of ~~this~~development ~~Quarterly~~and ~~Report~~related onproduction. ~~Form~~Accordingly, ~~10-Q~~reserve estimates may differ significantly from the quantities of oil and gas that are ultimately recovered.

5Should one or more of the risks or uncertainties described in this Quarterly Report or in the 2018 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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

Table of Contents

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

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

Item 1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

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

(in thousands)

໿



	Successor						Predecessor
	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Revenue
Oil	$	86,363		$	40,278		$	30,972
Natural gas	18,450			5,210			4,276
Natural gas liquids	11,216			4,714			4,000
Other	568			555			888
Operating revenue	116,597			50,757			40,136
Gain on sale of assets	1,483			5,139			840
Gain (loss) on derivatives	(23,777		)	(22,011		)	6,663
Total revenue	94,303			33,885			47,639
Operating expenses
Lease operating	25,108			8,317			4,408
Transportation and marketing	17,761			5,582			3,725
Production taxes	5,483			1,415			953
Workovers	197			1,245			423
Exploration	2,054			1,585			7,003
Depreciation, depletion and amortization	34,675			11,038			11,670
General and administrative	20,947			34,654			21,234
Total operating expenses	106,225			63,836			49,416
Operating income	(11,922		)	(29,951		)	(1,777		)
Other income (expense)
Interest expense	(12,830		)	(5,196		)	(5,511		)
Interest income and other	27			546			172
Total other expense, net	(12,803		)	(4,650		)	(5,339		)
Loss from continuing operations	(24,725		)	(34,601		)	(7,116		)
Loss from discontinued operations, net of tax	—			—			(7,746		)
Net loss	$	(24,725	)	$	(34,601	)	$	(14,862	)

	Successor		Predecessor
	September 30, 2018		December 31, 2017
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	8,869	$	3,660
Restricted cash	872		1,269
Accounts receivable, net	107,984		76,161
Other receivables	246		1,388
Receivables due from affiliate	16,656		—
Receivables due from related party	13,085		790
Note receivable due from related party	1,642		—
Prepaid expenses and other current assets	3,423		2,932
Current assets — discontinued operations	—		5,195
Derivative financial instruments	—		216
Total current assets	152,777		91,611
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	2,697,757		894,630
Other property and equipment, net	93,956		32,140
Total property and equipment, net	2,791,713		926,770
OTHER ASSETS
Deferred financing costs, net	1,216		1,787
Notes receivable due from related party	11,492		12,369
Deposits and other long-term assets	86		9,067
Non-current assets — discontinued operations	—		43,785
Derivative financial instruments	—		8
Total other assets	12,794		67,016
TOTAL ASSETS	$	2,957,284	$	1,085,397

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

~~The accompanying notes are an integral part of these condensed consolidated financial statements.~~3

Table of Contents

	Successor		Predecessor
	September 30, 2018		December 31, 2017
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	227,139	$	170,489
Accounts payable — affiliate	481		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	289,466		239,648
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	9,169		10,400
Long-term debt, net	610,354		607,440
Noncurrent liabilities — discontinued operations	—		66,862
Derivative financial instruments	7,078		1,114
Other long-term liabilities	5		5,488
Total long-term liabilities	626,606		691,304
TOTAL LIABILITIES	916,072		930,952
Commitments and Contingencies (Note 13)
PARTNERS’ CAPITAL	2,041,212		154,445
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	2,957,284	$	1,085,397

Index to Financial Statements

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

Table of Contents

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

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

(in thousands)

໿

	Successor				Predecessor			Successor			Predecessor
	March 31, 2019			December 31, 2018
	Three				Three			February 9, 2018			January 1, 2018				Nine
ASSETS
	Months Ended				Months Ended			Through			Through				Months Ended
Current assets
	September 30, 2018				September 30, 2017			September 30, 2018			February 8, 2018				September 30, 2017
Cash and cash equivalents	$	27,045		$	12,984
OPERATING REVENUES AND OTHER
Restricted cash	798			1,001
Oil	$	107,253			$	44,201		$	222,822		$	30,972			$	133,489
Accounts receivable, net	65,403			68,370
Natural gas	11,959				9,583			25,149			4,276				29,816
Other receivables	2,239			6,267
Natural gas liquids	13,880				7,548			28,835			4,000				21,201
Related party receivables, net	17,126			24,282
Other revenues	1,011				1,792			3,795			888				5,005
Notes receivable from related party, net	—			—
Total operating revenues	134,103				63,124			280,601			40,136				189,511
Prepaid expenses and other current assets	4,549			747
Gain (loss) on sale of assets and other	(18		)		—			5,898			—				—
Derivatives	—			16,423
Gain on acquisition of oil and gas properties	—				5,267			—			—				5,267
Total current assets	117,160			130,074
Gain (loss) on derivative contracts	(11,212		)		(10,468		)	(63,077		)	7,298				38,024
Property and equipment
Total operating revenues and other	122,873				57,923			223,422			47,434				232,802
Oil and gas properties, successful efforts method, net	777,750			763,337
OPERATING EXPENSES
Other property and equipment, net	38,099			38,147
Lease operating expense	16,351				10,407			37,347			4,485				32,897
Total property and equipment, net	815,849			801,484
Marketing and transportation expense	15,820				8,314			32,608			3,725				20,486
Other assets
Production taxes	6,311				1,262			10,332			953				3,712
Operating lease right-of-use assets, net	14,758			—
Workover expense	1,065				1,441			2,643			423				3,131
Deferred financing costs, net	1,115			1,151
Exploration expense	1,029				3,649			14,067			3,633				11,888
Deposits and other long-term assets	48			63
Depreciation, depletion and amortization expense	45,623				24,159			83,068			11,784				63,247
Derivatives	461			2,947
Impairment expense	—				—			—			—				1,188
Total other assets	16,382			4,161
Accretion expense	226				108			489			39				234
Total assets	$	949,391		$	935,719
General and administrative expense	7,918				17,445			57,188			24,352				35,474
Total operating expenses	94,343				66,785			237,742			49,394				172,257
INCOME (LOSS) FROM OPERATIONS	28,530				(8,862		)	(14,320		)	(1,960		)		60,545
OTHER INCOME (EXPENSE)
Interest expense	(11,008		)		(13,545		)	(26,565		)	(5,511		)		(38,165		)
Interest income and other	322				244			1,688			172				792
Total other income (expense), net	(10,686		)		(13,301		)	(24,877		)	(5,339		)	—	(37,373		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE STATE INCOME TAXES	17,844				(22,163		)	(39,197		)	(7,299		)		23,172
Provision for state income taxes	—				—			7			—				285
INCOME (LOSS) FROM CONTINUING OPERATIONS	17,844				(22,163		)	(39,204		)	(7,299		)		22,887
Loss from discontinued operations, net of state income tax	—				(2,041		)	—			(7,593		)		(37,490		)
NET INCOME (LOSS)	$	17,844			$	(24,204	)	$	(39,204	)	$	(14,892	)		$	(14,603	)

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



	March 31, 2019			December 31, 2018
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	108,666		$	197,064
Accounts payable - related party	481			3,425
Advances from non-operators	2,367			5,193
Advances from related party	4,479			9,822
Asset retirement obligations	48			2,079
Current operating lease liability	895			—
Derivatives	5,057			1,710
Total current liabilities	121,993			219,293
Long-term liabilities
Asset retirement obligations, net of current portion	11,750			9,330
Long-term debt, net	805,892			690,123
Operating lease liabilities, net of current portion	13,962			—
Derivatives	2,065			180
Total long-term liabilities	833,669			699,633
Total liabilities	955,662			918,926
Commitments and contingencies (Note 13)
Partners’ capital	(6,271		)	16,793
Total liabilities and partners’ capital	$	949,391		$	935,719

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

Table of Contents

Index to Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

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

(in thousands)

໿

	Successor						Predecessor
	Predecessor
	Three Months EndedSeptember 30, 2018			February 9, 2018 Through September 30, 2018			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	$	2,048,043		$	1,535,891		$	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 contributions	—			560,344			200,000			—			200,000
Balance, February 8, 2018	$	183,065
Distributions	(25,000		)	(32,000		)	—			—			—
	Successor
Issuance of additional Alta Mesa purchase consideration	—			9,467			—			—			—
Balance, February 9, 2018	$	1,535,891
Equity-based compensation expense	325			6,714			—			—			—
Contributions	560,344
Net income (loss)	17,844			(39,204		)	(24,204		)	(14,892		)	(14,603		)
Equity-based compensation expense	2,768
Ending balance	$	2,041,212		$	2,041,212		$	217,503		$	172,655		$	217,503
Net loss	(34,601		)
Balance, March 31, 2018	$	2,064,402
Balance, December 31, 2018	$	16,793
Equity-based compensation expense	1,661
Net loss	(24,725		)
Balance, March 31, 2019	$	(6,271	)

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

Table of Contents

Index to Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)

໿



	Successor						Predecessor
	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Cash flows from operating activities:
Net loss	$	(24,725	)	$	(34,601	)	$	(14,862	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion, amortization and ARO accretion	34,675			11,038			12,554
Non-cash lease expense	99			—			—
Provision for uncollectible related party receivables	853			—			—
Impairments	—			—			5,560
Amortization of deferred financing costs	45			—			171
Amortization of debt premium discount	(1,231		)	(820		)	—
Equity-based compensation expense	1,661			2,768			—
Expired leases	162			4,189			4,575
(Gain) Loss on derivatives	23,777			22,011			(6,663		)
Cash settlements of derivatives	365			(3,975		)	(2,296		)
Interest converted into debt	—			—			103
Interest added to notes receivable from affiliate	—			(162		)	(85		)
Loss on sale of fixed assets	—			—			1,923
Impact on cash from changes in:
Accounts receivable	2,968			3,097			(21,184		)
Other receivables	4,029			1,427			(662		)
Receivables from affiliate and related party	6,303			(7,880		)	(117		)
Prepaid expenses and other non-current assets	(3,787		)	(2,240		)	(591		)
Advances from related party	(5,344		)	(7,008		)	24,116
Settlement of asset retirement obligations	(147		)	(166		)	(63		)
Accounts payable to related party	(2,944		)	(1,824		)	—
Accounts payable, accrued liabilities and other liabilities	(6,824		)	(35,165		)	23,857
Cash from operating activities	29,935			(49,311		)	26,336
Cash flows from investing activities:
Capital expenditures	(133,077		)	(129,310		)	(36,695		)
Acquisitions, net of cash acquired	—			—			(1,218		)
Cash from investing activities	(133,077		)	(129,310		)	(37,913		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	117,000			—			60,000
Repayments of long-term debt	—			(134,065		)	(43,000		)
Deferred financing costs paid	—			(1,007		)	—
Capital distributions	—			—			(68		)
Capital contributions	—			560,344			—
Cash from financing activities	117,000			425,272			16,932
Net increase in cash, cash equivalents and restricted cash	13,858			246,651			5,355
Cash, cash equivalents and restricted cash, beginning of period	13,985			10,345			4,990
Cash, cash equivalents and restricted cash, end of period	$	27,843		$	256,996		$	10,345

	Successor			Predecessor
	February 9, 2018			January 1, 2018			Nine
	Through			Through			Months Ended
	September 30, 2018			February 8, 2018			September 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(39,204	)	$	(14,892	)	$	(14,603	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization expense	83,068			12,414			80,082
Impairment expense	—			5,560			29,206
Accretion expense	489			140			1,447
Amortization of deferred financing costs	151			171			2,205
Amortization of debt premium	(3,281		)	—			—
Equity-based compensation expense	6,714			—			—
Dry hole expense	—			(45		)	2,447
Expired leases	10,658			1,250			8,394
(Gain) loss on derivative contracts	63,077			(7,298		)	(38,024		)
Cash settlements of derivative contracts	(32,836		)	(1,661		)	1,775
Premium paid on derivative contracts	—			—			(520		)
Interest converted into debt	—			103			904
Interest added to notes receivable due from related party	(680		)	(85		)	(619		)
Loss on sale of assets and other	81			1,923			—
Gain on acquisition of oil and gas properties	—			—			(6,893		)
Impact on cash from changes in assets and liabilities:
Accounts receivable	(5,715		)	(20,895		)	(33,649		)
Other receivables	976			(9,887		)	7,382
Receivables due from affiliate	(16,656		)	—			—
Receivables due from related party	(12,178		)	(117		)	169
Prepaid expenses and other current and non-current assets	8,181			9,970			(9,938		)
Advances from related party	(30,589		)	24,116			5,266
Settlement of asset retirement obligations	(1,249		)	(63		)	(6,083		)
Accounts payable — related party	(4,994		)	—			—
Accounts payable, accrued liabilities and other liabilities	(10,531		)	25,815			27,308
NET CASH PROVIDED BY OPERATING ACTIVITIES	15,482			26,519			56,256
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment	(489,009		)	(38,096		)	(244,308		)
Acquisitions	—			—			(55,236		)
Proceeds from sale of assets and other, net	11			—			—
Notes receivable due from affiliate	—			—			(1,515		)
NET CASH USED IN INVESTING ACTIVITIES	(488,998		)	(38,096		)	(301,059		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuances of long-term debt	80,000			60,000			286,065
Repayments of long-term debt	(134,065		)	(43,000		)	(251,622		)
Additions to deferred financing costs	(1,367		)	—			(220		)
Capital distributions	(32,000		)	(68		)	—
Capital contributions	560,344			—			207,875
NET CASH PROVIDED BY FINANCING ACTIVITIES	472,912			16,932			242,098
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	(604		)	5,355			(2,705		)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period	10,345			4,990			7,618
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, end of period	$	9,741		$	10,345		$	4,913

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

~~The accompanying notes are an integral part of these condensed consolidated financial statements.~~6

Table of Contents

Index to Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS

Alta Mesa Holdings, LP, ~~together with its subsidiaries~~ (“~~we,”~~Alta ~~“us,~~Mesa” ~~“our,”~~or “the “Company,” ~~and “Alta Mesa”~~), is an 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 commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County (“STACK”). Our ~~activities~~operations ~~are~~prior ~~primarily~~to ~~directed~~February at9, 2018, also included other oil and natural gas interests in Texas, Idaho, Louisiana and Florida. In connection with our acquisition by Alta Mesa Resources, Inc. (“AMR”), on February 9, 2018 (“the ~~horizontal~~Business ~~development~~Combination”), we distributed the non-STACK oil and gas assets and liabilities to our prior owner, High Mesa Holdings, LP (“High Mesa”), and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in anthe ~~area~~STACK. Prior ofto the ~~basin~~closing ~~commonly~~of ~~referred to as~~ the ~~Sooner~~Business ~~Trend~~Combination, ~~Anadarko~~we ~~Basin~~were ~~Canadian~~controlled ~~and~~by ~~Kingfisher~~High ~~County~~Mesa Inc. (“~~STACK~~HMI”).

As described further in Note 5 — Business Combination, certain transactions were consummated on February 9, 2018 that resulted in our acquisition by Alta Mesa Resources, Inc. (“AMR”). These transactions are referred to as the “Business Combination”. AMR is a publicly traded corporation that is not under the control of any person. Prior to the closing of the Business Combination, we were controlled by High Mesa Inc. (“High Mesa”) and indirectly by our founder and Chief Operating Officer, Michael E. Ellis.

