UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_____________________________________

FORM 10-Q

_____________________________________

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

For the quarterly period ended ~~March~~June 3130, 2019

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

For the transition period from ___ to___

Commission file number: 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)

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

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



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

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



Large accelerated filer	¨	Accelerated filer	¨	Non-accelerated filer	¨
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	2220
Item 3. Quantitative and Qualitative Disclosures about Market Risk	3135
Item 4. Controls and Procedures	3236
PART II - OTHER INFORMATION
Item 1. Legal Procedures	33
Item 1. Legal Proceedings	37
Item 1A. Risk Factors	3337
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	3337
Item 3. Defaults Upon Senior Securities	3337
Item 4. Mine Safety Disclosures	3337
Item 5. Other Information	3337
Item 6. Exhibits	3438
Signatures	3539

Table of Contents

Index to Financial Statements

Glossary of Terms

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

Company Specific Terms -
2018 10-K -	Alta Mesa Holdings, LP Annual Report on Form 10-K for the year ended December 31, 2018.
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.
AMR -	Alta Mesa Resources, Inc., our parent company.
ARM -	ARM Energy Management, LLC, a company that markets our oil and gas production and provides services relating to our derivatives.
BCE -	BCE-STACK Development LLC, a fund advised by Bayou City Management, LLC.
Business Combination -	The acquisition by Alta Mesa Resources, Inc. of controlling interests in Alta Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, and KFM Midstream, LLC.
High Mesa -	High Mesa Holdings, LP, a partnership formed in connection with executing the Business Combination.
HMI -	High Mesa, Inc., the predecessor owner of Alta Mesa Holdings, LP.
Predecessor Period -	The period from January 1, 2018 through February 8, 2018.
SRII Opco -	SRII Opco, LP is a subsidiary of Alta Mesa Resources, Inc. and direct owner of Alta Mesa Holdings, LP and Kingfisher Midstream, LLC.
Successor Period -	The period from February 9, 2018 through December 31, 2018, and all periods thereafter.
Oil, Gas and Other Terms -
Basin -	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
bbl -	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to describe volumes of crude oil, condensate or natural gas liquids.
bbld -	Barrels per day.
Bcf -	One billion cubic feet of natural gas.
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.
Development project -	A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Differential -	An adjustment to the market reference price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole -	A well found to be incapable of producing hydrocarbons in commercial quantities.
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

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.
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.
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.
Formation -	A layer of rock which has distinct characteristics that differs from adjacent rock.
Fracing, fracture stimulation technology, hydraulic fracturing -	A well stimulation technique to improve a well’s production by pumping a mixture of fluids into the formation to create hydraulic fractures which intersect existing natural fractures. As part of this technique, sand or other material may also be injected to keep the hydraulic fracture open, so that fluids or natural gases may more easily flow through the formation.
Gross acres or gross wells -	The total acres or wells in which a working interest is owned.
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.
Horizontal drilling -	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.
Lease operating expenses -	The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a well. Such expenses include labor, supplies, repairs, utilities, environmental and safety, maintenance, allocated overhead costs, severance taxes, insurance and other expenses incidental to production, but excluding lease acquisition, drilling or completion expenses.
Mbbl -	One thousand barrels of crude oil, condensate, natural gas liquids, or produced water.
Mbblsd -	One thousand barrels per day.
MBoe -	One thousand boe.
MBoed -	One thousand boe per day.
Mcf -	One thousand cubic feet of natural gas.
Mcfd -	One thousand cubic feet per day.
Mcfe -	One thousand cubic feet equivalent determined using the ratio of one barrel of oil, condensate or natural gas liquids to six Mcf of natural gas.
Mcfed -	Mcfe per day.
MMBbl -	One million barrels of crude oil, condensate or natural gas liquids.
MMBtu -	One million British thermal units.
MMBtud -	One million British thermal units per day.
MMcf -	One million cubic feet of natural gas.
MMcfd -	One million cubic feet per day.
Net acres -	The total acres a working interest owner has attributable to a particular number of acres, or a specified tract.
Net production -	Production that is owned by us after royalties and production attributable to other owners.
Net revenue interest -	A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interest.
NGLs or natural gas liquids -	Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline.
Non-operated working interests -	The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.
NYMEX -	The New York Mercantile Exchange.
PDNP -	Proved developed non-producing reserves.
PDP -	Proved developed producing reserves.
Predecessor Period	The period from January 1, 2018 through February 8, 2018.



Enhanced recovery -	The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.
Exploitation -	A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Formation -	A layer of rock which has distinct characteristics that differs from adjacent rock.
Fracing, fracture stimulation technology, hydraulic fracturing -	A well stimulation technique to improve a well’s production by pumping a mixture of fluids into the formation to create hydraulic fractures which intersect existing natural fractures. As part of this technique, sand or other material may also be injected to keep the hydraulic fracture open, so that fluids or natural gases may more easily flow through the formation.
Held by production -	Acreage covered by mineral leases that perpetuates a company’s right to operate a property usually requiring production to be maintained at a minimum paying quantity of production.
Horizontal drilling -	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.
Lease operating expenses -	The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a well. Such expenses include labor, supplies, repairs, utilities, environmental and safety, maintenance, allocated overhead costs, severance taxes, insurance and other expenses incidental to production, but excluding lease acquisition, drilling or completion expenses.
Mbbl -	One thousand barrels of crude oil, condensate, natural gas liquids, or produced water.
Mbblsd -	One thousand barrels per day.
MBoe -	One thousand boe.
MBoed -	One thousand boe per day.
Mcf -	One thousand cubic feet of natural gas.
Mcfd -	One thousand cubic feet per day.
MMBtu -	One million British thermal units.
MMBtud -	One million British thermal units per day.
MMcf -	One million cubic feet of natural gas.
MMcfd -	One million cubic feet per day.
Net acres -	The total acres a working interest owner has attributable to a particular number of acres, or a specified tract.
Net production -	Production that is owned by us after royalties and production attributable to other owners.
NGLs or natural gas liquids -	Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline.
Non-operated working interests -	The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.
NYMEX -	The New York Mercantile Exchange.
Prospect -	A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
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.
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.