In connection with the closing of the Business Combination, we distributed our non-STACK assets and liabilities to High Mesa Holdings, LP (the “AM Contributor”) and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

WeBasis ~~have provided a discussion~~ of significant accounting policies in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Annual Report”). As of September 30, 2018, our significant accounting policies are consistent with those discussed in Note 2 in the 2017 Annual Report, other than as noted below.Presentation

~~Basis~~All ofintercompany ~~Presentation. As~~transactions ~~a result of the Business Combination, AMR was treated as the accounting acquirer~~ and weaccounts ~~are~~have ~~the~~been ~~accounting acquiree~~eliminated. ~~Pursuant~~ toThese ~~Financial~~interim ~~Accounting~~condensed ~~Standards~~consolidated ~~Board~~financial ~~(“FASB”)~~statements ~~Accounting~~are ~~Standard Codification (“ASC”) 805~~unaudited, ~~Business~~but ~~Combinations,~~we ~~(“ASC~~believe ~~805”),~~these ~~our~~statements ~~identifiable~~reflect ~~assets~~all ~~acquired~~adjustments ~~and~~necessary ~~liabilities~~for ~~assumed~~a ~~were provisionally recorded at their estimated~~ fair ~~values~~presentation onfor the ~~Closing~~periods ~~Date~~reported. ofAll ~~the~~such ~~Business~~adjustments ~~Combination~~are ~~(also~~of ~~referred~~a tonormal, ~~herein~~recurring asnature ~~the~~unless ~~“acquisition~~otherwise ~~date”)~~disclosed. ~~Fair~~ ~~value~~These ~~adjustments~~financial ~~related~~statements toand ~~the~~disclosures ~~transaction~~ have been ~~pushed~~prepared ~~down to us resulting~~ in ~~our~~accordance ~~assets~~with ~~and liabilities being recorded at fair value as of~~ the ~~acquisition~~SEC’s ~~date. As~~rules afor ~~result~~interim ~~of the Transactions described above, the~~ financial statements and ~~certain~~do ~~footnote~~not ~~presentations~~include ~~separate~~all the ~~Company’s~~information ~~presentations~~and ~~into~~disclosures ~~two~~required ~~distinct~~by ~~periods,~~generally ~~the~~accepted ~~period~~accounting ~~before~~principles ~~the consummation of the transaction~~ (“~~Predecessor~~GAAP”) ~~and~~for ~~the~~complete ~~period~~financial ~~after~~statements. ~~that~~These ~~date~~financial ~~(“Successor”),~~statements toshould ~~indicate~~be ~~the~~read ~~application~~in ofconjunction with the ~~different~~audited ~~basis~~consolidated offinancial ~~accounting~~statements ~~between~~and ~~the~~notes ~~periods~~thereto ~~presented. The~~included ~~Successor~~in ~~periods~~our ~~presented~~2018 ~~herein~~10-K. ~~are~~The results for the three months ended ~~September 30,~~March ~~2018 and from February 9~~31, ~~2018 to September 30~~2019, ~~2018~~are ~~(collectively,~~not ~~“Successor~~necessarily ~~Periods”);~~indicative ~~and~~of the ~~Predecessor~~results ~~periods presented herein are from January 1, 2018~~ to ~~February 8,~~be ~~2018~~expected ~~(“2018~~for ~~Predecessor Period”),~~ the ~~three~~full ~~months~~year. We ~~ended~~have ~~September 30,~~no ~~2017~~items ~~and~~of ~~the~~other ~~nine~~comprehensive ~~months~~income ~~ended~~during ~~September 30,~~any ~~2017~~period ~~(“2017 Predecessor Period,” and, together with the 2018 Predecessor Period, the “Predecessor Periods”)~~presented.

AsRecently ~~noted~~Issued ~~above,~~Accounting weStandards ~~distributed~~Applicable ~~our non-STACK assets and liabilities~~ to the AM Contributor in connection with the closing of the Business Combination. The distribution of our non-STACK assets and liabilities and the sale of our Weeks Island field during the fourth quarter of 2017 (collectively, the “non-STACK assets”) were part of the Company’s overall strategic shift to operate only in the eastern Anadarko Basin. As a result, we have classified the assets and liabilities and operating results of the non-STACK assets as discontinued operations during the Predecessor Periods within the condensed consolidated financial statements. See Note 7 — Discontinued Operations (Predecessor) for further discussion.Us

Principles of Consolidation and Reporting. The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete financial statements. The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances.Adopted

~~The~~Effective ~~condensed~~January ~~consolidated~~1, ~~financial~~2019, ~~statements~~we ~~included~~adopted ~~herein~~ASU asNo. ~~of September~~2016-02, 30Leases (Topic 842) (“ASU 2016-02”), ~~2018~~which requires that lessees recognize a lease liability, ~~and~~which ~~for~~is ~~the~~a ~~three~~lessee’s ~~months~~discounted ~~ended~~obligation ~~September~~to make payments under a lease and 30a right-of-use asset, ~~2018~~arising ~~(Successor)~~from ~~and~~a lessee’s right to use an asset over the ~~period~~lease ~~from~~term. ~~February 9~~Upon adoption, ~~2018~~we ~~through~~used ~~September 30,~~the ~~2018~~modified ~~(Successor),~~retrospective method to apply the ~~period~~standard ~~from~~as of January 1, ~~2018~~2019 ~~through~~for ~~February 8,~~existing ~~2018~~leases ~~(Predecessor)~~with ~~and~~terms ~~the~~in ~~three~~excess ~~and~~of ~~nine~~12 months ~~ended~~entered ~~September 30,~~into ~~2017~~prior ~~(Predecessor)~~to January 1, 2019.

11Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade and notes receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 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

Table of Contents

~~are~~Index unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2017, which were filed with the Securities and Exchange Commission (the “SEC”) in our 2017 Annual Report. Certain reclassifications of prior period condensed consolidated financial statements have been made to ~~conform~~Financial to current reporting practices. The reclassifications had no impact on net income (loss) or partners’ capital. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year. Statements

~~The~~the ~~Company’s condensed~~ consolidated statement of operations ~~subsequent~~as tothe fees associated with the ~~Business~~hosting ~~Combination~~element ~~includes~~of ~~depreciation~~the ~~and~~arrangement. ~~amortization~~Similarly, ~~expense~~capitalized onimplementation ~~the~~costs ~~Company’s~~are ~~property~~to ~~and~~be ~~equipment~~presented ~~balances~~in ~~resulting~~the ~~from~~statement of cash flows in the ~~fair~~same ~~value~~line ~~adjustments~~as payments made ~~under~~for ~~the~~fees ~~new~~associated ~~basis~~with ofthe ~~accounting~~hosting element. ~~Certain~~We ~~other~~will ~~items~~adopt ofthis ~~income~~new ~~and~~standard ~~expense~~no ~~were~~later ~~also~~than ~~impacted.~~January ~~Therefore~~1, 2020, although early adoption is permitted. We are currently evaluating the ~~Company’s~~impact of this new standard on our consolidated financial ~~information~~position ~~prior~~and toresults ~~the~~of ~~Business~~operations ~~Combination~~and ishave not ~~comparable~~yet determined when to ~~its~~adopt ~~financial~~and ~~information~~whether ~~subsequent~~to apply the new standard retrospectively or prospectively to implementation costs incurred after the ~~Business~~date ~~Combination~~of adoption.

~~Use~~In ofAugust ~~Estimates. The~~2018, ~~preparation~~the ofFASB ~~condensed~~issued ASU ~~consolidated~~No. ~~financial~~2018-13, Fair ~~statements~~Value inMeasurement ~~conformity~~(Topic ~~with~~820) ~~GAAP~~Disclosure ~~requires~~Framework ~~management~~- Changes to ~~make~~the ~~estimates~~Disclosure ~~and~~Requirements ~~assumptions~~for ~~that~~Fair ~~affect~~Value Measurement (“ASU 2018-13”), which modifies the ~~reported~~disclosure ~~amounts~~requirements of ~~assets~~fair ~~and~~value ~~liabilities~~measurements. ASU ~~and~~2018-13 is ~~disclosure~~effective offor ~~contingent~~us ~~assets~~beginning ~~and~~January ~~liabilities~~1, at2020. ~~the~~Certain ~~date~~disclosures ofare ~~the~~required ~~condensed~~to ~~consolidated~~be ~~financial~~applied ~~statements~~on a retrospective basis and ~~the~~others ~~reported~~on ~~amounts~~a ofprospective ~~revenues~~basis. ~~and~~We ~~expenses~~do ~~during~~not expect the ~~reporting~~adoption ~~period~~of this standard to impact our financial position or results of operations.

~~Reserve~~NOTE ~~estimates~~3 ~~significantly~~— ~~impact~~GOING 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, the value of oil and natural gas properties, the value of other property and equipment, bad debts, asset retirement obligations, derivative contracts, accounting for business combinations, state taxes, share-based compensation and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.CONCERN

~~Restricted~~We ~~Cash. The~~are ~~following~~required ~~table~~to ~~provides~~evaluate aour ~~reconciliation~~ability ofto ~~cash,~~continue ~~cash~~as ~~equivalents~~a ~~and~~going ~~restricted~~concern ~~cash~~for ~~reported~~a ~~within~~period of one year following the ~~consolidated~~date ~~balance~~of ~~sheets~~issuance ~~and~~of ~~the~~our ~~consolidated~~financial statements. As part of ~~cash~~that ~~flows~~evaluation, ~~(in~~we ~~thousands)~~took into consideration the following factors:


•	At March 31, 2019, our current liabilities exceeded our current assets by $4.8 million.


•	We have failed to meet the timelines to provide our audited and unaudited financial information under our debt agreements.


•	Our 2018 drilling program, much of which involved the drilling of additional wells in close proximity to existing wells, did not meet our expectations for production and recovery. We also experienced an increasing gas-to-oil ratio as a well’s production ages, which has contributed to a lowering of the expected economics of our properties.


•	Although our well costs for our 2019 capital program have averaged less than $3.0 million per well, we still expect for our operating cash flow to be less than our capital spending for all of 2019.

•

On April 1, 2019, our borrowing base was reduced to $370.0 million under the Alta Mesa RBL and we have no further capacity thereunder. There is risk that future redeterminations could reduce the borrowing base further, which would trigger rateable repayments of excess borrowings over five months. Without additional capital, we will only be able to utilize the cash on hand, which at May 31, 2019 was $93.7 million, to fund development and meet our financial obligations and may be unable to maintain our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. The lenders have an ability to make an optional redetermination ahead of the regular redetermination scheduled in October 2019.


•	We anticipate having difficulty meeting our existing leverage covenants during the next 12 months without relief from our lenders. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements.


•	We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in June 2019, which could become an event of default if unpaid within the cure period. The 2024 Notes trade substantially below par value.

•

The Class A common stock of our parent company, AMR, has been trading below $1.00 per share since February 22, 2019. On April 3, 2019, AMR was notified by NASDAQ that it was not in compliance with the minimum bid price requirement. Continued trading at these levels may put further pressure on the value of our parent’s common stock and limit our ability to raise additional capital in the equity markets.

The above factors raise substantial doubt about our and our parent’s ability to continue as a going concern. To address this, we have:


•	retained financial advisors to assist in evaluating financial alternatives;


•	engaged in discussions with the Alta Mesa RBL lenders and their advisors about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement, however, we currently expect that such relief would only be available in connection with a reduction in our borrowing capacity which could further hamper our liquidity;


•	considered seeking new sources of financing, however, such efforts have not reached a stage where significant terms have been agreed to;


•	engaged in discussions with advisors to a group of holders of the 2024 Notes regarding potential options to address overall leverage, but have not agreed upon any significant strategy or terms; and


•	had preliminary discussions with existing capital providers about making additional investments in us but such discussions have not reached a stage of being considered likely or probable of success at this time.

Table of Contents

Index to Financial Statements

In light of the above, we believe substantial unresolved doubt exists regarding our ability to continue as a going concern for the next 12 months. We have continued reporting our long-term debt as noncurrent, since a conclusion regarding going concern has no effect on debt compliance.

NOTE 4 — 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 January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets of $15.0 million and operating lease liabilities of $15.0 million. There was no adjustment to 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 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 sublease any of our ROU assets.

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

Upon adoption, we selected the following practical expedients:



Practical expedient package		We did not reassess whether any expired or existing contracts are, or contain, leases.
		We did not reassess the lease classification of any expired or existing leases.
		We did not reassess initial direct costs of any expired or existing leases.

Hindsight practical expedient		We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.

Easement expedient		We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.

Combining lease and non-lease components expedient		We elected to account for lease and non-lease components as a single component.

Short-term lease expedient		We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.

As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, comparable companies and credit analysis 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, for our operating leases the weighted-average remaining lease terms were approximately 8.3 years and our weighted-average discount rates were 14.3%.

The following summarizes the components of our lease expense:

Table of Contents

Index to Financial Statements



(in thousands)	Three Months Ended March 31, 2019
Operating lease cost	$	811
Variable lease cost	323
Short-term lease cost	2,187
Total lease cost	$	3,321

For the three months ended March 31, 2019, we recognized $2.3 million of lease costs in lease operating expense and $1.0 million in general and administrative expense.

Maturities of our operating lease liabilities were as follows as of March 31, 2019:



Fiscal year	(in thousands)
Remainder of 2019	$	2,200
2020	2,965
2021	2,942
2022	3,010
2023	2,718
Thereafter	12,647
Total lease payments	26,482
Less: imputed interest	(11,625		)
Present value of operating lease liabilities	$	14,857

Current portion of operating lease liabilities	$	895
Operating lease liabilities, net of current portion	13,962
Present value of operating lease liabilities	$	14,857

As described further in our 2018 Annual Report on Form 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.

Table of Contents

Index to Financial Statements

NOTE 5 — 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	$	1,750		$	1,092		$	1,145
Non-cash investing and financing activities:
Increase in asset retirement obligations	314			421			—
Increase (decrease) in accruals or payables for capital expenditures	(84,162		)	(36,866		)	4,896
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~~		Predecessor
	September 30, 2018			December 31, 2017
(in thousands)	March 31, 2019		March 31, 2018			February 8, 2018
Cash and cash equivalents	$	827,~~869~~045	$	$255,701	~~3,660~~	$	9,070
Restricted cash	~~872~~798		1,295	~~1,269~~		1,275
Cash of discontinued operations	—			61
Total cash, cash equivalents and restricted cash	$	27,843	$	256,996		$	10,345
Total cash, cash equivalents and restricted cash	$	9,741		$	4,990

~~Bond~~NOTE Premium on Senior Unsecured Notes. As a result of the pushdown accounting related to the Business Combination, the Company estimated the fair value of our $500.0 million senior unsecured notes at $533.6 ~~million as of the acquisition date. The amount in excess of the original principal balance was recorded as a bond premium, which is being amortized as a reduction to interest expense.~~ — RECEIVABLES

~~Equity-Based~~Accounts ~~Compensation~~Receivable (Successor). The Company recognizes compensation related to all stock-based awards in the financial statements based on their estimated grant-date fair value. AMR 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 AMR’s common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See Note 16 — Equity-Based Compensation for additional information regarding the Company’s equity based compensation.

Going Concern. The Company’s management is required to evaluate an entity’s ability to continue as a going concern for a period of one year following the date of the issuance of the Company’s consolidated financial statements. 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.



(in thousands)	March 31, 2019			December 31, 2018
Production sales	$	32,332		$	31,532
Joint interest billings	18,224			18,147
Pooling interest⁽¹⁾	14,960			18,786
Allowance for doubtful accounts	(113		)	(95		)
Total accounts receivable, net	$	65,403		$	68,370

_________________


(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

Table of Contents

Index to Financial Statements



(in thousands)	March 31, 2019			December 31, 2018
Related party receivables	$	27,013		$	33,316
Allowance for doubtful accounts	(9,887		)	(9,034		)
Related party receivables, net	17,126			24,282

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	$	17,126		$	24,282

KFM Receivables

We have entered into a Crude Oil Gathering Agreement and a Gas Gathering and Processing Agreement with KFM. During the three months ended March 31, 2019, the period February 9, 2018 through March 31, 2018, and the Predecessor Period January 1, 2018 through February 8, 2018, we incurred $15.2 million, $4.6 million, and $3.1 million, respectively, in transportation and marketing expenses related to these agreements. Additionally, related party receivables from KFM for the marketing of our processed natural gas and NGLs were $2.3 million and $7.8 million at March 31, 2019 and December 31, 2018, respectively.

In addition, we sold a produced water disposal system to KFM during the fourth quarter of 2018. As of March 31, 2019 and December 31, 2018, related party receivables included $9.1 million and $8.7 million, respectively, attributable to a purchase price adjustment due from KFM. We collected these amounts during June 2019.

We incur general and administrative costs that may be partially or fully allocable to KFM. These costs are either allocated monthly or charged directly to KFM but are cash settled in arrears. As of March 31, 2019 and December 31, 2018, respectively, we have receivables from KFM for such costs totaling $1.9 million and $3.4 million, respectively.

AMR Receivables

We incur general and administrative costs that may be partially or fully allocable to AMR. These costs are either allocated monthly or charged directly to AMR but are cash settled in arrears. As of March 31, 2019 and December 31, 2018, respectively, we have receivables from AMR for such costs totaling $3.8 million and $3.3 million, respectively.