Table of Contents

Index to Financial Statements

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.
Wellbore -	The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
Working interest -	The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs.
Workover -	Operations on a producing well to restore or increase production.

iii

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 Quarterly Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our ability to continue as a going concern, strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could”, “should”, “will”, “plan”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project,” the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” ~~included~~ in ~~Part II, Item 1A of~~ our Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 10-K”). These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about:

• our and our parent’s ability to continue as a going ~~concern~~concerns;

• the sufficiency of ~~our~~ liquidity ~~position~~ to ~~ensure financial flexibility and~~ fund our operations and capital expenditures;

• our ~~ability~~access to ~~comply~~capital, ~~with~~including orconstraints ~~otherwise~~from ~~obtain~~the ~~waivers~~cost ofand ~~the~~availability ~~covenants~~of indebt ~~our~~and ~~debt~~equity ~~agreements~~financing;

• our ~~business~~ability ~~strategy~~to comply with, or amend the terms of, the covenants and restrictions imposed by our debt agreements, including our ability to repay amounts borrowed under the Alta Mesa RBL that exceed the current borrowing base;


•	our ability to execute our stated business strategy;


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


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


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


•	our drilling, completion and production technology;

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


•	future oil and gas prices;


•	the supply and demand for our production;


•	the timing and amount of our future production;

• our hedging strategy and ~~ability to continue hedging~~ expected results;


•	competition and government regulation;


•	our ability to obtain permits and governmental approvals;

• expected or anticipated regulatory changes, inincluding to 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 our production;


•	our leasehold or business acquisitions;


•	our costs of developing our properties;


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


•	general economic conditions;

• operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, natural gas liquids, and crude oil;


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


•	the costs, terms and availability of midstream services;

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

• our ~~ability~~plans, toobjectives, ~~collect~~expectations ~~receivables~~and ~~from~~intentions ~~High~~contained ~~Mesa~~in this Quarterly Report that are not historical.

We caution you that any forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, 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

Index to Financial Statements

agreements, the timing of development expenditures, managing our growth and integration of acquisitions, cyber-attacks, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties, and the other risks described in ~~Item 1A.~~ Risk Factors of our ~~Annual Report on Form 10-K for the year ended December 31,~~ 2018 ~~(the “2018~~ 10-K”).

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

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

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

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Index to Financial Statements

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

ALTA MESA HOLDINGS, LP ~~AND SUBSIDIARIES~~

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(in thousands)

	Successor						~~Predecessor~~						Predecessor
	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 8, 2018
	Three Months EndedJune 30, 2019			Three Months EndedJune 30, 2018			Six Months EndedJune 30, 2019			February 9, 2018ThroughJune 30, 2018			January 1, 2018ThroughFebruary 8, 2018
Revenue
Oil	$	8690,~~363~~668		$	4075,~~278~~291		$	30177,~~972~~031		$	115,569		$	30,972
Natural gas	1812,~~450~~384			57,~~210~~980			430,~~276~~834			13,190			4,276
Natural gas liquids	1110,~~216~~251			410,~~714~~241			421,~~000~~467			14,955			4,000
Other	~~568~~330			~~555~~2,229			~~888~~898			2,784			888
Operating revenue	~~116~~113,~~597~~633			5095,~~757~~741			40230,~~136~~230			146,498			40,136
Gain on sale of assets	1,483			5,139			840
Gain (loss) on sale of assets	—			(63		)	1,483			5,076			840
Gain (loss) on derivatives	~~(23~~12,~~777~~412		)	(2229,~~011~~219		)	6(11,~~663~~365		)	(51,230		)	6,663
Total revenue	94126,~~303~~045			3366,~~885~~459			47220,~~639~~348			100,344			47,639
Operating expenses
Lease operating	2519,~~108~~123			812,~~317~~679			444,~~408~~231			20,996			4,408
Transportation and marketing	1719,~~761~~614			511,~~582~~206			337,~~725~~375			16,788			3,725
Production taxes	5,~~483~~117			12,~~415~~606			~~953~~10,600			4,021			953
Workovers	~~197~~412			~~1,245~~333			~~423~~609			1,578			423
Exploration	23,~~054~~289			18,~~585~~083			75,~~003~~343			9,668			7,003
Depreciation, depletion and amortization	34,~~675~~504			1126,~~038~~670			1169,~~670~~179			37,708			11,670
General and administrative	20,947			34,654			21,234
Impairment of assets	6,500			—			6,500			—			—
Total operating expenses	106,225			63,836			49,416
General and administrative	15,723			17,811			36,670			52,465			21,234
Operating income	(11,922		)	(29,951		)	(1,777		)
Total operating expenses	104,282			79,388			210,507			143,224			49,416
Other income (expense)
Operating income	21,763			(12,929		)	9,841			(42,880		)	(1,777		)
Interest expense	(12,830		)	(5,196		)	(5,511		)
Other income (expense)
Interest income and other	27			546			172
Interest expense	(14,071		)	(10,361		)	(26,901		)	(15,557		)	(5,511		)
Total other expense, net	(12,803		)	(4,650		)	(5,339		)
Interest income and other	54			820			81			1,366			172
Loss from continuing operations	(24,725		)	(34,601		)	(7,116		)
Total other expense, net	(14,017		)	(9,541		)	(26,820		)	(14,191		)	(5,339		)
Loss from discontinued operations, net of tax	—			—			(7,746		)
Income (loss) from continuing operations before income taxes	7,746			(22,470		)	(16,979		)	(57,071		)	(7,116		)
Net loss	$	(24,725	)	$	(34,601	)	$	(14,862	)
Income tax provision (benefit)	—			7			—			7			—
Income (loss) from continuing operations	7,746			(22,477		)	(16,979		)	(57,078		)	(7,116		)
Loss from discontinued operations, net of tax	—			—			—			—			(7,746		)
Net income (loss)	$	7,746		$	(22,477	)	$	(16,979	)	$	(57,078	)	$	(14,862	)

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

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Index to Financial Statements

ALTA MESA HOLDINGS, LP ~~AND SUBSIDIARIES~~

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands)

໿

	March 31, 2019		December 31, 2018
	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	2778,~~045~~275	$	12,984
Restricted cash	~~798~~890		1,001
Accounts receivable, net	6561,~~403~~662		68,370
Other receivables	23,~~239~~530		6,267
Related party receivables, net	1713,~~126~~149		24,282
Notes receivable from related party, net	—		—
Notes receivable from related parties, net	—		—
Prepaid expenses and other current assets	4,~~549~~623		747
Derivatives	—4,727		16,423
Total current assets	~~117~~166,~~160~~856		130,074
Property and equipment
Property and equipment, net
Oil and gas properties, successful efforts method, net	777,750		763,337
Oil and gas properties, successful efforts method	784,079		763,337
Other property and equipment, net	38,099		38,147
Other property and equipment	37,371		38,147
Total property and equipment, net	815,849		801,484
Total property and equipment	821,450		801,484
Other assets
Operating lease right-of-use assets, net	147,~~758~~871		—
Deferred financing costs, net	1,~~115~~021		1,151
Deposits and other long-term assets	4838		63
Derivatives	~~461~~2,508		2,947
Total other assets	1611,~~382~~438		4,161
Total assets	$	~~949~~999,~~391~~744	$	935,719