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 (the “Initial Term”), 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 (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, 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.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement 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 from us 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. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts

Table of Contents

AtIndex ~~the date of the issuance of these consolidated financial statements, management considers the Company~~ to beFinancial ~~a going concern and has prepared these consolidated financial statements on a going concern basis.~~Statements

~~Recent~~that ~~Accounting~~may ~~Pronouncements~~become ~~Issued~~due ~~But~~pursuant ~~Not~~to ~~Yet~~indemnification ~~Adopted. In~~obligations ~~August~~may ~~2018,~~be ~~the~~adversely ~~FASB~~impacted ~~issued~~by ~~ASU~~liquidity ~~No. 2018-15, Intangibles - Goodwill~~ and ~~Other~~solvency -issues ~~Internal-Use~~at ~~Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”)~~HMI. ~~The~~As ~~amendments in this standard align the requirements for capitalizing implementation costs incurred in~~ a ~~hosting~~result ~~arrangement~~of ~~that~~these iscircumstances, awe ~~service~~have ~~contract~~recognized ~~with~~an ~~the~~allowance ~~requirements~~ for ~~capitalizing~~uncollectible ~~implementation~~accounts ~~costs~~of ~~incurred~~$9.9 tomillion ~~develop or obtain internal use software (~~and ~~hosting~~$9.0 ~~arrangements~~million ~~that~~as ~~include~~of anMarch 31, ~~internal-use software license).~~2019 ~~Under~~and ~~this~~December 31, ~~new~~2018, ~~standard~~respectively, ato ~~customer~~fully inprovide afor ~~hosting~~the ~~arrangement~~unremitted ~~that~~balances. We ismay aalso ~~service~~be ~~contract~~subject ~~is required~~ to ~~follow~~future ~~the~~contingent ~~guidance~~liabilities infor ~~Subtopic~~the ~~350~~non-40STACK toassets ~~determine~~for which ~~implementation~~we ~~costs~~should tohave ~~capitalize~~been asindemnified, aincluding ~~prepaid~~liabilities ~~asset~~associated ~~related~~with litigation relating to the ~~service~~non-STACK ~~contract and which costs to expense~~assets. ~~The~~As ~~capitalized implementation costs are to be expensed over the term~~ of ~~the~~March ~~hosting~~31, ~~arrangement~~2019 and ~~reflected~~December in31, ~~the~~2018, ~~same~~we ~~line~~have inestablished ~~the~~no ~~consolidated~~liabilities ~~statement~~for ofcontingent ~~operations~~obligations ~~as the fees~~ associated with ~~the~~non-STACK ~~hosting~~assets ~~element~~owned ofby ~~the~~High ~~arrangement~~Mesa. ~~Similarly~~In addition, ~~capitalized~~we ~~implementation~~sold ~~costs~~a ~~are~~produced towater bedisposal ~~presented~~system into ~~the~~KFM ~~statement~~during ~~of cash flows in~~ the ~~same~~fourth ~~line~~quarter asof ~~payments made for fees associated with the hosting element~~2018. ~~The~~As ~~Company~~of ~~will~~March ~~adopt this new standard at the same time as our parent company~~31, ~~which~~2019 ~~will~~and ~~be no later than the fiscal year beginning after~~ December 1531, ~~2019~~2018, ~~although~~related ~~early~~party ~~adoption~~receivables isincluded ~~permitted~~$9. ~~The~~1 ~~Company~~million isattributable ~~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~~final ~~standard~~purchase ~~retrospectively~~price oradjustment ~~prospectively~~due tofrom ~~implementation~~KFM. This ~~costs~~amount ~~incurred~~was ~~after~~collected ~~the~~during ~~date~~June ~~of adoption~~2019.

InAs ~~May~~of ~~2014,~~March ~~the FASB issued ASU No. 2014-09~~31, ~~Revenue~~ ~~from~~2019 ~~Contracts~~and ~~with~~December ~~Customers (Topic 606) (“ASU 2014-09”)~~31, ~~which seeks to provide a single~~2018, ~~comprehensive revenue recognition model for all contracts with customers concerning~~ the ~~recognition,~~Company ~~measurement~~had ~~and disclosure of revenue from those contracts~~$3. ~~Subsequent~~8 tomillion ~~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$3. ~~The~~3 ~~core~~million ~~principle of the new amended standard is that a company will recognize revenue when it transfers promised goods and services to customers~~ in anrelated ~~amount~~party ~~that~~receivables ~~reflects~~due ~~the~~from ~~consideration~~AMR ~~to which the company is entitled in exchange~~ for ~~those~~expenses ~~services. In~~we ~~order~~paid toon ~~comply~~their 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 obligationbehalf.

~~ASU~~Promissory ~~2014-09,~~notes 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. receivable

~~ASU~~In ~~2014-09~~September, ~~allows~~2017, ~~for~~we ~~either~~entered ~~full~~into ~~retrospective~~a ~~adoption,~~$1.5 ~~meaning~~million ~~the~~promissory ~~standard~~note isreceivable ~~applied~~with toour ~~all~~affiliate, ~~periods~~Northwest ~~presented~~Gas inProcessing, ~~the financial statements~~LLC, orwhose ~~modified~~obligation ~~retrospective~~was ~~adoption,~~subsequently ~~meaning~~transferred ~~the~~to ~~standard~~High isMesa ~~applied~~Services, ~~only~~LLC to(“HMS”), ~~the~~a ~~most~~subsidiary ~~current~~of ~~period presented~~HMI. As The anpromissory ~~emerging~~note ~~growth~~bore ~~company~~interest, wewhich ~~previously~~could ~~elected~~be topaid-in-kind ~~use~~and ~~the~~added ~~extended~~to ~~transition~~the ~~period~~principal toamount ~~defer~~at ~~implementation~~a rate of ~~the~~8% ~~new~~per ~~standard~~annum, ~~until~~and ~~the~~matured ~~first~~in ~~quarter~~February of 2019. HMS ~~using~~defaulted under the ~~modified~~terms ~~retrospective~~of ~~method~~that ~~with~~promissory anote ~~cumulative~~when ~~adjustment~~it towas ~~retained~~not ~~earnings~~paid aswhen ~~necessary. AMR,~~due ~~our~~on ~~parent~~February ~~company~~28, is2019, ~~also~~and anHMS ~~emerging~~has ~~growth~~failed ~~company,~~to ~~but~~cure ~~will~~such ~~cease~~default. We tosubsequently bedeclared anall ~~emerging~~amounts ~~growth~~owed ~~company~~under onthe ~~December 31,~~note ~~2018,~~immediately ~~which~~due ~~will~~and ~~require~~payable ~~them~~and towe ~~adopt~~have ~~ASU~~fully ~~2014-09~~reserved onthe ~~December~~promissory ~~31,~~note ~~2018~~balance, ~~with~~including ~~modified~~interest ~~retroactive~~paid-in-kind, ~~implementation~~due as of ~~January~~ $1~~, 2018~~. ~~Accordingly,~~7 wemillion ~~will~~as ~~also~~of ~~adopt~~March 31, ~~ASU~~2019 ~~2014-09~~and atDecember 31, ~~the same time as our parent company~~2018.

WeIn ~~are~~addition, ~~continuing~~we ~~our~~have ~~review~~an of$8.5 ~~contracts~~million ~~for~~note ~~each~~receivable offrom ~~our~~HMS ~~revenue~~which ~~streams~~matures ~~and evaluating the impact~~ on ~~our consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09~~December 31, ~~as it relates to certain sales contracts~~2019, and inbears ~~particular,~~interest asat it8% ~~relates~~per ~~to disclosure requirements. In addition~~annum, wewhich ~~are~~may ~~evaluating~~be ~~the~~paid-in-kind ~~impact,~~and ifadded ~~any,~~to on the ~~presentation~~principal ofamount. HMI ~~our~~disputes ~~revenues~~its ~~and~~obligations ~~expenses~~ under the ~~new~~$8.5 ~~gross-versus-net~~million ~~presentation~~note. As ~~guidance~~of ~~and~~March on31, ~~our current accounting policies~~2019, ~~including the need to make changes to relevant accounting policies~~ and ~~internal controls~~December 31, ~~if needed. Based on assessments performed to date~~2018, ~~we do not expect ASU 2014-09 to have an effect on~~ the ~~timing~~note ofreceivable ~~revenue recognition or our financial position. In addition~~balance, weincluding ~~currently~~interest ~~expect the impact regarding gross~~paid-~~versus~~in-~~net~~kind, ~~presentation~~amounted to ~~involve~~$11.7 ~~certain~~million, ~~presentation~~for ~~changes~~each ~~specifically~~respective ~~related~~period. This tobalance ~~natural~~was ~~gas~~fully ~~processing~~reserved ~~contracts;~~at ~~however,~~ the ~~impact~~end of ~~such~~both ~~presentation changes will not impact our consolidated operating income, net income or cash flows~~periods.

InWe ~~February~~oppose ~~2016,~~HMI’s ~~the~~claims ~~FASB~~and ~~issued~~believe ~~ASU~~HMI’s ~~No.~~obligations ~~2016-02, Leases~~under ~~(Topic~~the ~~842)~~notes ~~(“ASU~~to ~~2016-02”),~~be ~~which~~valid ~~supersedes~~assets ~~ASC 840 “Leases”~~ and ~~creates~~that athe ~~new~~full ~~topic,~~amount ~~ASC~~is ~~842~~payable ~~“Leases~~to us.” We ~~The~~intend ~~amendments~~to inpursue ~~this~~all ~~update~~available ~~require,~~remedies ~~among~~under ~~other~~both ~~things,~~promissory ~~that~~notes ~~lessees~~and ~~recognize~~under ~~the~~applicable ~~following~~law ~~for~~in ~~all~~connection ~~leases~~with ~~(except~~repayment ~~for~~of ~~short-term leases) at~~ the ~~commencement~~promissory ~~date:~~notes. As ~~(i)~~ a ~~lease~~result ~~liability,~~of ~~which~~the ispotential aconflict ~~lessee’s~~of ~~obligation~~interest ~~to make lease payments arising~~ from acertain ~~lease,~~of ~~measured~~AMR’s ondirectors awho ~~discounted~~are ~~basis;~~also ~~and~~controlling ~~(ii) a~~holders ~~right-~~of~~-use~~ ~~asset~~HMI, ~~which is an asset that represents a lessee~~AMR’s ~~right~~disinterested todirectors ~~use,~~will oraddress ~~control~~any ~~the~~potential ~~use~~conflicts of, ainterest ~~specified~~with ~~asset~~respect ~~for~~to ~~the~~this ~~lease term~~matter. ~~Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the~~

Table of Contents

~~earliest~~Index ~~comparative period presented in the financial statements. ASU 2016-02 also requires disclosures designed~~ to ~~provide~~Financial 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.Statements

~~The~~NOTE 7 — ~~standard~~PROPERTY ~~provides~~AND 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.EQUIPMENT

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 thousands)	March 31, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	811,804		$	816,282
Accumulated impairment of unproved properties	(742,065		)	(742,065		)
Unproved properties, net	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	5,059			5,059
Fresh water wells	27,742			27,366
Produced water disposal system	3,590			3,608
Office furniture, equipment and vehicles	2,842			2,840
Accumulated depreciation	(1,134		)	(726		)
Other property and equipment, net	38,099			38,147
Total property and equipment, net	$	815,849		$	801,484

InDepletion ~~August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts~~ and ~~Cash~~Depreciation 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 had elected to use the extended transition period to defer adoption of this standard until 2019. However, our parent company will lose its emerging growth status, effective December 31, 2018. Accordingly, we will be required to adopt this new standard on December 31, 2018, when adopted by our parent company. 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. Expense

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 our trade 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, which will be effective for us in fiscal years beginning after December 15, 2019, also requires additional disclosures regarding the credit quality of our trade 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.



	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
Other property and equipment depreciation	408		163		609
Total depletion and depreciation	$	34,450	$	10,936	$	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. Therefore, we did not conduct further analysis on the recognition of additional impairment.

NOTE 8 — 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.

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.

Table of Contents

~~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):



	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		)
Total other 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		)

	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	$	22,073		$	1,145	$	25,675
Cash paid for state income taxes	7			—		—
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	35,967			4,712		41,322
Distribution of non-STACK (assets) net liability	—			33,102		—
Increase in accounts receivable for sale of assets	(524		)	—		—

NOTE 9 — DERIVATIVES

~~NOTE~~We 4have —entered ~~ACCOUNTS~~into ~~RECEIVABLE~~derivatives to reduce our exposure to price risk associated with our production. From time to time, we may enter into interest rate swap agreements to mitigate the risk of changes in interest rates, but as of March 31, 2019, we have none. We do not designate any of our derivatives as hedges under GAAP.

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

໿



	March 31, 2019
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivatives, current assets	$	6,525	$	(6,525	)	$	—
Derivatives, long-term assets	8,182		(7,721		)	461
Total	$	14,707	$	(14,246	)	$	461

	Successor			Predecessor
	September 30, 2018			December 31, 2017
Oil, natural gas and natural gas liquids sales	$	40,134		$	26,916
Joint interest billings	44,548			13,821
Pooling interest (1)	23,367			35,839
Allowance for doubtful accounts	(65		)	(415		)
Total accounts receivable, net	$	107,984		$	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 of unbilled interests on wells which the Company incurred before the pooling process was completed. Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties.

NOTE 5 — BUSINESS COMBINATION

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

Pursuant to the Contribution Agreements, SRII Opco, LP, a newly formed subsidiary of AMR (“SRII Opco”), acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP ((i) and (ii) together, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The

Table of Contents

~~acquisition~~Index ~~of us and Kingfisher pursuant~~ to ~~the~~Financial 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.” As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. Statements

At the closing of the Transactions, the AM Contributor received 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco. The AM Contributor also acquired from AMR a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), corresponding to the number of Common Units received by the AM Contributor at closing.



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

Additionally, for a period of seven years following the closing, the AM Contributor will be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of AMR’s Class C Common Stock) as earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock of AMR equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):



	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

20-DayVWAP	Earn-Out Consideration
Balance sheet location	Gross fair valueof liabilities		Gross assetsoffset against liabilitiesin the Balance Sheet			Net fairvalue of liabilitiespresented inthe Balance Sheet
$14.00	10,714,285 Common Units
	(in thousands)
$16.00	9,375,000 Common Units
Derivatives, current liabilities	$	7,799	$	(6,089	)	$	1,710
$18.00	13,888,889 Common Units
Derivatives, long-term liabilities	5,143		(4,963		)	180
$20.00	12,500,000 Common Units
Total	$	12,942	$	(11,052	)	$	1,890

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

The AM Contributor will not 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 to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of AMR, including a merger or sale of all or substantially all of AMR’s assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.



	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

~~AMR~~Other ~~also~~receivables ~~contributed~~at ~~$560~~March 31, ~~million~~2019 inand ~~net~~December 31, ~~cash~~2018 toinclude ~~us at the closing~~$0.4 ~~AMR’s~~million ~~source for these funds was from the sale of its securities to investors in a public offering~~ and ~~in private placements~~$1. We3 ~~used~~million, arespectively, ~~portion~~ of ~~the~~derivative ~~amount~~positions scheduled to ~~repay~~be ~~all~~settled ~~outstanding~~in ~~balance under~~ the ~~senior~~next ~~secured revolving credit facility described in Note 11 — Long-Term Debt, Net~~month.

~~Pursuant~~We toperiodically ~~the~~monitor ~~AM Contribution Agreement, AM Contributor delivered a final closing statement during~~ the ~~second~~creditworthiness ~~quarter~~ of ~~2018~~our counterparties. ~~Based~~Although onour ~~the~~counterparties ~~final~~provide ~~closing~~no ~~statement~~collateral, the AMagreements ~~Contributor~~with ~~received~~each ancounterparty ~~additional~~allow ~~1,197,934~~us ~~SRII~~to ~~Opco~~set-off ~~Common~~unpaid ~~Units~~amounts ~~and~~against anthe ~~equivalent~~outstanding ~~number~~balance ofunder ~~shares~~the ofAlta ~~AMR’s~~Mesa ~~Class C Common Stock~~RBL.

The Business Combination has been accounted for using the acquisition method. The acquisition method of accounting is based on FASB ASC 805, Business Combination (“ASC 805”), and uses the fair value concepts defined in FASB ASC 820, Fair Value Measurements (“ASC 820”). ASC 805 requires, among other things, that our assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by AMR, who was determined to be the accounting acquirer. We have not completed the detailed valuation studies necessary to arrive at the final determination of the fair value of the assets acquired, the liabilities assumed and the related allocations of the purchase price in the Business Combination. As a result, the values of certain of our long-term assets and liabilities are preliminary in nature and are subject to change as additional information becomes available and as additional analysis is performed. Pursuant to ASC 805, finalization of the values is to be completed within one year of the acquisition date.

Table of Contents

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

~~AMR’s~~We ~~preliminary~~had ~~estimated~~the ~~purchase~~following ~~price~~call ~~consideration~~and ~~for~~put ~~Alta~~derivatives ~~Mesa~~at ~~was~~March 31, ~~as follows (in thousands)~~2019:

OIL

໿



	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

GAS

	February 9, 2018 (As initially reported)		Measurement Period Adjustment (1)			February 9, 2018 (As adjusted)
		Volume in	Weighted			Range
Preliminary Purchase Consideration: (2)
Settlement Period and Type of Contract		MMBtu	Average			High			Low
SRII Opco Common Units issued (3)	$	1,251,782	$	9,467		$	1,261,249
2019
Estimated fair value of contingent earn-out purchase consideration (4)	284,109		—			284,109
Price Swap Contracts		11,030,000	$	2.67		$	2.72		$	2.64
Total purchase price consideration	$	1,535,891	$	9,467		$	1,545,358
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

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

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

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

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

(4) For a period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of AMR Class C Common Stock) if the 20-day VWAP of the Class A Common Stock of AMR 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 AMR (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.