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

	March 31, 2019			December 31, 2018
	June 30, 2019			December 31, 2018
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	108,666		$	197,064
Current portion of debt	$	871,162		$	—
Accounts payable - related party	481			3,425
Accounts payable and accrued liabilities	91,694			197,064
Advances from non-operators	2,367			5,193
Accounts payable - related party	222			3,425
Advances from related party	4,479			9,822
Advances from non-operators	1,755			5,193
Asset retirement obligations	48			2,079
Advances from related party	4,003			9,822
Current operating lease liability	895			—
Asset retirement obligations	44			2,079
Derivatives	5,057			1,710
Current operating lease liability	938			—
Total current liabilities	121,993			219,293
Derivatives	840			1,710
Total current liabilities	970,658			219,293
Long-term liabilities
Asset retirement obligations, net of current portion	1112,~~750~~293			9,330
Long-term debt, net	~~805,892~~—			690,123
Operating lease liabilities, net of current portion	13,~~962~~733			—
Derivatives	~~2,065~~189			180
Total long-term liabilities	~~833~~26,~~669~~215			699,633
Total liabilities	~~955~~996,~~662~~873			918,926
Commitments and contingencies (Note 13)
Commitments and contingencies
Partners’ capital	(62,~~271~~871		)	16,793
Total liabilities and partners’ capital	$	~~949~~999,~~391~~744		$	935,719

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

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Index to Financial Statements

ALTA MESA HOLDINGS, LP ~~AND SUBSIDIARIES~~

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

(in thousands)

໿

	Predecessor
Balance, December 31, 2017	$	154,445
Distribution of non-STACK oil and gas assets, net of associated liabilities	43,482
Net loss	(14,862		)
Balance, February 8, 2018	$	183,065
	Successor
Balance, February 9, 2018	$	1,535,891
Contributions	560,344
Equity-based compensation expense	2,768
Net loss	(34,601		)
Balance, March 31, 2018	$2,064,402	~~2,064,402~~
Issuance of additional purchase consideration	9,467
Equity-based compensation expense	3,621
Distributions	(7,000		)
Net loss	(22,477		)
Balance, June 30, 2018	$	2,048,013
Balance, December 31, 2018	$	16,793
Equity-based compensation expense	1,661
Net loss	(24,725		)
Balance, March 31, 2019	$(6,271	~~(6,271~~	)
Equity-based compensation expense	1,396
Net income	7,746
Balance, June 30, 2019	$	2,871

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

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Index to Financial Statements

ALTA MESA HOLDINGS, LP ~~AND SUBSIDIARIES~~

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)

	Successor						Predecessor
	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 8, 2018
	Six Months EndedJune 30, 2019			February 9, 2018ThroughJune 30, 2018			January 1, 2018ThroughFebruary 8, 2018
Cash flows from operating activities:
Net loss	$	(2416,~~725~~979	)	$	(3457,~~601~~078	)	$	(14,862	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion, amortization and ARO accretion	34,675			11,038			12,554
Depreciation, depletion, amortization and accretion	69,179			37,708			12,554
Non-cash lease expense	991,587			—			—
Provision for uncollectible related party receivables	853			—			—
Provision for uncollectible receivables	1,177			—			—
Impairments	—			—			5,560
Impairment of assets	6,500			—			5,560
Amortization of deferred financing costs	45139			—80			171
Amortization of debt premium discount	(1,231		)	(820		)	—
Amortization of debt (premium) discount	(2,462		)	(2,051		)	—
Equity-based compensation expense	13,~~661~~057			26,~~768~~389			—
Expired leases	162			4,189			4,575
Non-cash exploration expense	388			10,658			4,575
(Gain) Loss on derivatives	23,777			22,011			(6,663		)
(Gain) loss on derivatives	11,365			51,230			(6,663		)
Cash settlements of derivatives	~~365~~909			(318,~~975~~334		)	(2,296		)
Premium paid on derivatives	(1,000		)	—			—
Interest converted into debt	—			—			103
Interest added to notes receivable from affiliate	—			(~~162~~417		)	(85		)
Loss on sale of fixed assets	—			—63			1,923
Impact on cash from changes in:
Accounts receivable	26,~~968~~384			3(2,~~097~~923		)	(21,184		)
Other receivables	42,~~029~~737			1,~~427~~426			(662		)
Receivables from affiliate and related party	6,303			(7,880		)	(117		)
Receivables from related parties	10,280			(18,494		)	(117		)
Prepaid expenses and other non-current assets	(3,~~787~~853		)	(27,~~240~~810		)	(591		)
Advances from related party	(5,~~344~~819		)	(710,~~008~~371		)	24,116
Settlement of asset retirement obligations	~~(147~~—		)	(~~166~~806		)	(63		)
Accounts payable to related party	(23,~~944~~203		)	(14,~~824~~994		)	—
Accounts payable, accrued liabilities and other liabilities	(617,~~824~~281		)	(3545,~~165~~385		)	23,857
Cash from operating activities	29,935			(49,311		)	26,336
Operating lease obligations	(1,287		)	—			—
Cash from operating activities	61,818			(45,489		)	26,336
Cash flows from investing activities:
Capital expenditures	(~~133~~180,~~077~~138		)	(~~129~~319,~~310~~042		)	(36,695		)
Acquisitions, net of cash acquired	—			—			(1,218		)
Cash from investing activities	(133,077		)	(129,310		)	(37,913		)
Proceeds from sale of assets	—			11,299			—
Cash from investing activities	(180,138		)	(307,743		)	(37,913		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	~~117~~183,~~000~~500			—			60,000
Repayments of long-term debt	—			(134,065		)	(43,000		)
Deferred financing costs paid	—			(1,~~007~~366		)	—
Capital distributions	—			—(7,000		)	(68		)
Capital contributions	—			560,344			—
Cash from financing activities	~~117~~183,~~000~~500			~~425~~417,~~272~~913			16,932
Net increase in cash, cash equivalents and restricted cash	1365,~~858~~180			~~246~~64,~~651~~681			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	$	2779,~~843~~165		$	~~256~~75,~~996~~026		$	10,345

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

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Index to Financial Statements

ALTA MESA HOLDINGS, LP ~~AND SUBSIDIARIES~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Alta Mesa Holdings, LP (“Alta Mesa” or “the Company”) 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 operations prior to February 9, 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 Business 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 the STACK. Prior to the closing of the Business Combination, we were controlled by High Mesa Inc. (“HMI”). The 2018 10-K contains substantially more information about our operations and the Business Combination.

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

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

~~Basis~~Going ~~of Presentation~~ Concern

~~All~~We ~~intercompany transactions and accounts have been eliminated. These interim condensed consolidated financial statements~~ are ~~unaudited,~~required ~~but~~to weevaluate ~~believe~~our ~~these~~ability ~~statements~~to ~~reflect~~continue ~~all~~as ~~adjustments necessary for~~ a ~~fair~~going ~~presentation~~concern for ~~the~~a ~~periods~~period ~~reported. All such adjustments are~~ of aone ~~normal,~~year ~~recurring~~following ~~nature unless otherwise disclosed. These financial statements and disclosures have been prepared in accordance with~~ the ~~SEC’s~~date ~~rules~~of ~~for~~issuance ~~interim~~of ~~financial~~our ~~statements and do not include all the information and disclosures required by generally accepted accounting principles (“GAAP”) for complete~~ financial statements. As ~~These~~part ~~financial~~of ~~statements~~that ~~should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three months ended March 31~~evaluation, ~~2019,~~we ~~are~~took ~~not~~into ~~necessarily~~consideration ~~indicative of~~ the ~~results~~following ~~to be expected for the full year. We have no items of other comprehensive income during any period presented.~~ factors:

~~Recently~~• ~~Issued~~Market ~~Accounting~~prices ~~Standards~~for ~~Applicable~~crude tooil Ushave declined since the Business Combination. This negatively impacted our future operating cash flow and lowers our expected future economic results from our assets compared with the time of the Business Combination.

~~Adopted~~• 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 and reduces the number of wells we expect to develop in the future compared with the time of the Business Combination. 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.

~~Effective~~• ~~January~~Although 1,our ~~2019,~~well wecosts ~~adopted~~for ~~ASU~~our ~~No.~~2019 ~~2016-02, Leases~~capital ~~(Topic~~program ~~842)~~have ~~(“ASU~~averaged ~~2016-02”),~~less ~~which~~than ~~requires~~$3.0 ~~that~~million ~~lessees~~per ~~recognize a lease liability~~well, ~~which~~we isstill aexpect ~~lessee’s~~our ~~discounted~~operating ~~obligation~~cash flow to ~~make~~be ~~payments~~less ~~under~~than aour ~~lease~~2019 ~~and a~~capital ~~right-of-use~~spending. ~~asset,~~Future ~~arising~~well ~~from~~costs aare ~~lessee’s~~expected ~~right~~ to ~~use~~increase anas ~~asset over the lease term. Upon adoption,~~ we ~~used~~move ~~the~~into ~~modified~~higher ~~retrospective~~cost ~~method~~areas ~~to apply the standard as~~ of ~~January~~our 1,acreage ~~2019~~which ~~for~~have ~~existing~~less ~~leases~~infrastructure ~~with terms~~ in ~~excess~~place ofand 12that ~~months~~may ~~entered~~require ~~into~~more ~~prior~~intense ~~to January 1, 2019~~completions.

~~Not~~• ~~Yet~~On ~~Adopted~~April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced to $370.0 million and we had no meaningful remaining capacity available thereunder at June 30, 2019. Without additional capital, we will only be able to utilize the cash on hand, which at July 31, 2019 was $79.7 million, to fund development and meet our financial obligations. 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. Also, the lack of sufficient capital may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceed the new borrowing base amount by $162.4 million, we have five months to make ratable payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. The first payment is due in September 2019. If we are unable to make this repayment, we will be in default under the Alta Mesa RBL. There is

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

Index to Financial Statements

~~the~~a ~~consolidated~~risk ~~statement~~that offuture ~~operations~~redeterminations ascould ~~the~~reduce ~~fees associated with~~ the ~~hosting~~borrowing ~~element~~base ~~of the arrangement~~further. Our ~~Similarly,~~decreased ~~capitalized~~borrowing ~~implementation~~base ~~costs~~could ~~are~~cause tous be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to ~~adopt~~reduce ~~and whether to apply the new standard retrospectively~~ or ~~prospectively~~abandon toour ~~implementation~~development ~~costs incurred after the date of adoption~~activities.

In• ~~August~~We ~~2018,~~do ~~the~~not ~~FASB~~anticipate ~~issued ASU~~meeting ~~No.~~our ~~2018-13, Fair~~existing ~~Value~~leverage ~~Measurement~~covenants ~~(Topic~~through ~~820)~~June ~~Disclosure~~2020 ~~Framework~~without -relief ~~Changes~~from toour ~~the~~lenders ~~Disclosure~~and ~~Requirements~~currently ~~for~~expect ~~Fair~~not Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be ~~applied~~able onto asatisfy ~~retrospective~~the ~~basis~~consolidated ~~and~~total ~~others~~leverage onratio acovenant ~~prospective~~in ~~basis. We do not expect~~ the ~~adoption~~Alta ofMesa ~~this~~RBL ~~standard~~as toearly ~~impact~~as ~~our~~the ~~financial~~measurement ~~position~~date orof ~~results~~September of30, ~~operations~~2019.

~~NOTE~~• 3We —have ~~GOING~~$500.0 ~~CONCERN~~million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in December 2019, which could become an event of default if unpaid before January 14, 2020. The 2024 Notes trade substantially below par value.

We• ~~are~~The ~~required~~Class toA ~~evaluate~~common stock of our ~~ability~~parent tocompany, ~~continue~~AMR, ashas abeen ~~going~~trading ~~concern~~below ~~for~~$1.00 aper ~~period~~share ofsince ~~one~~February ~~year~~22, ~~following~~2019. ~~the~~On ~~date~~April of3, ~~issuance~~2019, ofAMR ~~our~~was ~~financial~~notified ~~statements~~by NASDAQ that it was not in compliance with the minimum bid price requirement. As ~~part~~Continued oftrading ~~that~~at ~~evaluation,~~these welevels ~~took~~may ~~into~~limit ~~consideration~~its and our ability to raise additional capital in the ~~following~~equity ~~factors:~~markets.

• AtOur ~~March~~ability ~~31,~~to ~~2019,~~collect ~~our~~receivables ~~current~~due ~~liabilities~~from ~~exceeded~~High ~~our~~Mesa ~~current~~and ~~assets~~its ~~by $4.8 million.~~affiliates

• 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 advisors for the Alta Mesa RBL lenders ~~and their advisors~~ about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement,. ~~however,~~To date we ~~currently~~have ~~expect~~been ~~that~~unable ~~such~~to ~~relief~~reach ~~would~~an ~~only~~accord beon ~~available~~any insuch ~~connection~~relief ~~with~~and ado ~~reduction~~not inexpect ~~our~~that ~~borrowing~~the ~~capacity~~lenders ~~which~~would ~~could~~grant ~~further~~any ~~hamper~~extended ~~our~~period ~~liquidity~~of covenant relief;

• considered seeking new sources of financing, however, such efforts ~~have~~do not ~~reached~~appear ato ~~stage~~present ~~where~~a ~~significant~~substantive ~~terms have been agreed to~~solution; and

• engaged in discussions with ~~advisors~~and provided requested information to financial and legal advisors for a group of holders of ~~the~~Alta Mesa’s 2024 Notes, ~~regarding~~but ~~potential~~we ~~options~~cannot topredict ~~address~~what ~~overall~~will ~~leverage,~~result ~~but~~from ~~have~~the ~~not~~discussions ~~agreed~~or ~~upon~~whether ~~any~~they ~~significant~~will ~~strategy~~yield ora ~~terms;~~constructive ~~and~~deal.