Table of Contents

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

~~The~~We ~~allocation~~had ~~of AMR’s preliminary estimate of~~ the ~~purchase~~following ~~consideration~~basis toswaps ~~the~~at ~~assets~~March 31, ~~acquired and liabilities assumed in the acquisition of Alta Mesa was as follows (in thousands)~~2019:

໿



Total Gas Volumes in MMBtu⁽¹⁾over Remaining Term	Reference Price 1 ⁽¹⁾	Reference Price 2 ⁽¹⁾	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
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		)

	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
Accounts payable — affiliate	5,476		—			5,476
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	961,001		(10,946		)	950,055
Total consideration and fair value	$	1,535,891	$	9,467		$	1,545,358

________________

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

(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.

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

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

(4) Represents the approximate fair value as of the acquisition date of Alta Mesa’s $500.0 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 Eighth A&R credit facility (described in Note 11 — Long-Term Debt, Net) of approximately $134.1 million as of the acquisition date.

Table of Contents

~~NOTE~~Index 6to —Financial ~~PROPERTY AND EQUIPMENT~~Statements

~~Property~~NOTE 10 — ~~and~~ACCOUNTS ~~equipment~~PAYABLE ~~consisted~~AND ofACCRUED ~~the following (in thousands):~~LIABILITIES

	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 AND EQUIPMENT
Land	5,059			2,912
Salt water disposal system	88,176			30,990
Office furniture and equipment and vehicles	2,325			20,008
Accumulated depreciation	(1,604		)	(21,770		)
OTHER PROPERTY AND EQUIPMENT, net	93,956			32,140
TOTAL PROPERTY AND EQUIPMENT, net	$	2,791,713		$	926,770

໿

In conjunction with pushdown accounting, property and equipment was measured at fair value as of the acquisition date, which also impacted how value was assigned between the categories within property and equipment (see Note 5 — Business Combination for details).



(in thousands)	March 31, 2019		December 31, 2018
Accounts payable	$	8,502	$	20,200
Accruals for capital expenditures	25,964		101,214
Revenue and royalties payable	40,365		46,870
Accruals for operating expenses	8,910		16,355
Accrued interest	13,754		1,784
Derivative settlements	49		109
Other	11,122		10,532
Total accrued liabilities	100,164		176,864
Accounts payable and accrued liabilities	$	108,666	$	197,064

NOTE 7 11 — ~~DISCONTINUED~~ASSET ~~OPERATIONS~~RETIREMENT ~~(Predecessor)~~OBLIGATIONS

We distributed our non-STACK assets and related liabilities to the AM Contributor immediately prior to the Closing Date of the Business Combination. The distribution of our non-STACK assets and related liabilities and the sale of our Weeks Island field during the fourth quarter of 2017 were part of our 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 condensed consolidated financial statements in the 2018 Predecessor Period and the 2017 Predecessor Periods.



	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	$	11,409		$	—		$	10,469
Liabilities assumed in Business Combination	—			5,998			—
Liabilities incurred	315			421			—
Liabilities settled	(147		)	(166		)	(63		)
Revisions to estimates	(4)			300			63
Accretion expense	225			102			39
Balance, end of period	11,798			6,655			10,508
Less: Current portion	48			622			33
Long-term portion	$	11,750		$	6,033		$	10,475

Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bore simple interest at 10%. In connection with the Transactions described in Note 5 – Business Combination, the Founder Notes were converted into an equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK asset distribution. The balance of the Founder Notes at the time of conversion was approximately $28.3 million, including accrued interest. Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period and $0.3 million and $0.9 million for the three months ended SeptemberNOTE ~~30,~~12 — ~~2017~~LONG ~~(Predecessor)~~TERM ~~and 2017 Predecessor Period~~DEBT, ~~respectively.~~NET

໿



(in thousands)	March 31, 2019		December 31, 2018
Alta Mesa RBL	$	278,000	$	161,000
2024 Notes	500,000		500,000
Unamortized premium on 2024 notes	27,892		29,123
Total long-term debt, net	$	805,892	$	690,123

Alta Mesa RBL

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


•	a ratio of our current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and


•	a ratio of our consolidated debt to our consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0. For the first 3 measurement periods following the Business Combination we were able to annualize cumulative Successor Period results in measuring Adjusted EBITDAX.

During 2019, and possibly as soon as June 30, 2019, we may be unable to satisfy the leverage ratio. Also, we recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements.

Table of Contents

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

໿2024 Notes

	Predecessor
	December 31, 2017
Assets associated with discontinued operations:
Current assets
Cash	$	61
Accounts receivable	4,980
Other receivables	154
Total current assets	5,195
Noncurrent assets
Investments in LLC - Cost	9,000
Proved oil and natural gas properties, net	15,408
Unproved properties, net	15,504
Land	2,706
Other long-term assets	1,167
Total noncurrent assets	43,785
Total assets associated with discontinued operations	$	48,980
Liabilities associated with discontinued operations:
Current liabilities
Accounts payable and accrued liabilities	$	7,882
Asset retirement obligations	7,537
Total current liabilities	15,419
Noncurrent liabilities
Asset retirement obligations, net of current	37,049
Founder notes	28,166
Other long-term liabilities	1,647
Total noncurrent liabilities	66,862
Total liabilities associated with discontinued operations	$	82,281

In connection with the Business Combination, we recorded the fair value of our $500.0 million unsecured senior notes at $533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $194.9 million at March 31, 2019. This estimation was based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination.

Maturities of Long-Term Debt



Fiscal year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	278,000
Thereafter	500,000
	$	778,000

NOTE 13 — COMMITMENTS AND CONTINGENCIES

There have been no material developments during the first quarter of 2019 in relation to our commitments and contingencies as compared to our discussion of those matters in our Annual Report on Form 10-K for the year ended December 31, 2018.

NOTE 14 — SIGNIFICANT CONCENTRATIONS

During the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC (“ARM”) marketed our oil, gas and NGLs. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. During January and February 2019 and for all of 2018, ARM collected payments from purchasers, deducted their marketing fee and remitted the balance to us. In March 2019, in preparation for the return of oil and NGL marketing responsibilities to us, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM.

Effective as of June 1, 2019, we have terminated our oil and NGL marketing agreement with ARM and will market such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019. With respect to gas sales, ARM continues to collect payments from purchasers, deducts their marketing fee and remits the balance to us.

Our affiliate, Kingfisher Midstream, LLC (“KFM”) is responsible for marketing our firm transportation on the ONEOK Gas Transmission, L.L.C. system, which is indirectly marketed by ARM through an asset management agreement with KFM for a management fee.

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



	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	$	83,831	$	37,343	$	28,757

Marketing and management fees paid to ARM	$	661	$	—	$	—
Fees paid to ARM for services relating to our derivatives	193		74		66
Total fees paid to ARM	$	854	$	74	$	66

Table of Contents

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

໿Receivables from ARM for sales on our behalf were $3.8 million and $38.4 million as of March 31, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

	Predecessor
	Three Months EndedSeptember 30, 2017			January 1, 2018ThroughFebruary 8, 2018			Nine Months EndedSeptember 30, 2017
Operating revenues and other:
Oil	$	10,994		$	1,617		$	36,122
Natural gas	2,376			1,023			7,964
Natural gas liquids	571			236			1,613
Other revenues	72			16			274
Total operating revenues	14,013			2,892			45,973
Loss on sale of assets	—			(1,923		)	—
Gain on acquisition of oil and gas properties	—			—			1,626
Total operating revenues and other	14,013			969			47,599
Operating expenses:
Lease operating expense	6,888			1,770			21,944
Marketing and transportation expense	352			83			1,080
Production taxes	1,443			167			5,100
Workover expense	273			127			1,981
Exploration expense	1,874			—			8,042
Depreciation, depletion and amortization	4,625			630			16,835
Impairment expense	82			5,560			28,018
Accretion expense	287			101			1,213
General and administrative expense	13			21			60
Total operating expenses	15,837			8,459			84,273
Other income (expense)
Interest expense	(305		)	(103		)	(904		)
Interest income and other	88			—			88
Total other income (expense)	(217		)	(103		)	(816		)
Loss from discontinued operations, net of state income taxes	$	(2,041	)	$	(7,593	)	$	(37,490	)

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

~~The~~NOTE ~~total~~15 ~~operating~~— ~~and investing cash flows of the non~~EQUITY-~~STACK~~BASED ~~assets~~COMPENSATION ~~were as follows~~ (~~in thousands~~Successor):

໿Stock compensation expense recognized was as follows:

	Predecessor
	Successor						Predecessor
	January 1, 2018ThroughFebruary 8, 2018			Nine Months EndedSeptember 30, 2017
(in thousands)	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 8, 2018
Total operating cash flows of discontinued operations	$	(6,838	)	$	16,166
Stock options	$	791		$	1,048		$	—
Total investing cash flows of discontinued operations	(570		)	(15,950		)
Restricted stock awards	862			564			—
Performance-based restricted stock units	8			1,156			—
Total compensation expense	$	1,661		$	2,768		$	—

~~NOTE~~Performance-based 8restricted —stock ~~FAIR~~units ~~VALUE~~(“PSUs”) ~~MEASUREMENTS~~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 are 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.

WeThe ~~follow~~performance ~~ASC~~targets ~~820,~~for ~~which provides a hierarchy of fair value measurements based on~~ the ~~inputs~~2019 totranche ~~the~~were ~~fair~~established ~~value~~in ~~estimation~~March ~~process.~~2019 Itand ~~requires disclosure of fair values classified according to defined “levels~~595,”417 ~~which~~PSUs ~~are~~were ~~based~~deemed ongranted ~~the~~at ~~reliability~~that oftime. The ~~the evidence used to determine~~ fair value, ~~with~~of ~~Level 1 being~~ the ~~most~~2019 ~~reliable~~tranche ~~and~~granted ~~Level~~was ~~3 the least reliable~~$0.27 ~~Level~~per 1unit, ~~evidence~~which ~~consists~~will ofbe ~~observable~~recognized ~~inputs, such~~ as ~~quoted~~expense ~~prices~~over ~~in an active market. Level 2 inputs typically correlate~~ the ~~fair~~remainder ~~value~~ of ~~the~~2019, ~~asset~~subject ~~or liability~~ to acontinued ~~similar, but not identical item which is actively traded~~employment. ~~Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.~~

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

NOTE 16 — RELATED PARTY TRANSACTIONS

As of December 31, 2018, we had a payable of $2.9 million to KFM for produced water disposal services provided following the sale of the produced water system to them during the fourth quarter of 2018. Beginning in 2019, these costs are utilized to reduce the amount that KFM owes us for marketing our production, which are reported in related party receivables.

As of March 31, 2019 and December 31, 2018, we had a payable to AMR of $0.5 million.

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.

David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860, $970,197 and $28,874 during the 2019 Quarter, the period February 9, 2018 through March 31, 2018 and the Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019.

David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $70,180, $112,761 and $67,322 during the 2019 Quarter, the period February 9, 2018 through March 31, 2018 and the Predecessor Period, respectively. These amounts are included in general and administrative expense.

Table of Contents

InIndex connection with our acquisition, we recorded the fair value of our $500.0 million unsecured senior notes at $533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to beFinancial $476.3 million at September 30, 2018 (Successor). This estimation was based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination. See Note 11— Long-Term Debt, Net for information on long-term debt.Statements

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

~~Oil~~In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and ~~natural~~December ~~gas~~31, ~~properties~~2016, ~~are~~(the ~~subject~~“JDA”), with BCE, a fund advised by Bayou City, to ~~impairment~~fund ~~testing~~a portion of our drilling operations and ~~potential~~to ~~impairment~~allow ~~write~~us ~~down~~to accelerate development of our STACK acreage. The ~~During~~JDA established a development plan of 60 wells in three tranches, and provides opportunities for the ~~2017~~parties ~~Predecessor~~to ~~Period~~potentially agree to an additional 20 wells. Pursuant to the terms and provisions of the JDA, ~~certain~~BCE committed to fund 100% of our ~~oil~~working ~~and~~interest ~~natural~~share ~~gas~~up ~~properties~~to ~~with~~ a ~~carrying~~maximum ~~amount~~average well cost of $3.32 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 ~~written~~subsequently ~~down~~removed. In exchange for carrying the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to ~~their~~20% ~~fair~~of ~~value~~our initial working interest upon BCE achieving a 15% internal rate of $2return on the wells within a tranche and automatically further reduced to 12.15% ~~million~~of our initial interest upon BCE achieving a 25% internal rate of return on each individual tranche. Following the completion of each joint well, ~~resulting~~we inand anBCE ~~impairment~~will ~~charge~~each bear our respective proportionate working interest share of $1all subsequent costs and expenses related to such joint well.2 Mr. ~~million~~William McMullen, one of our directors, is founder and managing partner of BCE. ~~Significant~~ ~~Level~~The 3approximate ~~assumptions~~dollar ~~used~~value inof the ~~calculation~~amount ofinvolved ~~estimated~~in ~~discounted~~this ~~cash~~transaction, ~~flows~~or Mr. McMullen’s interests in the ~~impairment~~transaction, ~~analysis~~depends ~~included~~on ~~our~~a ~~estimate~~number of ~~future~~factors ~~oil~~outside his control and ~~natural~~is ~~gas~~not ~~prices~~known at this time. During the period February 9, ~~production~~2018 ~~costs~~through March 31, ~~development~~2018, ~~expenditures~~BCE advanced us approximately $39.5 million to drill wells under the JDA. As of March 31, ~~estimated~~2019, ~~timing~~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 ~~production~~revenue and net advances remaining from BCE for their working interest share of ~~proved~~the ~~reserves~~drilling and development costs arising under the JDA were included as “Advances from related party” in our condensed consolidated balance sheets. At March 31, ~~appropriate~~2019, ~~risk-adjusted~~there ~~discount~~were ~~rates~~no funded horizontal wells in progress, and ~~other~~we ~~relevant~~do ~~data~~not expect any wells to be developed in 2019 pursuant to the JDA.

~~New additions to asset retirement obligations result from estimations for new or acquired properties~~Item 2. ~~Such~~Management’s ~~estimations~~Discussion ~~of fair value are based on present value techniques that utilize company-specific information for such inputs as cost~~ and ~~timing~~Analysis of ~~plugging~~Financial Condition and ~~abandonment~~Results of wells and facilities. These inputs are classified as Level 3. We recorded $1.7 million, zero and $1.0 million in additions to asset retirement obligations measured at fair value during the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively.Operations

The following ~~table~~discussion ~~presents~~and ~~information~~analysis ~~about~~should ~~our~~be read in conjunction with the condensed consolidated financial ~~assets~~statements and ~~liabilities~~related ~~measured~~notes atincluded ~~fair~~elsewhere ~~value~~in onthis areport. ~~recurring~~The ~~basis~~following asdiscussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of ~~September 30~~oil and gas prices, ~~2018~~production timing and ~~December 31~~volumes, ~~2017~~estimates of proved reserves, operating costs and ~~indicates~~capital ~~the~~expenditures, ~~fair~~economic ~~value~~and ~~hierarchy~~competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this Quarterly Report and in the ~~valuation~~sections ~~techniques~~titled we“Risk ~~utilized~~Factors” in this Quarterly Report and in our 2018 Annual Report on Form 10-K, all of which are difficult to ~~determine~~predict. ~~such~~As ~~fair~~a ~~value:~~result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

	Level 1	Level 2		Level 3	Total
	(in thousands)
At September 30, 2018: (Successor)
Financial Assets:
Derivative contracts for oil and natural gas	—	$	5,670	—	$	5,670
Financial Liabilities:
Derivative contracts for oil and natural gas	—	$	47,144	—	$	47,144
At December 31, 2017: (Predecessor)
Financial Assets:
Derivative contracts for oil and natural gas	—	$	4,416	—	$	4,416
Financial Liabilities:
Derivative contracts for oil and natural gas	—	$	24,609	—	$	24,609

Overview

~~The~~We ~~amounts~~are ~~above~~an ~~are~~independent ~~presented~~exploration and production company focused on athe ~~gross~~acquisition, ~~basis~~development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We ~~will~~Our ~~net~~activities are primarily directed at the ~~value~~horizontal development of ~~assets~~an oil and ~~liabilities~~liquids-rich ~~with~~resource play in an area of the ~~same~~basin ~~counterparty~~commonly ~~for~~referred ~~purposes~~to ofas ~~presentation~~the inSooner ~~our~~Trend ~~condensed~~Anadarko ~~consolidated~~Basin ~~balance~~Canadian ~~sheets~~and ~~where~~Kingfisher ~~master~~County ~~netting~~(“STACK”). ~~agreements~~We ~~are~~generate inrevenue ~~place~~principally by the production and sale of oil, natural gas and NGLs. ~~For~~We ~~additional~~maintain ~~information~~operational oncontrol ~~derivative~~of ~~contracts~~the majority of our properties, ~~see~~either ~~Note~~through 9directly —operating ~~Derivative~~them ~~Financial~~or ~~Instruments~~through operating arrangements with other interest owners.