•Regardless ~~had~~of ~~preliminary~~whether ~~discussions~~we ~~with~~are ~~existing~~able ~~capital~~to ~~providers~~reach ~~about~~an ~~making~~agreement ~~additional~~with ~~investments~~our increditors, it may be necessary for us ~~but~~to ~~such~~file ~~discussions~~a ~~have~~voluntary ~~not~~petition ~~reached~~for relief under Chapter 11 of the U.S. Bankruptcy Code. In light of these factors, we believe substantial unresolved doubt exists regarding our ability to continue as a ~~stage~~going concern for the 12 months following the issuance of ~~being~~these ~~considered~~financial ~~likely~~statements. orBased on the foregoing, we believe that it is probable that our indebtedness will accelerate before July 2020 and, therefore, have reported all of ~~success~~our atdebt ~~this~~as ~~time~~current.

Recently Issued Accounting Standards Applicable to Us

Adopted

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

Not Yet Adopted

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Index to Financial Statements

Inhosting ~~light~~arrangement ofthat is a service contract with the ~~above~~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, wea ~~believe~~customer ~~substantial~~in ~~unresolved~~a ~~doubt~~hosting ~~exists~~arrangement ~~regarding~~that ~~our~~is ~~ability~~a service contract is required to ~~continue~~follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a ~~going~~prepaid ~~concern~~asset ~~for~~related to the ~~next~~service 12contract ~~months~~and which costs to expense. WeThe ~~have~~capitalized ~~continued~~implementation ~~reporting~~costs ~~our~~are ~~long-~~to be expensed over the term ~~debt~~of the hosting arrangement and reflected in the same line in the consolidated statement of operations as ~~noncurrent~~the fees associated with the hosting element of the arrangement. Similarly, ~~since~~capitalized aimplementation ~~conclusion~~costs ~~regarding~~are ~~going~~to ~~concern~~be ~~has~~presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no ~~effect~~later onthan ~~debt~~January ~~compliance~~1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

~~NOTE~~In 4August —2018, ~~ADOPTION~~the OFFASB issued ASU NONo. ~~2016~~2018-0213, ~~LEASES~~Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

~~ASU~~NOTE ~~No.~~3 ~~2016-02~~— ~~requires~~ADOPTION usOF ~~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 NoNO. 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 LEASES

WeASU ~~lease~~No. ~~office~~2016-02 ~~space,~~requires ~~office~~us ~~equipment~~to ~~and~~recognize ~~field~~a ~~equipment, including compressors. Many~~ right-of-use ~~our~~(“ROU”) ~~leases~~asset ~~include~~and ~~both~~a discounted lease ~~and~~liability ~~non-lease~~on ~~components~~the ~~which~~balance ~~are~~sheet ~~primarily~~for ~~management~~all ~~services~~leases bywith ~~the~~a ~~lessors~~term ~~for~~longer ~~the~~than ~~underlying~~one ~~assets~~year. ~~All~~We ofadopted ~~our~~ASU ~~leases~~No. of2016-02 ~~office space~~ and ~~office~~related ~~equipment,~~guidance ~~were~~using ~~classified~~the asmodified ~~operating~~retrospective ~~leases~~method ~~upon~~to ~~adoption.~~apply ~~Our~~the ~~leases~~standard ofas ~~field~~January ~~equipment~~1, ~~had~~2019, ~~remaining~~and ~~terms~~this ofadoption ~~less~~had ~~than~~no ~~one~~effect ~~year~~on at the ~~date~~earlier ofcomparative ~~adoption~~periods ~~and~~presented. At ~~were~~adoption, ~~not~~we recognized as operating ~~leases~~lease onROU ~~our~~assets ~~balance~~and ~~sheet~~operating ~~due~~lease toliabilities ~~our election~~ of ~~the short term lease practical expedient described below~~$15. ~~Our~~0 ~~leases do not contain any residual value guarantees or restrictive covenants~~million. WeThere dowas ~~not~~no ~~sublease~~adjustment ~~any~~to beginning of ~~our~~period ~~ROU assets~~equity.

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

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:

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(in thousands)	Three Months EndedMarch 31, 2019
Practical expedient package	We did not reassess whether any expired or existing contracts are, or contain, leases.
Operating lease cost	$	811
	We did not reassess the lease classification of any expired or existing leases.
Variable lease cost	323
	We did not reassess initial direct costs of any expired or existing leases.
Short-term lease cost	2,187
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.
Total lease cost	$	3,321
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.

~~For~~As ~~the~~most ~~three~~leases ~~months~~do ~~ended~~not ~~March~~have ~~31,~~readily ~~2019~~determinable implicit rates, we ~~recognized~~estimated ~~$2.3~~the ~~million~~incremental ofborrowing rates for our future lease ~~costs~~payments inbased on prevailing financial market conditions at the later of date of adoption or lease ~~operating~~commencement, ~~expense~~comparable companies and $1credit analysis and management judgments to determine the present values of our lease payments.0 ~~million~~We inalso ~~general~~apply the portfolio approach to account for leases with similar terms. At June 30, 2019, for our operating leases the weighted-average remaining lease terms were approximately 8.1 years and ~~administrative~~our ~~expense~~weighted-average discount rates were 14.1%.

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

Fiscal year	(in thousands)
(in thousands)	Three Months EndedJune 30, 2019			Six Months Ended June 30, 2019
Remainder of 2019	$	2,200
Operating lease cost	$	776		$	1,587
2020	2,965
Variable lease cost	473			796
2021	2,942
Short-term lease cost	1,075			3,261
2022	3,010
Total lease cost	$	2,324		$	5,644
2023	2,718
Reported as:
Thereafter	12,647
Lease operating expense	$	1,031		$	3,326
Total lease payments	26,482
General and administrative expense	1,293			2,318
Less: imputed interest	(11,625		)
Total lease cost	$	2,324		$	5,644
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

AsOperating ~~described~~Lease ~~further~~Liability inMaturities ~~our~~as ~~2018~~of ~~Annual Report on Form 10-K~~June 30, ~~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.~~

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NOTE 5 — SUPPLEMENTAL CASH FLOW INFORMATION



Fiscal year	(in thousands)
Remainder of 2019	$	1,470
2020	2,965
2021	2,942
2022	3,010
2023	2,718
Thereafter	12,647
Total lease payments	25,752
Less: imputed interest	(11,081		)
Present value of operating lease liabilities	$	14,671

Current portion of operating lease liabilities	$	938
Operating lease liabilities, net of current portion	13,733
Present value of operating lease liabilities	$	14,671

	Successor						Predecessor
(in thousands)	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 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

Operating Lease Payment Obligations as of December 31, 2018

~~The~~As ~~following~~described ~~table~~further ~~summarizes~~in ~~cash~~our 2018 10-K, ~~cash~~our ~~equivalents~~minimum ~~and~~future ~~restricted~~contractual ~~cash~~lease inpayments ~~the~~under ~~statements~~ASC of840 ~~cash~~at ~~flows:~~ December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter.

Right-of-Use Asset Impairment

During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We are seeking to sublease the unused office space within three buildings. We do not anticipate that we will be able to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.

NOTE 4 — SUPPLEMENTAL CASH FLOW INFORMATION



	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	25,070		$	21,216		$	1,145
Cash paid for state income taxes, net of refunds	—			6			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	634			877			—
Increase (decrease) in accruals or payables for capital expenditures	(91,639		)	(27,646		)	4,896
Distribution of non-STACK assets, net of liabilities	—			—			43,482

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

໿

	Successor				Predecessor
(in thousands)	March 31, 2019		March 31, 2018		February 8, 2018
Cash and cash equivalents	$	27,045	$	255,701	$	9,070
Restricted cash	798		1,295		1,275
Total cash, cash equivalents and restricted cash	$	27,843	$	256,996	$	10,345

NOTE 5 — RECEIVABLES

NOTE 6 — RECEIVABLES

Accounts Receivable

(in thousands)	~~March~~June 3130, 2019			December 31, 2018
Production sales	$	3229,~~332~~730		$	31,532
Joint interest billings	1820,~~224~~836			18,147
Pooling interest (1)	1411,~~960~~506			18,786
Allowance for doubtful accounts	(~~113~~410		)	(95		)
Total accounts receivable, net	$	6561,~~403~~662		$	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



(in thousands)	June 30, 2019			December 31, 2018
Related party receivables	$	23,037		$	33,316
Allowance for doubtful accounts	(9,888		)	(9,034		)
Related party receivables, net	13,149			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	$	13,149		$	24,282

KFM Receivables

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(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

We have entered into contracts with KFM whereby they provide midstream services, including produced water disposal, to us. During the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, we incurred $30.8 million, $13.6 million, and $3.1 million, respectively, in midstream services, which we have recognized in transportation and marketing expense. Additionally, we had related party receivables from KFM which include its portion of allocated G&A, other expenditures attributable to KFM and proceeds due to us for KFM’s sale of our natural gas and NGLs reduced by the fees from midstream services that KFM provided to us totaling $4.6 million and $11.2 million at June 30, 2019 and December 31, 2018, respectively.

In addition, we sold a produced water disposal system to KFM ~~Receivables~~during the fourth quarter of 2018. As of December 31, 2018, related party receivables of $8.7 million were attributable to a purchase price adjustment due from KFM. We collected this receivable during June 2019.

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~~June 3130, 2019 and December 31, 2018, respectively, we have receivables from AMR for such costs totaling $3.8.5 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.



(in thousands)	June 30, 2019
High Mesa related party receivable at December 31, 2018	$	10,066
Additions	894
Payments	(1,072		)
High Mesa related party receivable at June 30, 2019	9,888
Allowance for uncollectibility⁽¹⁾	(9,888		)
Balance at June 30, 2019, net	$	—

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 _________________


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

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

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently agreed to terminate the High Mesa Agreement, effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. As of June 30, 2019, and December 31, 2018, approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9 million and $9.0 million as of June 30, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation

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Index to Financial Statements

that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9 million and $9.0 million as of March 31, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation relating to the non-STACK assets. As of ~~March~~June 3130, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa. 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 attributable to the final purchase price adjustment due from KFM. This amount was collected during June 2019.

As of March 31, 2019 and December 31, 2018, the Company had $3.8 million and $3.3 million in related party receivables due from AMR for expenses we paid on their behalf.

Promissory notes receivable

In September, 2017, we entered into a $1.5 million promissory note receivable with our affiliate, Northwest Gas Processing, LLC, whose obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bore interest, which could be paid-in-kind and added to the principal amount at a rate of 8% per annum~~, and matured in February 2019~~. HMS defaulted under the terms of that promissory note when it was not paid ~~when~~at ~~due~~maturity on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, ~~due~~totaling of $1.7 million as of ~~March~~June 3130, 2019 and December 31, 2018.

In addition, we have an $8.5 million note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. HMI disputes its obligations under the $8.5 million note. As of ~~March~~June 3130, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.

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

NOTE 6 — PROPERTY AND EQUIPMENT



(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	76,665		$	74,217
Proved oil and gas properties	2,196,605			2,110,346
Accumulated depletion and impairment	(1,489,191		)	(1,421,226		)
Proved oil and gas properties, net	707,414			689,120
Total oil and gas properties, net	784,079			763,337
Other property and equipment
Land	5,059			5,059
Fresh water wells	27,372			27,366
Produced water disposal system	3,590			3,608
Office furniture, equipment and vehicles	2,825			2,840
Accumulated depreciation	(1,475		)	(726		)
Other property and equipment, net	37,371			38,147
Total property and equipment, net	$	821,450		$	801,484

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Index to Financial Statements

NOTE 7 — PROPERTY AND EQUIPMENT

(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

Depletion and Depreciation Expense

	Successor				~~Predecessor~~				Predecessor
(in thousands)	Three Months ~~EndedMarch~~EndedJune 3130, 2019		~~February~~Three 9,Months ~~2018ThroughMarch~~EndedJune 3130, 2018		~~January~~Six 1,Months ~~2018ThroughFebruary~~EndedJune 830, ~~2018~~2019		February 9, 2018ThroughJune 30, 2018		January 1, 2018ThroughFebruary 8, 2018
Oil and gas properties depletion	$	3433,~~042~~923	$	1026,~~773~~086	$	1167,~~021~~965	$	36,859	$	11,021
Other property and equipment depreciation	~~408~~341		~~163~~423		~~609~~749		586		609
Total depletion and depreciation	$	34,~~450~~264	$	1026,~~936~~509	$	1168,~~630~~714	$	37,445	$	11,630

Impairment

During the three months ended ~~March~~June 3130, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment impacting our property and equipment. 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.

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Index to Financial Statements

	Predecessor
(in thousands)	January 1, 2018ThroughFebruary 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	)

NOTE 7 — DISCONTINUED OPERATIONS (Predecessor)



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



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

NOTE 98 — DERIVATIVES

WeAll of our derivatives have ~~entered~~the ~~into~~lenders ~~derivatives~~under tothe ~~reduce~~Alta ~~our~~Mesa ~~exposure~~RBL toas ~~price~~counterparty, ~~risk~~and ~~associated~~are ~~with~~collateralized ~~our~~by ~~production~~the security interests thereunder. ~~From~~We ~~time~~periodically tomonitor ~~time,~~the wecreditworthiness ~~may~~of ~~enter~~our ~~into~~counterparties. Although ~~interest~~our ~~rate~~counterparties ~~swap~~provide no collateral, the agreements with each counterparty allow us to ~~mitigate~~set-off ~~the~~unpaid ~~risk~~amounts ofagainst ~~changes~~the inoutstanding ~~interest~~balance ~~rates,~~under ~~but~~the asAlta ofMesa ~~March 31,~~RBL. The ~~2019,~~derivatives wesettle monthly. No derivatives have ~~none. We~~been doentered ~~not~~into ~~designate~~for ~~any~~trading ofor ~~our~~speculative ~~derivatives~~purposes and none have been designated as hedges under GAAP.