As of March 31, 2019, we have assembled a highly contiguous position of approximately 137,000 net acres in the up-dip, naturally-fractured oil portion of the STACK primarily in eastern Kingfisher and south-eastern Major counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. When we consider acquiring acreage within or adjacent to our acreage footprint, we prioritize opportunities where we can be the operator. During January 2019, we suspended our development program to evaluate well costs and performance. We restarted our development program in March 2019 and expect to use 2-3 rigs for the remainder of 2019 as we focus on the optimal completion design, well pattern and sustaining lower well costs.

As a result of the Business Combination, our identifiable assets acquired and liabilities assumed were recorded at their estimated fair values at February 9, 2018 and were pushed down to us. As a result, our financial statements and certain footnote

Table of Contents

~~NOTE~~Index 9to —Financial ~~DERIVATIVE FINANCIAL INSTRUMENTS~~Statements

Wepresentations ~~have~~separate ~~entered into forward-swap contracts and collar contracts to reduce~~ our ~~exposure~~presentations tointo ~~price~~two ~~risk~~distinct inperiods, the ~~spot~~period ~~market~~before ~~for oil, natural gas and natural gas liquids. From time to time, we also utilize financial basis swap contracts, which address~~ the ~~price~~consummation ~~differential between market-wide benchmark prices and other benchmark pricing referenced in certain~~ of ~~our~~the ~~oil,~~acquisition ~~natural~~(“Predecessor”) ~~gas~~ and ~~natural gas liquids sales contracts. Substantially all of our derivative contracts are executed by affiliates of our lenders under~~ the ~~senior~~period ~~secured~~after ~~revolving~~that ~~credit~~date ~~facility described in Note 11 — Long-Term Debt~~(“Successor”), ~~Net,~~to ~~and~~indicate ~~are collateralized by~~ the ~~security~~application ~~interests~~ of the ~~respective~~different ~~affiliated~~basis ~~lenders in certain~~ of ~~our~~accounting ~~assets~~between ~~under~~ the ~~senior~~periods ~~secured revolving credit facility~~presented. ~~The~~Accordingly, ~~derivative~~the ~~contracts~~period ~~settle monthly and are scheduled to coincide with oil production equivalent to barrels (bbl) per month~~January 1, ~~natural~~2018 ~~gas production equivalent~~ to ~~volumes in millions of British thermal units (MMBtu) per month~~February 8, ~~and~~2018 ~~natural~~is ~~gas~~referred ~~liquids production equivalent~~ to ~~volumes~~as ~~in gallons (gal) per month. The derivative contracts represent agreements between us and~~ the ~~counterparties~~Predecessor ~~to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices~~Period. ~~Cash settlement occurs monthly. No derivative contracts have been entered into for trading or speculative purposes.~~

~~From~~We ~~time~~distributed toour ~~time,~~non-STACK weoil ~~enter~~and ~~into~~gas ~~interest~~assets ~~rate~~and ~~swap~~liabilities ~~agreements~~to ~~with~~High ~~financial~~Mesa ~~institutions~~in toconnection ~~mitigate~~with the ~~risk~~closing of ~~loss~~the ~~due~~Business toCombination. ~~changes~~We inreport ~~interest~~the ~~rates. As~~non-STACK ofoil ~~September 30,~~and ~~2018,~~gas weassets ~~are~~and ~~not~~liabilities aas ~~party~~discontinued tooperations ~~any~~during ~~interest~~the ~~rate~~Predecessor ~~swap agreements~~Period.

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

~~Derivative~~Our ~~contracts~~revenue, ~~are~~profitability ~~subject~~and tofuture ~~master~~growth ~~netting~~rate ~~arrangements~~depend ~~and are presented~~ on amany ~~net~~factors, ~~basis~~particularly in the ~~condensed~~prices ~~consolidated~~of ~~balance~~oil, ~~sheets.~~gas ~~This~~and ~~netting~~NGLs, ~~can~~which ~~cause~~are ~~derivative~~beyond ~~assets~~our tocontrol. The besuccess ~~ultimately~~of ~~presented~~our inbusiness ais ~~liability~~significantly ~~account~~affected onby the ~~condensed~~price ~~consolidated~~of ~~balance~~oil ~~sheets.~~due ~~Likewise,~~to ~~derivative~~its ~~liabilities~~weighting ~~could be presented~~ in aour ~~derivative~~production ~~asset account~~profile.

~~The~~Factors ~~following~~affecting ~~table~~oil ~~summarizes~~prices include worldwide economic conditions; geopolitical activities in various regions of the ~~fair~~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 ~~classification~~it is uncertain whether the increase in market prices experienced since the end of ~~our~~2018 ~~derivative~~will ~~instruments~~be sustained. As a result, ~~none~~we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of ~~which~~certainty what effect increases or decreases in these prices will have ~~been~~on ~~designated~~our ascapital ~~hedging~~expenditures, ~~instruments~~production volumes or revenues. In the event that oil, gas and NGLs prices significantly decrease, such decreases could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of the borrowing capacity under ~~ASC~~the ~~815:~~Alta Mesa RBL.

~~Fair~~Key ~~Values~~performance ~~of Derivative Contracts:~~indicators

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

	September 30, 2018 (Successor)
Balance sheet location	Gross fair valueof assets		Gross liabilitiesoffset against assetsin the Balance Sheet			Net fairvalue of assetspresented inthe Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	2,407	$	(2,407	)	$	—
Derivative financial instruments, long-term assets	3,263		(3,263		)	—
Total	$	5,670	$	(5,670	)	$	—


•	Production

໿• General and administrative costs (excluding strategic costs)

Balance sheet location	Gross fair valueof liabilities		Gross assetsoffset against liabilitiesin the Balance Sheet			Net fairvalue of liabilitiespresented inthe Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	36,803	$	(2,407	)	$	34,396
Derivative financial instruments, long-term liabilities	10,341		(3,263		)	7,078
Total	$	47,144	$	(5,670	)	$	41,474


•	Lease operating expense

໿• Well costs


•	Adjusted EBITDAX

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

Going concern

Our present level of indebtedness and the impact of commodity prices at the end of 2018 on our current drilling and production plans present challenges to our ability to comply with the covenants under our debt agreements. Absent one or more deleveraging transactions, we may be at risk of non-compliance with the Consolidated Total Leverage Ratio Covenant in the Alta Mesa RBL as early as the June 30, 2019 measurement date. In addition, the lenders under the Alta Mesa RBL have an ability to make an optional redetermination ahead of the regular redetermination in October 2019. If the outstanding borrowings under the Alta Mesa RBL were to exceed the borrowing base due to any such redetermination, we would be required to repay the excess ratably over five months, which could have an adverse impact on our liquidity. Our general partner’s board and our parent’s board of directors and its financial advisors are evaluating the available financial alternatives, including, without limitation, seeking amendments or waivers to the covenants or other provisions of our indebtedness, raising new capital from the private or public markets or taking other actions to address our capital structure. If we are unable to reach an agreement with our lenders or find acceptable alternative financing, it may lead to an event of default under the Alta Mesa RBL. If following an event of default, the Alta Mesa RBL lenders were to accelerate repayment, it may result in an event of default and an acceleration under the 2024 Notes. We have concluded that these circumstances create substantial doubt regarding our ability to continue as a going concern. For a more detailed discussion, please read “Item 1A. Risk Factors” in Part I of our 2018 10-K.

Derivatives

Table of Contents

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

Index to Financial Statements

໿The objective of our hedging program is to reduce price volatility for our production over time. 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. For the quarter ended March 31, 2019, we recognized a net loss on our derivatives of $23.8 million, which includes $0.4 million in cash settlements received for derivatives.

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

Impairments

~~The~~In ~~following~~late ~~table~~fourth ~~summarizes~~quarter of 2018, the ~~effect~~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 resulted in impairment charges of $2.0 billion to our ~~derivative~~proved ~~instruments~~and unproved oil and gas properties 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. In the ~~condensed~~future, ~~consolidated~~we ~~statements~~may recognize further impairments of ~~operations~~proved (and unproved oil and gas properties if commodity prices decline from current levels and further restrict our drilling plans. Prolonged low commodity prices may also result in ~~thousands):~~additional impairments of other assets and could cause us to delay or abandon anticipated development activities.

໿Factors affecting future performance

	Successor			Predecessor			Successor			Predecessor
Derivatives not	Three			Three			February 9, 2018			January 1, 2018		Nine
designated as hedging	Months Ended			Months Ended			Through			Through		Months Ended
instruments under ASC 815	September 30, 2018			September 30, 2017			September 30, 2018			February 8, 2018		September 30, 2017
Gain (loss) on derivative contracts
Oil commodity contracts	$	(12,339	)	$	(10,873	)	$	(63,630	)	$	5,431	$	31,665
Natural gas commodity contracts	1,127			1,035			553			1,867		6,763
Natural gas liquids commodity contracts	—			(630		)	—			—		(404		)
Total gain (loss) on derivative contracts	$	(11,212	)	$	(10,468	)	$	(63,077	)	$	7,298	$	38,024

The primary factors affecting our production levels (which may be interrelated) are current commodity prices, capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of identified drilling locations. 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. Our ability to add reserves through drilling and other development techniques is dependent on 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 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.

~~The~~Results ~~Company periodically monitors the creditworthiness~~ of its counterparties. Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, under certain circumstances, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the senior secured revolving credit facility described in Note 11 — Long-Term Debt, Net.Operations

IfFor athe ~~counterparty~~Three ~~were~~Months toEnded ~~default~~March on31, ~~payment~~2019 ofCompared anto ~~obligation under~~ the ~~master~~Periods ~~derivative agreements~~February 9, we2018 ~~could~~Through March 31, be2018 ~~exposed~~(Successor) toand ~~commodity price fluctuations~~January 1, ~~and~~2018 ~~the~~Through ~~protection~~February 8, ~~intended~~2018 by(Predecessor) ~~the derivative could be lost. The value of our derivative financial instruments would be impacted.~~

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 for the three months ended March 31, 2018 as the “2018 Quarter.”

Table of Contents

WeIndex ~~had~~to ~~the~~Financial ~~following open derivative contracts for crude oil at September 30, 2018:~~Statements

~~OIL DERIVATIVE CONTRACTS~~Revenue

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

໿



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

Average net daily production volumes:
Oil (Mbblsd)	18.0			12.8			12.7
Natural gas (MMcfd)	64.8			44.1			41.2
NGLs (Mbblsd)	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 E&P sales revenue	$	116,029		$	50,202		$	39,248

	Volumein bbls	WeightedAverage		Range
Settlement Period and Type of Contract				High		Low
2018
Price Swap Contracts	552,000	$	53.55	$	61.26	$	50.27
Collar Contracts
Short Call Options	552,000	61.28		64.60		60.50
Long Put Options	552,000	51.67		60.00		50.00
Short Put Options	552,000	42.08		52.50		40.00
2019
Price Swap Contracts	182,500	63.03		63.03		63.03
Collar Contracts
Short Call Options	2,701,000	66.31		75.20		56.50
Long Put Options	2,883,500	53.80		62.00		50.00
Short Put Options	2,883,500	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	366,000	67.00		73.80		60.20
Long Put Options	1,317,600	56.46		62.50		50.00
Short Put Options	1,317,600	45.83		50.00		40.00

Oil 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 sales prices. The increase in production in the 2019 Quarter was due to the extensive development program conducted following the Business Combination.

WeNatural ~~had~~gas revenue for the ~~following~~2019 ~~open~~Quarter ~~derivative~~increased compared ~~contracts~~to ~~for~~the ~~natural~~2018 ~~gas~~Quarter atdue ~~September 30,~~to an increase in production in the 2019 Quarter as a result of the extensive development program during 2018: and higher prevailing market prices.

NATURAL GAS DERIVATIVE CONTRACTS

໿

	Volume inMMBtu	WeightedAverage		Range
Settlement Period and Type of Contract				High		Low
2018
Price Swap Contracts	1,842,500	$	2.95	$	3.09	$	2.75
Collar Contracts
Short Call Options	1,832,500	3.36		3.75		3.14
Long Put Options	1,527,500	2.89		2.90		2.75
Short Put Options	610,000	2.40		2.40		2.40
2019
Price Swap Contracts	10,905,000	2.69		3.09		2.64
Collar Contracts
Short Call Options	4,000,000	3.31		3.75		3.17
Long Put Options	3,550,000	2.81		2.90		2.70
Short Put Options	2,425,000	2.27		2.40		2.20
2020
Collar Contracts
Short Call Options	2,275,000	3.19		3.20		3.17
Long Put Options	9,150,000	2.57		2.70		2.50
Short Put Options	9,150,000	2.07		2.20		2.00
2021
Collar Contracts
Long Put Options	2,250,000	2.65		2.65		2.65
Short Put Options	2,250,000	2.15		2.15		2.15

In those instances where contracts are identical as to time period, volume and strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table

Table of Contents

~~above~~Index ~~for~~to ~~oil~~Financial ~~may settle against either the NYMEX index or may reflect a mix of positions settling on various combinations of these benchmarks.~~Statements

WeNGL ~~had~~revenue for the ~~following~~2019 ~~open~~Quarter ~~financial~~increased compared ~~basis~~to ~~swaps~~the at2018 ~~September~~Quarter due to an 30increase 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.

~~NATURAL~~Gain ~~GAS~~(loss) ~~BASIS~~on ~~SWAP~~sale ~~DERIVATIVE~~of ~~CONTRACTS~~assets and other 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.

Volume in MMBtu(1)	Reference Price 1 (1)	Reference Price 2 (1)	Period			WeightedAverage Spread($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
4,445,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Oct '18	—	Dec '18	(0.63		)
17,950,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '19	—	Dec '19	(0.68		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
152,500	San Juan	NYMEX Henry Hub	Nov '18	—	Dec '18	(0.47		)
2,365,000	San Juan	NYMEX Henry Hub	Jan '19	—	Oct '19	(0.78		)

Derivatives

_________________



	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

~~(1)~~Increases ~~Represents~~in ~~short~~commodity ~~swaps~~prices ~~that~~during ~~fix~~ the ~~basis~~2019 ~~differentials~~Quarter, ~~between~~which ~~OneOK,~~outpaced ~~Tex/OKL~~increases ~~Panhandle~~during ~~Eastern~~the ~~Pipeline~~2018 ~~(“PEPL”)~~Quarter, ~~San~~largely ~~Juan~~drove ~~and~~the ~~NYMEX~~higher ~~Henry~~unrealized ~~Hub~~losses on our outstanding derivatives.

~~OIL~~Operating ~~BASIS SWAP DERIVATIVE CONTRACTS~~Expenses

໿



	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
Operating expenses:
Lease operating	$	25,108	$	8,317	$	4,408
Transportation and marketing	17,761		5,582		3,725
Production taxes	5,483		1,415		953
Workovers	197		1,245		423
Exploration	2,054		1,585		7,003
Depreciation, depletion and amortization	34,675		11,038		11,670
General and administrative	20,947		34,654		21,234
Total operating expense	$	106,225	$	63,836	$	49,416

Operating expenses per BOE:
Lease operating	$	7.42	$	6.66	$	4.82
Transportation and marketing	5.25		4.47		4.08
Production taxes	1.62		1.13		1.04
Workovers	0.06		1.00		0.46
Depreciation, depletion and amortization	10.24		8.84		12.77

Volume in bbl (1)

Reference Price 1 (1)

Reference Price 2 (1)

Period

WeightedAverage Spread($ per bbl)

552,000

CMA Oil

WTI

Oct '18

—

Dec '18

(0.54

)

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

_________________

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

NOTE 10 — ASSET RETIREMENT OBLIGATIONS

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

໿

	2018
Balance, as of January 1 (Predecessor)	$	10,469
Liabilities settled	(63		)
Revisions to estimates	63
Accretion expense	39
Balance, as of February 8 (Predecessor)	$	10,508
Balance, as of February 9 (Successor)	$	—
Liabilities assumed from Business Combination	5,998
Liabilities incurred	1,689
Liabilities settled	(1,249		)
Liabilities transferred in sale of properties	(20		)
Revisions to estimates (1)	3,562
Accretion expense	489
Balance, as of September 30 (Successor)	10,469
Less: Current portion	1,300
Long-term portion	$	9,169

(1) The total revisions included $3.0 million related to additions to property, plant and equipment for the Successor Period.