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

March 31, 2019

June 30, 2019

Balance sheet location

Gross fair valueof assets

Gross liabilitiesoffset against assetsin the Balance Sheet

Net fairvalue of assetspresented inthe Balance Sheet

(in thousands)

Derivatives, current assets

613,~~525~~855

(69,~~525~~128

)

—4,727

Derivatives, long-term assets

811,~~182~~977

(79,~~721~~469

)

~~461~~2,508

Total

1425,~~707~~832

(1418,~~246~~597

)

~~461~~7,235



Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	9,968	$	(9,128	)	$	840
Derivatives, long-term liabilities	9,658		(9,469		)	189
Total	$	19,626	$	(18,597	)	$	1,029



	December 31, 2018
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivatives, current assets	$	22,512	$	(6,089	)	$	16,423
Derivatives, long-term assets	7,910		(4,963		)	2,947
Total	$	30,422	$	(11,052	)	$	19,370



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

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



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

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

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

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OIL

Balance sheet location	Gross fair valueof liabilities			Gross assetsoffset against liabilitiesin the Balance Sheet				Net fairvalue of liabilitiespresented inthe Balance Sheet
	Remaining Volume		Weighted				Range
	(in thousands)
Settlement Period and Type of Contract	in bbls		Average				High			Low
Derivatives, current liabilities	$	11,582		$	(6,525	)		$	5,057
2019
Derivatives, long-term liabilities	9,786			(7,721		)		2,065
Price Swap Contracts	92,000		$	63.03			$	63.03		$	63.03
Total	$	21,368		$	(14,246	)		$	7,122
Collar Contracts
Short Call Options	1,361,600		66.31				75.20			56.50
Long Put Options	1,453,600		53.80				62.00			50.00
Short Put Options	1,453,600		42.72				52.00			37.50
2020
Collar Contracts
Short Call Options	1,017,600		63.95				73.80			59.55
Long Put Options	1,566,600		56.81				62.50			50.00
Short Put Options	1,566,600		42.81				50.00			37.50
2021
Collar Contracts
Short Call Options	279,750		63.51				63.75			63.35
Long Put Options	659,850		46.94				55.00			41.00
Short Put Options	279,750		43.00				43.00			43.00

NATURAL GAS

	December 31, 2018
	Remaining Volume		Weighted				Range
Balance sheet location	Gross fair valueof assets			Gross liabilitiesoffset against assetsin the Balance Sheet				Net fairvalue of assetspresented inthe Balance Sheet
Settlement Period and Type of Contract	in MMBtu		Average				High			Low
	(in thousands)
2019
Derivatives, current assets	$	22,512		$	(6,089	)		$	16,423
Price Swap Contracts	7,980,000		$	2.67			$	2.72		$	2.64
Derivatives, long-term assets	7,910			(4,963		)		2,947
Basis Swap Contracts	9,680,000		(0.72		)		(0.49		)	(0.93		)
Total	$	30,422		$	(11,052	)		$	19,370
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

Balance sheet location	Gross fair valueof liabilities		Gross assetsoffset against liabilitiesin the Balance Sheet			Net fairvalue of liabilitiespresented inthe Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	7,799	$	(6,089	)	$	1,710
Derivatives, long-term liabilities	5,143		(4,963		)	180
Total	$	12,942	$	(11,052	)	$	1,890

	Successor						Predecessor
Derivatives not designated as hedges	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 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

Other receivables at March 31, 2019 and December 31, 2018 include $0.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the next month.

We periodically monitor the creditworthiness of our counterparties. Although our counterparties provide no collateral, the agreements with each counterparty allow us to set-off unpaid amounts against the outstanding balance under the Alta Mesa RBL.

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Index to Financial Statements

We had the following ~~call~~basis ~~and~~swaps ~~put derivatives~~ at ~~March~~June 3130, 2019:

	Volume		Weighted			Range
Total Gas Volumes in MMBtu(1) overRemaining Term	Reference Price 1 (1)	Reference Price 2 (1)		Period				WeightedAverage Spread($ per MMBtu)
Settlement Period and Type of Contract	in bbls		Average			High			Low
460,000	OneOK	NYMEX Henry Hub		Jul '19	—		Dec '19	$	(0.93	)
2019
7,990,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub		Jul '19	—		Dec '19	(0.70		)
Price Swap Contracts	137,500		$	63.03		$	63.03		$	63.03
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub		Jan '20	—		Mar '20	(0.49		)
Collar Contracts
1,230,000	San Juan	NYMEX Henry Hub		Jul '19	—		Oct '19	(0.81		)
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

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

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.

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We had the following basis swaps at March 31, 2019:

Total Gas Volumes in MMBtu(1) overRemaining Term	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	)
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		)

________________


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

18NOTE 9 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

໿

(in thousands)	~~March~~June 3130, 2019		December 31, 2018
Accounts payable	$	8,~~502~~871	$	20,200
Accruals for capital expenditures	2518,~~964~~477		101,214
Revenue and royalties payable	4039,~~365~~232		46,870
Accruals for operating expenses	810,~~910~~701		16,355
Accrued interest	135,~~754~~642		1,784
Derivative settlements	49743		109
Other	118,~~122~~028		10,532
Total accrued liabilities	~~100~~82,~~164~~823		176,864
Accounts payable and accrued liabilities	$	~~108~~91,~~666~~694	$	197,064

NOTE 1110 — ASSET RETIREMENT OBLIGATIONS

	Successor						Predecessor
(in thousands)	~~Three~~Six Months ~~EndedMarch~~EndedJune 3130, 2019			February 9, ~~2018ThroughMarch~~2018ThroughJune 3130, 2018			January 1, 2018ThroughFebruary 8, 2018
Balance, beginning of period	$	11,409		$	—		$	10,469
Liabilities assumed in Business Combination	—			5,998			—
Liabilities incurred	~~315~~634			~~421~~877			—
Liabilities settled	(~~147~~162		)	(~~166~~806		)	(63		)
Revisions to estimates	(4)			300			63
Liabilities transferred in sale of properties	—			(20		)	—
Accretion expense	225			102			39
Revisions to estimates	(9		)	665			63
Balance, end of period	11,798			6,655			10,508
Accretion expense	465			263			40
Less: Current portion	48			622			33
Balance, end of period	12,337			6,977			10,509
Long-term portion	$	11,750		$	6,033		$	10,475
Less: Current portion	44			538			33
Long-term portion	$	12,293		$	6,439		$	10,476

NOTE 1211 — ~~LONG TERM~~ DEBT~~, 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

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(in thousands)	June 30, 2019		December 31, 2018
Alta Mesa RBL	$	344,500	$	161,000
2024 Notes	500,000		500,000
Unamortized premium on 2024 Notes	26,662		29,123
Total debt, net	871,162		690,123
Less: Current portion	871,162		—
Long-term debt, net	$	—	$	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~~Before ~~2019~~July 2020, and possibly as soon as ~~June~~ September 30, 2019, we ~~may~~do benot ~~unable~~expect to satisfy the leverage ratio. ~~Also,~~We 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.