Table of Contents

~~NOTE~~Index 11to —Financial ~~LONG-TERM DEBT, NET~~Statements

~~Long-term~~Transportation ~~debt~~and marketing expense for the 2019 Quarter increased compared to the 2018 Quarter primarily due to higher volumes. The fee we pay per unit reflects the firm processing capacity at the plant, ~~net~~as ~~consisted~~well ofas firm transport for our residue gas at the ~~following~~tailgate ~~(in~~of ~~thousands):~~the plant.

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

	Successor		Predecessor
	September 30, 2018		December 31, 2017
Senior secured revolving credit facility	$	80,000	$	117,065
7.875% senior unsecured notes due 2024	500,000		500,000
Unamortized premium on senior unsecured notes	30,354		—
Unamortized deferred financing costs	—		(9,625		)
Total long-term debt, net	$	610,354	$	607,440

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

Senior Secured Revolving Credit Facility (Successor). In connection with the consummation of the Business Combination, all indebtedness at that time under the senior secured revolving credit facility was repaid in full. On February 9, 2018, and in connection with the closing of the AM Contribution Agreement (as described in Note 5), we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base. In April 2018, our borrowing base was increased to $400.0 million. This borrowing base was reaffirmed by the lenders subsequent to September 30, 2018. The next scheduled redetermination will occur in April 2019, at which time the borrowing base may be increased, lowered or stay the same. The Eighth A&R credit facility does not permit us to borrow funds if, at the time of such borrowing, we are not in compliance with the financial covenants set forth in the Eighth A&R credit facility. As of September 30, 2018, we had $80.0 million of borrowings outstanding under the Eighth A&R credit facility and had $21.9 million of outstanding letters of credit, leaving a total borrowing capacity of $298.1 million remaining available for future use.



	Successor				Predecessor
(in thousands)	Three Months Ended March 31, 2019		February 9, 2018 Through March 31, 2018		January 1, 2018 Through February 8, 2018
Exploration expense:
Geological and geophysical costs	$	312	$	451	$	2,440
Dry hole expense	—		—		—
Other exploration expense, including expired leases	1,695		833		4,504
ARO settlements in excess of recorded liabilities	47		301		59
Total exploration expense	$	2,054	$	1,585	$	7,003

~~The~~Exploration ~~principal~~expense ~~amounts~~for ~~borrowed are payable on~~ the ~~maturity~~2019 ~~date~~Quarter ofdecreased ~~February 9,~~compared 2023. We have a choice of borrowing in Eurodollars or at the reference rate, with such borrowings bearing interest, payable quarterly for reference rate loans or, for Eurodollar loans, in one, three or six-month tranches. Eurodollar loans bear interest at a rate per annum equal to the ~~applicable~~2018 ~~LIBOR~~Quarter ~~rate,~~primarily ~~plus~~due ~~a margin ranging from 2.00%~~ to ~~3.00%. Reference~~our ~~rate~~cost ~~loans~~reduction ~~bear~~efforts ~~interest~~and at a ~~rate~~decrease ~~per~~in ~~annum~~expenses ~~equal~~relating to ~~the~~expired ~~greater of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points~~ or ~~(iii) the~~expiring ~~rate for one-month Eurodollar loans plus 1~~leaseholds.~~00%, plus a margin ranging from 1.00% to 2.00%.~~

The amounts outstanding under the Eighth A&R credit facility are secured by the first priority liens on substantially all of the Company’s, and its material operating subsidiaries’, oil and natural gas properties and associated assets and all of the equity of our material operating subsidiaries that are guarantors of the Eighth A&R credit facility. Additionally, SRII Opco and AMH GP have pledged their respective limited partner interests in us as security for our obligations. If an event of default occurs under the Eighth A&R credit facility, the administrative agent will have the right to proceed against the pledged collateral and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.



	Successor				Predecessor
(in thousands)	Three Months Ended March 31, 2019		February 9, 2018 Through March 31, 2018		January 1, 2018 Through February 8, 2018
General and administrative expense:
Employee-related costs	$	10,376	$	6,788	$	1,032
Strategic costs - Business Combination costs	—		23,717		17,040
Equity-based compensation	1,661		2,768		—
Professional fees	2,871		890		1,019
Severance costs	3,975		—		—
Operating leases	1,024		491		208
Other	1,040		—		1,935
Total general and administrative expense	$	20,947	$	34,654	$	21,234

~~The~~General ~~Eighth~~and ~~A&R~~administrative ~~credit~~expense ~~facility,~~for asthe ~~amended~~2019 ~~effective~~Quarter ~~August~~decreased ~~13,~~compared ~~2018,~~to ~~contains~~the ~~restrictive~~2018 ~~covenants~~Quarter ~~that~~primarily ~~may~~due ~~limit~~to nonrecurring ~~our~~strategic ~~ability~~costs ~~to,~~and ~~among~~professional ~~other~~fees ~~things,~~incurred ~~incur~~in ~~additional~~the ~~indebtedness,~~2018 ~~sell~~Quarter ~~assets,~~for ~~guaranty~~advisors orhelping ~~make~~to ~~loans~~value toand ~~others,~~integrate ~~make~~the ~~investments,~~acquired ~~enter~~business ~~into~~pursuant ~~mergers,~~to ~~make~~the ~~certain~~Business ~~payments~~Combination. General and ~~distributions~~administrative expense in ~~excess~~the ofSuccessor ~~specific~~Periods ~~amounts,~~also ~~enter~~include ~~into~~equity-based orcompensation beawards ~~party~~with tono ~~hedge~~similar ~~agreements,~~activity ~~amend organizational documents, incur liens and engage~~ in ~~certain other transactions without~~ the ~~prior~~Predecessor ~~consent of the lenders~~Period. Employee-related ~~The~~costs ~~Eighth~~primarily ~~A&R~~increased ~~credit~~due ~~facility permits us~~ to ~~make~~higher ~~distributions~~employee toexpenses ~~any~~compared ~~parent entity (i)~~ to ~~pay~~the ~~for~~2018 ~~reimbursement~~Quarter ofreflecting ~~third~~the ~~party~~increase ~~costs~~in ~~and~~production ~~general~~activity ~~and~~during ~~administrative~~2018. ~~expenses~~Following ~~(“G&A”)~~a ~~incurred~~reassessment ~~in the ordinary course~~ of ~~business~~2019 byactivity ~~such~~levels, ~~parent~~we ~~entity~~implemented ora ~~(ii)~~ reduction in ~~order~~force toprogram ~~permit~~during ~~such~~the ~~parent~~2019 ~~entity~~Quarter towhich ~~(x) make~~resulted ~~permitted~~in ~~tax~~an ~~distributions~~increase ~~and~~in ~~(y) pay~~severance ~~the~~costs ~~obligations~~for ~~under~~ the ~~tax~~current ~~receivable agreement~~period.

~~The~~Below ~~Eighth~~is ~~A&R~~a ~~credit~~reconciliation ~~facility~~of ~~also~~our ~~requires~~Adjusted usEBITDAX to ~~maintain~~our ~~the~~loss ~~following~~from ~~two~~continuing ~~financial~~operations ~~ratios~~before income taxes:

• a current ratio, subject to various adjustments as defined in the Eighth A&R credit facility, tested quarterly, commencing with the fiscal quarter ended June 30, 2018, of our consolidated current assets to our consolidated current liabilities of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

• a leverage ratio, tested quarterly, commencing with the fiscal quarter ended June 30, 2018, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated EBITDAX annualized by multiplying EBITDAX for the period of (a) the fiscal quarter ended June 30, 2018 times 4, (b) the two fiscal quarter periods ended September 30, 2018 times 2 (c) the three fiscal quarter periods ending December 31, 2018 times 4/3rds and

Table of Contents

~~(d)~~Index ~~for each fiscal quarter on or after March 31, 2019, EBITDAX for the four-fiscal quarter period then ended, of not greater than 4.0~~ to ~~1.0.~~Financial Statements

As of September 30, 2018, we were in compliance with the financial ratios described above.



	Successor						Predecessor
(in thousands)	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Loss from continuing operations before income taxes	$	(24,725	)	$	(34,601	)	$	(7,116	)

Interest expense	12,830			5,196			5,511
Depreciation, depletion and amortization	34,675			11,038			11,670
Exploration	2,054			1,585			7,003
Loss (gain) on unrealized hedges	24,142			18,036			(8,959		)
Loss on sale of property and equipment	—			1,923			—
Equity-based compensation	1,661			2,768			—
Severance costs	3,975			—			—
EBITDAX	54,612			5,945			8,109
Business Combination related expense	—			23,717			17,040
Adjusted EBITDAX	$	54,612		$	29,662		$	25,149

~~Senior~~The ~~Secured~~Company’s ~~Revolving~~management ~~Credit~~believes ~~Facility~~Adjusted ~~(Predecessor). As~~EBITDAX ofis ~~December 31,~~useful ~~2017~~because it allows users to more effectively evaluate our operating performance, compare the ~~Company~~results ~~had~~of ~~$117.1~~our ~~million~~operations offrom ~~borrowings~~period ~~outstanding~~to period and against our peers without regard to our financing methods or capital structure and because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures. At ~~the~~Adjusted ~~date~~EBITDAX ofshould ~~the~~not ~~Business~~be ~~Combination,~~considered ~~the~~as ~~outstanding~~an ~~balance~~alternative ~~under~~to our ~~credit~~net ~~facility~~income ~~was~~(loss), ~~paid~~operating ~~off~~income (loss) or other performance measures derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports.

~~Senior~~Other ~~Unsecured Notes. We have $500.0 million in aggregate principal amount of 7.875% senior unsecured notes~~ (~~the “senior notes”~~Income) which were issued at par by us and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016. The senior notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017. Expense

The senior notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes for an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.



	Successor						Predecessor
(in thousands)	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Alta Mesa RBL	$	3,579		$	278		$	815
2024 Notes	9,844			6,561			3,281
Bond premium amortization	(1,231		)	(820		)	—
Deferred financing cost amortization	45			—			171
Other	593			(823		)	1,244
Total interest expense	12,830			5,196			5,511
Interest income and other	(27		)	(546		)	(172		)
Total other expense, net	$	12,803		$	4,650		$	5,339

~~The~~Interest ~~senior~~expense ~~notes~~for ~~are~~the ~~fully~~2019 ~~and~~Quarter ~~unconditionally~~increased ~~guaranteed~~$2.1 onmillion acompared ~~senior~~to ~~unsecured~~the ~~basis~~2018 byQuarter ~~each~~primarily ofdue ~~our material subsidiaries, subject~~ to ~~certain~~increased ~~customary~~levels ~~release provisions. Accordingly, they will rank equal in right~~ of ~~payment~~borrowing tounder ~~all~~the ofAlta ~~our~~Mesa ~~existing~~RBL. ~~and~~Deferred ~~future~~financing ~~senior~~costs ~~indebtedness;~~related ~~senior in right of payment~~ to ~~all~~the ofAlta ~~our~~Mesa ~~existing~~RBL and ~~future indebtedness that is expressly subordinated to~~ the ~~senior~~premium ~~notes~~associated orwith ~~the respective guarantees; effectively subordinated to all of~~ our ~~existing~~2024 ~~and~~Notes ~~future~~are ~~secured~~being ~~indebtedness~~amortized toover the ~~extent~~remaining ofterm ~~the value~~ of ~~the~~each ~~collateral~~obligation. ~~securing~~Other ~~such~~interest ~~indebtedness,~~expense ~~including~~includes ~~amounts~~commitment ~~outstanding~~fees ~~under our credit facility;~~ and ~~structurally~~interest ~~subordinated~~expense related to ~~all existing and future indebtedness and obligations of any of~~ our ~~subsidiaries~~joint ~~that~~development doagreement ~~not~~with ~~guarantee the senior notes~~BCE.

~~The~~Liquidity ~~senior notes contain certain covenants limiting the Issuers’ ability~~ and ~~the~~Capital ability of the Restricted Subsidiaries (as defined in the indenture governing the senior notes to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business. Resources

~~Under~~Our ~~the~~principal ~~terms~~requirements ~~of the indenture~~ for ~~the~~capital ~~senior~~are ~~notes,~~to iffund weour ~~experience~~day-to-day ~~certain specific change of control events~~operations, ~~unless~~development ~~the~~activities ~~Issuers~~and ~~have previously or concurrently exercised their right~~ to ~~redeem~~satisfy ~~all~~our ofcontractual ~~the~~obligations ~~senior~~related ~~notes under the optional redemption provision, such holder has the right~~ to ~~require~~servicing usour todebt ~~purchase such holder’s senior notes at 101% of the principal amount plus accrued~~ and ~~unpaid interest to the date of the purchase~~hedges. ~~The~~ During ~~closing of~~ the ~~Business~~2019 ~~Combination~~Quarter, ~~with~~our ~~AMR~~main ~~did~~sources ~~not constitute a change~~ of ~~control~~liquidity ~~under~~and ~~the~~capital ~~indenture~~resources ~~governing~~came ~~the~~from ~~senior~~operating ~~notes~~cash ~~because~~flow ~~certain existing owners of the Company~~ and ~~SRII~~borrowings ~~Opco~~under ~~entered into an amended and restated voting agreement with respect to~~ the ~~voting~~Alta ~~interests~~Mesa ~~in AMH GP~~RBL. ~~See Note 5 — Business Combination to the consolidated condensed financial statements for further detail.~~

The indenture contains customary events of default, including:

• default in any payment of interest on the senior notes when due, continued for 30 days;

• default in the payment of principal or premium, if any, on the senior notes when due;

• failure by the Issuers or any subsidiary guarantor to comply with its obligations under the indenture;

• default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Issuers or restricted subsidiaries;

Table of Contents

•Index ~~certain~~to ~~events~~Financial ~~of bankruptcy, insolvency or reorganization of the Issuers or restricted subsidiaries; and~~Statements

•During ~~failure~~April by2019, our borrowing base was reduced from $400.0 million to $370.0 million as part of the ~~Issuers~~semi-annual orredetermination. We ~~certain~~currently ~~subsidiaries~~have outstanding borrowings of approximately $350.0million and outstanding letters of credit of $20.0 million, leaving us no additional remaining borrowing capacity. We had $93.7 million of cash at May 31, 2019. We have not obtained covenant relief, but that ~~would~~remains ~~constitute~~an aimportant ~~payment~~objective for us. As referenced above, we may be at risk of ~~final~~non-compliance ~~judgment~~with ~~aggregating~~the Consolidated Total Leverage Ratio Covenant in the Alta Mesa RBL as early as the June 30, 2019 measurement date. In addition, the lenders under the Alta Mesa RBL have an ability to make an optional redetermination ahead of the regular redetermination in October 2019. If the outstanding borrowings under the Alta Mesa RBL were to exceed the borrowing base due to any such redetermination, we would be required to repay the excess ratably over five months, which could have an adverse impact on our liquidity. Our general partner’s board and our parent’s board of ~~$20~~directors ~~million~~and its financial advisors are evaluating the available financial alternatives, including, without limitation, seeking amendments or waivers to the covenants or other provisions of our indebtedness, raising new capital from the private or public markets or taking other actions to address our capital structure. If we are unable to reach an agreement with our lenders or find acceptable alternative financing, it may lead to an event of default under the Alta Mesa RBL. If following an event of default, the Alta Mesa RBL lenders were to accelerate repayment, it may result in an event of default and an acceleration under the 2024 Notes. We have concluded that these circumstances create substantial doubt regarding our ability to continue as a going concern. Assuming covenant relief can be obtained, we believe that our combined future operating cash flow and cash currently on our balance sheet will be sufficient to allow us to carry out our desired 2019 development program, despite the associated negative free cash flow. Our ability to reduce well costs and to more precisely assess the productivity of wells under our new spacing design tests are important to our success in 2019 as we evaluate our future prospects and opportunities.

IfOur anfuture ~~event~~drilling plans and capital budgets are subject to change based upon various factors, some of ~~default~~which ~~occurs~~are beyond our control, including drilling results, oil and isgas ~~continuing~~prices, the ~~holders~~availability and cost of ~~such~~capital, ~~indebtedness~~drilling ~~may~~and ~~elect~~production tocosts, ~~declare~~availability ~~all~~of ~~the~~drilling ~~funds~~services ~~borrowed~~and toequipment, bemidstream ~~immediately~~availability, ~~due~~other ~~and~~working ~~payable~~interest ~~with~~owner ~~accrued~~participation and ~~unpaid~~regulatory ~~interest~~matters. ~~Borrowings~~ ~~under~~Any ~~other~~deferral ~~debt~~of ~~instruments~~planned ~~that~~capital ~~contain~~expenditures, ~~cross-acceleration~~particularly orwith ~~cross-default~~respect ~~provisions~~to ~~may~~bringing ~~also~~new bewells ~~accelerated~~onto production, could reduce our anticipated production, revenue and ~~become~~cash ~~due~~flow, and ~~payable~~may result in the expiry of certain leases. However, because a large percentage of our acreage is held by production, we can alter our drilling program to minimize the risk of losing significant acreage.

AsWe ofstrive ~~September 30,~~to ~~2018~~maintain financial flexibility and, if they are available to us on terms we ~~were~~find inacceptable, ~~compliance~~may ~~with~~access the ~~indentures~~capital ~~governing~~markets ~~the~~to ~~senior~~facilitate ~~notes~~our development program, to selectively expand our acreage position or to redesign our capital structure. If our operating cash flow is materially less than anticipated and other sources of capital are not available on acceptable terms, we may decide to curtail our capital spending.

~~Bond~~We ~~Premium~~expect ~~(Successor).~~to Asoperate ~~discussed~~2-3 inrigs ~~Note~~during 52019 to develop our assets, particularly to focus on testing the ~~fair~~spacing ~~value~~patterns ofwe ~~our~~believe ~~senior~~to ~~notes~~be asoptimal, ofand ~~the~~to ~~acquisition~~implement ~~date~~cost ~~was~~reduction ~~$533.6~~strategies ~~million~~begun earlier in 2019. ~~The~~ If ~~bond~~we ~~premium~~have ofadequate ~~$33.6~~liquidity ~~million~~to isfund ~~being~~such ~~amortized~~operations, ~~over~~we ~~the~~expect ~~respective~~to ~~term~~drill ofand ~~the~~bring ~~senior~~online ~~notes~~approximately 60 wells during 2019 while incurring approximately $140. ~~The~~0 ~~bond~~million ~~premium~~to ~~amortization~~$155.0 ~~recognized~~million inof ~~interest~~capital ~~expense~~expenditures ~~was~~related to this development program. We also expect that an additional $118.20 million ~~and~~to $323.30 million ~~for~~could ~~the~~be ~~three~~incurred ~~months~~for ~~ended~~non-operated ~~September 30~~projects, ~~2018~~leasehold ~~(Successor)~~costs and ~~the~~capitalized ~~Successor~~workover ~~Period, respectively~~activity. ~~The~~We ~~unamortized~~do ~~bond~~not ~~premium~~expect ~~related~~our to2019 ~~the~~operating ~~senior~~cash ~~notes~~flow isalone ~~included~~to asprovide asufficient ~~component~~proceeds to meet this level of ~~long-term~~expenditure, ~~debt~~which inwill ~~the~~require ~~condensed~~us ~~consolidated~~to ~~balance~~most ~~sheet~~likely asutilize ofexisting ~~September 30,~~cash ~~2018~~on hand.

~~Deferred financing costs.~~ As ofwe ~~December 31,~~execute ~~2017~~our ~~(Predecessor)~~business strategy, we ~~had~~will ~~$11.4~~continually ~~million~~monitor ofthe ~~unamortized~~capital ~~deferred~~resources ~~financing~~available ~~costs related~~ to ~~both~~meet ~~our~~future ~~senior~~financial ~~secured~~obligations ~~notes~~ and ~~the~~planned ~~Eighth~~capital ~~A&R credit facility~~expenditures. As We abelieve ~~result of the Business Combination,~~ our ~~unamortized~~cash ~~deferred~~flows ~~financing~~provided ~~costs~~by ~~were~~operating ~~adjusted~~activities toand aavailable ~~fair~~cash ~~value~~on ofhand ~~zero~~will atallow ~~February~~us ~~9, 2018. During the Successor Period, we incurred additional deferred financing costs related~~ to ~~the~~pursue ~~Eighth~~our ~~A&R~~currently ~~credit~~planned ~~facility~~development ~~of $1~~activities.4 We ~~million. These~~cannot ~~costs~~provide ~~are~~assurance ~~reflected~~that as deferred financing costs, net in other noncurrent assets in the condensed consolidated balance sheets as of September 30, 2018 (Successor). The amortization of the deferred financing costs is included in interest expense in the consolidated statements of operations~~. For~~ ~~the three months ended September 30, 2018 (Successor)~~ and ~~2017~~other ~~(Predecessor),~~needed ~~the~~capital ~~amortization~~will ofbe ~~deferred~~available ~~financing~~on ~~costs~~acceptable ~~was $0.1 million and $0.7 million~~terms, ~~respectively. For~~or ~~the~~at ~~Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, the amortization of deferred financing costs was $0~~all.~~2 million, $0.2 million and $2.2 million, respectively.~~

NOTE 12 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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

໿

	Successor		Predecessor
	September 30, 2018		December 31, 2017
Accruals for capital expenditures	$	83,687	$	48,771
Revenues and royalties payable	44,626		29,514
Accruals for operating expenses/taxes	8,156		14,632
Accrued interest	11,651		2,587
Derivative settlement payable	4,593		2,106
Other	3,408		4,301
Total accrued liabilities	156,121		101,911
Accounts payable	71,018		68,578
Accounts payable and accrued liabilities	$	227,139	$	170,489

NOTE 13 — COMMITMENTS AND CONTINGENCIES

Commitments

We lease office space and certain field equipment such as compressors, under long-term operating lease agreements. On April 1, 2018, we amended the lease agreement for our corporate headquarters located in Houston, Texas. The amended lease agreement provides for additional office space and extends the original lease term through April 2028. Due to the amendment, we have additional lease commitment obligations of approximately $17.6 million through April 2028. Any initial rent-free months are amortized over the life of the lease.

The Company has entered into certain firm transportation contracts that extend through 2028. At September 30, 2018, the future minimum commitments related to these contracts were approximately $5.7 million a year.

Contingencies

Environmental claims. Various landowners have sued us in lawsuits concerning several fields in which we have, or historically had, operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our condensed consolidated financial statements at September 30, 2018.

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

Litigation (Predecessor). On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our former subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish. Plaintiffs claimed they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located. Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. In connection with the Business Combination, the liability was included in the distribution of our non-STACK assets to the AM Contributor.

On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP and Alta Mesa Services, LP, each a wholly owned subsidiary, and us (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty. The suit alleged that the AMH Parties made improper post production deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells. The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case. In June 2017, the court administratively closed the case following mediation. As of December 31, 2017, we had accruals of approximately $4.7 million in accounts payable and accrued liabilities in our condensed consolidated balance sheets and in G&A in our condensed consolidated statements of operations as a result of this litigation. During January 2018, approximately $4.7 million was paid to fund the settlement. On March 12, 2018, the class settlement was approved by the Court.

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

Other contingencies. We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

Performance appreciation rights. In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan was intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants were granted performance appreciation rights (“PARs”) with a stipulated initial designated value. The Company accelerated the vesting and payment of all outstanding PARs in connection with the Business Combination with AMR as described in Note

Table of Contents

~~5. The~~Index ~~value~~to ofFinancial ~~the PARs that vested was approximately $10.9 million and such amount was recorded in G&A in the Successor Period. Following the closing of the Business Combination, the Plan was terminated.~~Statements

~~Nonqualified~~Cash ~~Deferred~~flow Compensation. In 2013, we established a nonqualified deferred compensation plan, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”). The Retirement Plan was intended to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees. In connection with the Business Combination, we terminated the Retirement Plan resulting in approximately $9.4 million being recorded in G&A in the Successor Period. Analysis

NOTE 14 — SIGNIFICANT RISKS AND UNCERTAINTIES



	Successor						Predecessor
(in thousands)	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Cash from operating activities	$	29,935		$	(49,311	)	$	26,336
Cash from investing activities	(133,077		)	(129,310		)	(37,913		)
Cash from financing activities	117,000			425,272			16,932
Net increase in cash, cash equivalents and restricted cash	$	13,858		$	246,651		$	5,355

~~Our~~Cash ~~business~~flow ~~makes~~from usoperating vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Declines in oil and/or natural gas prices or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil, natural gas, and natural gas liquids price derivative contracts. See Note 9 — Derivative Financial Instruments for further details on derivatives.activities

NOTE 15 — PARTNERS’ CAPITAL



	Successor						Predecessor
(in thousands)	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Cash-based items of net income (loss)	$	35,681		$	448		$	980
Changes in working capital and other assets and liabilities	(5,746		)	(49,759		)	25,356
Cash from operating activities	$	29,935		$	(49,311	)	$	26,336

~~Management~~During ~~and~~the ~~Control: Our~~2019 ~~Seventh~~Quarter, ~~Amended~~cash-based ~~and~~items ~~Restated~~of ~~Agreement~~net ofincome ~~Limited~~(loss), ~~Partnership~~including revenue (~~the~~exclusive ~~“Seventh~~of ~~Amended~~unrealized ~~Partnership~~commodity ~~Agreement”~~gains or losses), ~~currently~~operating ~~provides~~expenses ~~for~~and ~~interests~~taxes, togeneral beand ~~divided~~administrative ~~into~~expenses, ~~economic~~and ~~units~~the ~~held~~cash byportion ~~the~~of ~~partners~~our ~~referred~~interest toexpense were $35.7 million as ~~“LP~~compared ~~Units”~~to $1.4 million during the 2018 Quarter. Changes in working capital and ~~non-economic~~other ~~general~~assets ~~partner~~and ~~interests~~liabilities ~~owned~~resulted byin ~~AMH~~a GPdecrease ~~referred~~in tocash asof ~~“GP~~approximately ~~Units”~~$5. ~~AMH~~7 GPmillion ~~owns~~as ~~all~~compared to a decrease of $24.4 million during the GP2018 ~~Units~~Quarter. ~~and~~The increase in ~~connection~~cash ~~with~~from ~~the~~operating activities of $52.9 million is primarily related to Business Combination, ~~SRII~~Costs ~~Opco~~of ~~owns~~$40.7 ~~all~~million incurred in the LP2018 ~~Units~~Quarter. In addition, the 2018 Quarter included net loss from Discontinued Operations of $7.7 million.

AsCash aflow ~~limited~~from ~~partnership,~~investing ~~our operations and~~ activities are managed by the board of directors (the “Board of Directors”) of our general partner, AMH GP. The limited liability company agreement of AMH GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic interests in AMH GP and (ii) Class B Units, which hold 100% of the voting interests in AMH GP.

SRII Opco is the sole owner of Class A Units and owns 90% of the Class B Units. Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, the founder, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company, and HPS Investment Partners, LLC, a Delaware limited liability company, own an aggregate 10% of the Class B Units. AMH GP’s Board of Directors are selected by the Class B members. Notwithstanding the foregoing, voting control of AMH GP is vested in SRII Opco pursuant to a voting agreement.



	Successor						Predecessor
(in thousands)	Three Months Ended March 31, 2019			February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Cash provided by (used for)
Capital expenditures	$	(133,077	)	$	(129,310	)	$	(36,695	)
Acquisition of acreage	—			—			(1,218		)
Cash from investing activities	$	(133,077	)	$	(129,310	)	$	(37,913	)

~~The~~During ~~Seventh Amended Partnership Agreement specifies~~ the ~~manner~~2019 inQuarter, ~~which~~cash wespent ~~will~~for ~~make~~capital ~~cash~~expenditures ~~distribution~~included ~~to our partners~~$84. ~~When~~2 ~~AMH~~for GPadditions soto ~~directs,~~property weand ~~shall~~equipment ~~make~~that ~~distributions~~occurred ofprior ~~Net Cash Flow (as defined in the Seventh Amended Partnership Agreement)~~ to ~~the~~December 31, ~~limited partner~~2018.

~~NOTE~~Cash 16flow —from ~~EQUITY-BASED~~financing ~~COMPENSATION (Successor)~~activities

Following the closing of the Business Combination, AMR adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”). A total of 50,000,000 shares of AMR’s Class A Common Stock were reserved for issuance under the LTIP. The LTIP provides for the grant of stock options, including incentive stock options (“ISOs”), nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other stock-based awards in AMR’s Class A Common Stock. Prior to the Business Combination, we did not have any equity-based compensation programs. Pursuant to the LTIP, certain grants of stock-based awards have been made to various employees of the Company since February 9, 2018. During the Successor Period, we recognized non-cash stock-based compensation expense of $6.7 million resulting from stock options, restricted stock, and RSUs awards granted to our employees, which is included in general and administrative expense in the accompanying condensed consolidated statements of operations. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.

Table of Contents

WeIndex ~~recognize compensation expense on a straight-line basis for service-based grants~~ to ~~our~~Financial employees over the vesting period. The fair value of restricted stock awards and performance-based restricted stock units is determined based on the estimated fair market value of AMR’s Class A Common Stock on the date of grant. As provided in ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, the Company has elected to recognize actual forfeitures as they occur. Statements

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



	Successor					Predecessor
(in thousands)	Three Months Ended March 31, 2019		February 9, 2018 Through March 31, 2018			January 1, 2018 Through February 8, 2018
Cash provided by (used for)
Proceeds from long-term debt borrowings	$	117,000	$	—		$	60,000
Repayments of long-term debt	—		(134,065		)	(43,000		)
Capital contributions (distributions), net	—		560,344			(68		)
Other	—		(1,007		)	—
Cash from financing activities	$	117,000	$	425,272		$	16,932

~~Information~~During ~~about~~the ~~outstanding~~2019 ~~stock~~Quarter, ~~options~~our isoutstanding ~~summarized~~balance inowed under the ~~table~~Alta ~~below:~~Mesa RBL increased by $117.0 million from December 31, 2018 largely related to borrowings to fund of our capital expenditures.

	Successor
	Stock Options		Weighted Average Grant - Date Fair Value		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of February 9, 2018	—		$	—	—
Granted	4,704,433		4.45		—
Exercised	—		—		—
Forfeited or expired	(94,693	)	4.52		—
Outstanding as of September 30, 2018	4,609,740		$	4.44	6.4	$	—
Exercisable as of September 30, 2018	—		$	—	—	$	—

Immediately following the Business Combination on February 9, 2018, we received a capital contribution from our immediate parent, SRII Opco, of $560.3 million, a portion of which was used to fund additional capital expenditures and to increase working capital.

~~Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable three-year vesting period~~Item 3. ~~The~~ ~~Company~~Quantitative estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and isQualitative ~~estimated~~Disclosures asabout ~~the~~Market ~~average of the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.~~Risk

~~The~~We ~~following~~are ~~summarizes~~exposed ~~the~~to ~~assumptions~~certain ~~used~~market torisks ~~determine~~that are inherent in our financial statements that arise in the ~~fair~~normal ~~value~~course of ~~those~~business. ~~options:~~We may enter into derivatives to manage or reduce market risk, but we do not enter into derivatives for speculative purposes. We do not designate derivatives as hedges for accounting purposes.

໿Commodity Price Risk and Hedges

	Successor
	February 9, 2018 Through September 30, 2018
Expected term (in years)	4.5
Expected stock volatility	64.6	%
Dividend yield	—
Risk-free interest rate	2.4	%

We forecast our future production based on information in our December 31, 2018 reserve report for all reserve categories using estimates for future pricing, costs and other assumptions that may prove to be inaccurate. Our actual production will vary from the amounts estimated in the report, perhaps materially.

AsOur ofmajor ~~September 30~~market risk exposure is associated with prices for oil, ~~2018~~gas and NGLs, ~~there~~which ~~was~~have ~~$16~~historically been volatile.2 ~~million~~As ofsuch, ~~unrecognized~~future ~~compensation~~results ~~cost~~are ~~related~~subject to ~~non-vested~~change ~~stock~~due ~~options~~to changes in these prices. ~~The~~ ~~Company~~Realized ~~expects~~prices toare ~~recognize~~primarily ~~that~~driven ~~cost~~by onthe aprevailing ~~pro~~worldwide ~~rata~~price ~~basis~~for ~~over~~oil aand ~~weighted~~regional ~~average~~prices ~~period~~for gas. We have used, and expect to continue to use, derivatives to reduce our exposure to the risks of 2price changes.4 ~~years~~Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated with developed and undeveloped reserves.

~~Restricted~~The ~~stock. Restricted~~fair ~~stock~~value ~~granted~~of toour ~~employees~~oil ~~generally~~and ~~vests~~gas derivatives and basis swaps at March 31, 2019 was a net liability of $6.7 million. A 10% increase or decrease in ~~one-third~~oil ~~increments~~and ~~each~~gas ~~year~~prices on(with ~~the~~all ~~anniversary~~other ~~date~~factors ~~following~~held ~~the~~constant) ~~date~~would ofresult ~~grant,~~in ~~based~~an onunrealized ~~continued~~loss ~~employment. Prior~~or togain ~~vesting,~~in nothe ~~dividends~~fair ~~are~~value ~~paid~~of our oil and gas derivatives for the ~~shares~~2019 ~~may~~Quarter ~~not~~of be$24,429 ~~traded~~and $9,820, respectively.

Counterparty and Customer Credit Risk

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

Our principal ongoing exposures to credit risk are from joint interest receivables and receivables from the sale of our oil and gas production. The inability or failure of our customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our purchasers of production and other working interest owners is high.

During the first quarter of 2019 and 2018, ARM marketed our oil, gas and NGLs. Effective as of June 1, 2019, we have terminated our oil and NGL marketing agreement with ARM and will market such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019. In March 2019, in preparation for the return of

Table of Contents

~~The~~Index ~~following~~to ~~table~~Financial ~~provides information about restricted stock awards granted during the Successor Period:~~Statements

໿oil and NGL marketing responsibilities to us, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. However, with respect to gas sales, ARM continues to collect payments from purchasers, deducts their marketing fee and remits the balance to us.

	Successor
	Restricted Stock Awards		Weighted Average Grant Date Fair Value per share
Outstanding as of February 9, 2018	—		$	—
Granted	1,658,756		7.77
Vested	—		—
Forfeited or expired	(42,086	)	8.74
Outstanding as of September 30, 2018	1,616,670		$	7.75

For the 2019 Quarter, ARM marketed $83.8 million, or 71.9% of our operating revenue for the period.

~~Compensation~~Joint ~~cost~~operations ~~for~~receivables ~~restricted~~arise ~~shares~~from isbillings ~~based~~to ~~upon~~entities ~~the~~that ~~grant-date~~own ~~market~~interests ~~value~~in of the ~~award,~~wells ~~recognized~~we ~~ratably~~operate. ~~over~~These ~~the~~entities ~~applicable~~participate ~~three-year~~in ~~vesting~~our ~~period,~~wells ~~subject~~primarily tobased ~~the~~on ~~employee’s~~their ~~continued~~ownership ~~service. Unrecognized~~in ~~compensation~~leases ~~cost~~on ~~related~~which towe ~~unvested~~intend ~~restricted~~to ~~shares at September 30, 2018 was $10~~drill.1 ~~million,~~We ~~which~~have ~~the~~little ~~Company~~ability ~~expects~~ to ~~recognize~~control ~~over~~whether athese ~~weighted~~entities ~~average~~will ~~remaining~~participate ~~period~~in ofour 2wells.~~5 years.~~

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

~~The~~We ~~following~~are ~~summary~~subject ~~provides~~to ~~information~~interest ~~about~~rate risk under the ~~target~~Alta ~~number~~Mesa ofRBL. We ~~PSUs~~currently ~~granted~~have ~~during~~no open interest rate derivatives. A 100 basis point increase in interest rates would increase annual interest expense on the ~~Successor~~Alta ~~Period:~~Mesa RBL by approximately $2.8 million, based on the balance outstanding at March 31, 2019.

	Successor
	PSUs			Weighted Average Grant - Date Fair Value per unit
Outstanding as of February 9, 2018	—			$	—
Granted	781,200			8.69
Vested	—			—
Forfeited or expired	(4,174	)		8.45
Outstanding as of September 30, 2018	777,026		—	$	8.69

Inflation

AsInflation ofin ~~September 30,~~the ~~2018,~~United ~~there~~States ~~was~~has nobeen relatively low in recent years and did not have a material ~~unrecognized~~impact ~~compensation~~on ~~cost~~our ~~related~~results toof operations for the ~~unvested~~2019 ~~PSUs~~Quarter. Although the impact of inflation has been insignificant in recent years, it could cause future upward pressure on the cost of oilfield services, equipment and general and administrative expenses.

~~NOTE~~Item 4. 17Controls —and ~~RELATED PARTY TRANSACTIONS~~Procedures

OnEvaluation January 13, 2016, Alta Mesa’s wholly owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “Joint Development Agreement”), with BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City, to fund a portion of ~~Alta~~Disclosure ~~Mesa’s~~Controls ~~drilling operations~~ and to allow Alta Mesa to accelerate development of our STACK acreage. The Joint Development Agreement, as amended, establishes a development plan of 60 wells in three tranches, and provides opportunities for the parties to potentially agree to an additional 20 wells. Procedures

~~Pursuant~~As torequired ~~the~~by ~~terms~~Rules 13a-15 and ~~provisions~~15d-15 of the ~~Joint~~Exchange ~~Development Agreement~~Act, ~~BCE~~our ~~committed~~management, towith ~~fund~~the ~~100%~~participation of ~~Alta~~our ~~Mesa’s~~principal ~~working~~executive ~~interest~~officer ~~share~~and upprincipal tofinancial aofficer, ~~maximum~~performed ~~average~~an ~~well~~evaluation ~~cost~~ of ~~$3.2~~our ~~million~~disclosure incontrols ~~drilling~~ and ~~completion~~procedures. ~~costs~~Our ~~per~~controls ~~well~~and ~~for~~procedures ~~any~~are ~~tranche,~~designed ~~subject~~ to ~~modifications~~ensure orthat ~~adjustments~~information ~~proposed~~required ~~and~~to ~~approved~~be disclosed by the ~~parties.~~Company Wein ~~are~~reports ~~responsible~~it ~~for~~files ~~any~~or ~~drilling~~submits ~~and~~under ~~completion costs exceeding approved amounts. In exchange for~~ the ~~payment~~Exchange ofAct ~~drilling~~is ~~and~~recorded, ~~completion~~processed, ~~costs~~summarized, ~~BCE~~and ~~receives~~reported ~~80%~~within ofthe ~~our~~time ~~working~~periods ~~interest~~specified in ~~each~~the ~~wellbore,~~rules ~~which~~and ~~BCE~~forms ~~interest~~of ~~will~~the beSEC, ~~reduced~~and tothat ~~20%~~the ofinformation ~~our~~required ~~initial~~to ~~working~~be ~~interest~~disclosed ~~upon~~by ~~BCE~~the ~~achieving~~Company ain ~~15%~~reports ~~internal~~that ~~rate~~it offiles ~~return~~or onsubmits under the ~~wells~~Exchange ~~within~~Act ais ~~tranche~~accumulated and ~~automatically~~communicated ~~further reduced~~ to ~~12.5%~~the ofCompany’s ~~our~~management, ~~initial~~including ~~interest~~the ~~upon~~principal ~~BCE~~executive ~~achieving~~officer aand ~~25%~~principal ~~internal~~financial ~~rate~~officer, ofas ~~return. Following the completion of each joint well~~appropriate, ~~Alta~~to ~~Mesa~~allow ~~and~~timely ~~BCE~~decisions ~~will~~regarding ~~each~~required ~~bear its~~ disclosure.

~~respective~~As ~~proportionate~~described ~~working~~further ~~interest~~in ~~share~~our of2018 ~~all~~Annual ~~subsequent~~Report ~~costs~~on ~~and~~Form ~~expenses related to such joint well. Mr. William McMullen~~10-K, ~~one~~we ofconcluded that our ~~former~~disclosure ~~directors,~~controls ~~is founder~~ and ~~managing~~procedures ~~partner~~were ofnot ~~BCE.~~effective ~~The~~as ~~approximate dollar value~~ of ~~the~~December ~~amount involved in this transaction~~31, ~~or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the~~ 2018 ~~Predecessor Period~~, ~~BCE~~due ~~advanced us approximately $39.5 million~~ to ~~drill~~existence ~~wells under the Joint Development Agreement. As~~ of ~~September 30,~~material ~~2018,~~weakness 55in ~~joint~~our ~~wells~~internal ~~have~~control ~~been~~over ~~drilled~~financial orreporting ~~spudded~~(“ICFR”). AsApart offrom ~~September 30,~~the ~~2018~~controls ~~(Successor),~~ and ~~December 31,~~procedures ~~2017~~relating ~~(Predecessor),~~to ~~$16.9~~accounting ~~million~~for ~~and~~business ~~$23.4 million~~combinations, ~~respectively,~~several of ~~net advances remaining from BCE for their working interest share of~~ the ~~drilling~~material ~~and~~weaknesses ~~development costs arising under the Joint Development Agreement were included as “Advances from related party”~~ in our ~~consolidated~~ICFR ~~balance~~continued ~~sheets. BCE may request refunds of certain advances from time~~ to ~~time~~exist ifduring ~~funded wells previously on~~ the ~~drilling~~2019 ~~schedule~~Quarter. These ~~were~~material ~~subsequently~~weaknesses ~~removed.~~ include:

On• ~~August 31,~~establishment 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with Kingfisher. The Gas Gathering and Processing Agreement was subsequently amended on February 3, 2017, effective as of ~~December~~formal 1,policies ~~2016,~~ and thereafter amended on June 29, 2018, effective as of April 1, 2018. The recent amendment to the Gas Gathering and Processing Agreement impacts our net NGL production volumes but will not impact our consolidated financial statements.procedures;

~~Effective~~• ~~June~~ineffective 1,monitoring ~~2018,~~activities wethat ~~entered~~span into a Marketing Services Agreement with ARM Energy Management, LLC (“AEM”) pursuant to which AEM markets our oil, natural gas and natural gas liquids and sells them under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location and quality taken into account. AEM remits monthly collections on these sales to us, and receives a marketing fee. In addition, AEM markets our firm transportation on the ~~ONEOK~~Company ~~Gas Transportation, L.L.C. system for an asset management fee. The AM Contributor owns less than 10% of AEM. For the period from June 1, 2018~~ to ~~September 30,~~ensure ~~2018,~~that weinternal ~~paid~~controls ~~AEM~~processes ~~$0.8~~are ~~million~~functioning ~~for our share of the marketing fees.~~ properly;

~~NOTE~~• 18ineffective —controls ~~SUBSIDIARY~~over ~~GUARANTORS~~the financial statement close and disclosure process; and

~~All~~• ofover-reliance ~~our~~on ~~wholly owned subsidiaries are guarantors under the terms of the senior notes~~ and ~~the~~ineffective ~~Eighth~~controls ~~A&R~~over ~~credit~~access ~~facility. Our condensed consolidated financial statements reflect the financial position of these subsidiary guarantors. As the parent company~~ to ~~these subsidiaries, we have no independent operations, assets, or liabilities. The guarantees are full~~ and ~~unconditional~~changes ~~(except~~involving ~~for~~critical ~~customary release provisions) and joint and several~~worksheets. Those subsidiaries which are not wholly owned by us and are not guarantors of our senior notes or our credit facility, are immaterial subsidiaries. There are no restrictions on dividends, distributions, loans or other transfers of funds from the subsidiary guarantors to us.

~~NOTE~~Changes 19in —Internal ~~SUBSEQUENT~~Control ~~EVENTS~~Over Financial Reporting (ICFR)

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

~~Effective~~During ~~November 9, 2018,~~ the ~~Company~~2019 ~~sold its produced water assets~~Quarter, ~~consisting~~we ofhave ~~over~~made ~~200~~access ~~miles~~changes ofto ~~produced water gathering pipelines~~payroll, ~~and~~production ~~related facilities and equipment~~accounting, ~~along with 20 produced water disposal wells, surface leases, easements~~ and ~~other~~reserves ~~agreements,~~systems ~~net of related obligations,~~ to aaddress ~~subsidiary~~material ofweaknesses ~~Kingfisher~~identified ~~Midstream,~~during ~~LLC,~~2018. aTesting ~~related~~to ~~party~~be ~~and~~conducted ~~wholly~~later ~~owned~~in ~~subsidiary~~2019 ofwill ~~our~~determine ~~parent,~~whether ~~AMR,~~these ~~for~~changes ato ~~total~~system ~~purchase~~access ~~price~~will ofprove ~~$90.0~~effective ~~million~~ in ~~cash,~~remediating ~~subject~~the tounderlying ~~normal~~material ~~acquisition adjustments~~weakness. At

Table of Contents

~~September 30,~~Index ~~2018,~~to ~~the~~Financial net book value of long-lived assets associated with these operations totaled $86.9 million. In conjunction with the sale, the Company entered into a new fifteen-year water gathering and disposal agreement with Kingfisher Midstream. Statements

~~ITEM 2. Management’s~~PART ~~Discussion~~II ~~and~~- ~~Analysis~~OTHER ~~of Financial Condition and Results of Operations~~INFORMATION

~~The~~Item ~~following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes included elsewhere in this report~~1. InLegal addition, such analysis should be read in conjunction with the consolidated financial statements and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Annual Report”). The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements,” at the beginning of this Quarterly Report and in our 2017 Annual Report, particularly in the section titled “Risk Factors,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.Proceedings

~~Overview~~We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes cannot be reasonably estimated. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. There have been no significant changes during the 2019 Quarter to the matters described in Item 3. Legal Proceedings in our 2018 Annual Report on Form 10-K.

~~Alta~~Item Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent 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 Oklahoma1A. ~~Our~~ ~~activities~~Risk are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County (“STACK”). We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners.Factors

AsWe ofare ~~September 30,~~subject ~~2018,~~to wevarious ~~have~~risks ~~assembled~~and auncertainties ~~highly contiguous position of approximately 134,000 net acres~~ in the ~~up-dip,~~course ~~naturally-fractured oil portion~~ of ~~the~~our ~~STACK,~~business. ~~primarily~~There inhave ~~eastern~~been ~~Kingfisher~~no ~~County~~material ~~and~~changes ~~Major~~during ~~County, Oklahoma. Our drilling locations primarily target~~ the ~~Osage,~~2019 ~~Meramec~~Quarter ~~and Oswego formations. We continue~~ to ~~acquire acreage within and adjacent to our acreage footprint with~~ the ~~goal~~risk offactors ~~operating~~described ~~the~~under ~~drilling,~~Item ~~completion~~1A. ~~and~~Risk ~~production~~Factors ~~operations~~ in ~~such~~our ~~locations.~~2018 AtAnnual ~~present,~~Report weon ~~are~~Form ~~operating nine horizontal drilling rigs in the STACK~~10-K.

~~Additional~~Item ~~information relating to the acquisition of Alta Mesa by Alta Mesa Resources, Inc~~2. ~~and~~Unregistered ~~certain~~Sales ~~other transactions that occurred on February 9, 2018, may be found in Note 5 — Business Combination~~ of ~~the~~Equity ~~Notes~~Securities ~~to Condensed Consolidated Financial Statements. Immediately prior to the closing of the business combination described in Note 5, we also distributed our non-STACK assets~~ and ~~related~~Use ~~liabilities to High Mesa Holdings, LP (the “AM Contributor”), which is more fully described in Note 7 — Discontinued Operations (Predecessor)~~ of ~~the Notes to Condensed Consolidated Financial Statements, relating to discontinued operations.~~Proceeds

~~Outlook, Market Conditions and Commodity Prices~~None.

~~Our~~Item ~~revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, natural gas and natural gas liquids, which are beyond our control~~3. ~~The~~ ~~success~~Defaults ofUpon ~~our~~Senior ~~business is significantly affected by the price of oil due to our current focus on development of oil reserves and exploration for oil.~~Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

On June 10, 2019, Mr. Hackett resigned from the Board of Managers of our general partner. He will continue to serve as Executive Chairman of the Board and Interim Chief Executive Officer of our parent, AMR. Mr. Hackett’s decision to resign from the Board of Managers of our general partner was not due to any disagreement with the Company relating to the operations, practices or policies of the Company.

In addition, on June 10, 2019, Donald R. Dimitrievich, Sylvia J. Kerrigan, Pierre F. Lapeyre Jr., David M. Leuschen, William W. McMullen, Donald R. Sinclair, Jeffrey H. Tepper and Diana J. Walters were appointed as members of the Board of Managers of our general partner. On June 11, 2019, Patrick J. Bartels Jr. was appointed to the Board of Managers of our general partner. Pursuant to the terms of an independent manager agreement between Mr. Bartels and the Company, Mr. Bartels will serve as a Manager for an initial term of nine months and receive $25,000 per month for compensation for his services. The other Managers will not receive any compensation with respect to their service. The independent manager agreement also provides, among other things, that the Company will indemnify Mr. Bartels, subject to certain exceptions, to the fullest extent permitted by law. The foregoing description of the independent manager agreement is a summary only and is qualified in its entirety by reference to the independent manager agreement, which is filed as an Exhibit to this quarterly report and is incorporated by reference herein.

There are no arrangements or understandings between any of the new Managers and any other person pursuant to which they were elected as a Manager. There are no related party transactions involving the new Managers that are reportable under Item 404(a) of Regulation S-K. The Board of Managers does not currently have Committees; therefore, no Manager will be appointed to any Committees.

Table of Contents

~~Factors~~Index affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and it is uncertain whether the increase in market prices experienced in recent months will be sustained. As a result, we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues. If oil, natural gas and NGLs prices were to ~~significantly~~Financial 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 our borrowing capacity under the Eighth A&R credit facility. The following tables set forth the average New York Mercantile Exchange prices for oil and natural gas for the three and nine months ended September 30, 2018 and 2017:Statements

	Three Months Ended September 30,
	2018		2017	Change	%
Average NYMEX daily prices:
Oil (per bbl)	$	69.4

Filing Compare · Alta Mesa Holdings, LP