19At June 30, 2019, inclusive of $20.2 million of outstanding letters of credit, we had $5.3 million of stated borrowing capacity remaining under the Alta Mesa RBL, dependent upon the lenders’ willingness to provide such funds.

~~Table~~In August 2019, the lenders exercised their ability to make an optional redetermination of ~~Contents~~our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. Our discussion about our ability to continue as a going concern provides information about the borrowing base and deficiency payments arising from the redetermination.

Index to Financial Statements

2024 Notes

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~~193.98 million at ~~March~~June 3130, 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.

Scheduled Maturities of ~~Long-Term~~ Debt

Fiscal year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	~~278~~344,~~000~~500
Thereafter	500,000
	$	~~778~~844,~~000~~500

~~NOTE 13 —~~Based ~~COMMITMENTS~~upon ~~AND~~the ~~CONTINGENCIES~~factors leading to the substantial unresolved doubt about our ability to continue as a going concern, we believe that it is probable that our indebtedness will accelerate prior to July 1, 2020, and earlier than the scheduled maturities shown above. We have reported all of our debt as current at June 30, 2019.

~~There~~NOTE 12 — ~~have~~COMMITMENTS ~~been~~AND 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 DecemberCONTINGENCIES ~~31, 2018.~~

~~NOTE~~There ~~14 —~~have ~~SIGNIFICANT~~been ~~CONCENTRATIONS~~ no material changes during the first six months of 2019 in our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K.

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.18

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 EndedMarch 31, 2019		February 9, 2018ThroughMarch 31, 2018		January 1, 2018ThroughFebruary 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

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Index to Financial Statements

~~Receivables~~NOTE ~~from ARM for sales on our behalf were $3.8 million and $38.4 million as of March~~13 ~~31,~~— ~~2019~~SIGNIFICANT ~~and December~~CONCENTRATIONS ~~31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.~~

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

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



	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	7,703	$	70,601	$	91,534	$	107,944	$	28,757

Marketing and management fees paid to ARM	$	476	$	—	$	1,137	$	—	$	—
Fees paid to ARM for derivative services	218		209		411		283		66
Total fees paid to ARM	$	694	$	209	$	1,548	$	283	$	66

Receivables from ARM for sales on our behalf were $0.2 million and $38.4 million as of June 30, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

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

NOTE 1514 — EQUITY-BASED COMPENSATION (Successor)

Stock compensation expense ~~recognized~~allocated to us by AMR pursuant to its equity-based compensation programs was as follows:

	Successor				~~Predecessor~~				Predecessor
(in thousands)	Three Months ~~EndedMarch~~EndedJune 3130, 2019		~~February~~Three 9,Months ~~2018ThroughMarch~~EndedJune 3130, 2018		~~January~~Six 1,Months ~~2018ThroughFebruary~~EndedJune 830, ~~2018~~2019		February 9, 2018ThroughJune 30, 2018		January 1, 2018ThroughFebruary 8, 2018
Stock options	$	~~791~~744	$	1,~~048~~606	$	—1,535	$	2,628	$	—
Restricted stock awards	~~862~~563		~~564~~871		—1,425		1,412		—
Performance-based restricted stock units	889		1,~~156~~144		—97		2,349		—
Total compensation expense	$	1,~~661~~396	$	23,~~768~~621	$	—3,057	$	6,389	$	—

Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year 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.

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Index to Financial Statements

The performance targets for the 2019 tranche were established in March 2019 and 595,417 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment.

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

NOTE 1615 — 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 which was settled during the second quarter of 2019.

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 iswas 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 $3683,000 and $28,000 for the period February 9, 2018 through ~~March 31~~June 30, 2018, and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses.

David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860, $~~970~~929,~~197~~428 and $28,874 during the ~~2019~~six ~~Quarter~~months ended June 30, 2019, the period February 9, 2018 through ~~March 31~~June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense and represent the portion that was allocated to AMH. 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.

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Bayou City Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for ~~the parties to potentially agree to~~ an additional 20 wells. Pursuant to the ~~terms and provisions of the~~ JDA, BCE committed to fund 100% of our working interest ~~share~~ up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for ~~carrying~~funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return ~~on each individual tranche~~. Following the completion of each joint well, we and BCE ~~will~~ each bear our respective proportionate working interest share of all subsequent costs ~~and expenses~~ related to such joint well. Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the ~~period~~Predecessor ~~February 9~~Period, ~~2018 through March 31, 2018,~~ BCE advanced us approximately $39.5 million to drill wells under the JDA. ~~As of March~~Through June 3130, 2019, 61 joint wells have been drilled or spudded. At ~~March~~June 3130, 2019 and December 31, 2018, $4.50 million and $9.8 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our condensed consolidated balance sheets. At ~~March~~June 3130, 2019, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves.

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

The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes included elsewhere in this report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and 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 the sections titled “Risk Factors” in this Quarterly Report and in our 2018 Annual Report on Form 10-K, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

~~Overview~~20

We are 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 Oklahoma. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County (“STACK”). We generate revenue principally by the production and sale of oil, natural gas and NGLs. We maintain operational control of the majority of our properties, either through directly operating them or 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

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~~presentations~~in ~~separate~~these ~~our~~forward-looking ~~presentations~~statements. ~~into~~Factors ~~two~~that ~~distinct~~could ~~periods~~cause or contribute to such differences include, ~~the~~but ~~period~~are ~~before~~not limited to, the ~~consummation~~volatility of ~~the~~oil ~~acquisition~~and ~~(“Predecessor”)~~gas prices, production timing and ~~the~~volumes, ~~period~~our ~~after~~ability ~~that~~to ~~date~~continue ~~(“Successor”)~~as a going concern, toestimates ~~indicate~~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 ~~application~~beginning of this Quarterly Report and in the ~~different~~sections ~~basis~~titled of“Risk ~~accounting~~Factors” ~~between~~in ~~the~~this ~~periods~~Quarterly ~~presented.~~Report ~~Accordingly,~~and ~~the~~in ~~period~~our ~~January 1~~2018 10-K, ~~2018~~all of which are difficult to ~~February 8,~~predict. ~~2018~~As isa ~~referred~~result toof asthese risks, uncertainties and assumptions, the ~~Predecessor~~forward-looking ~~Period~~events discussed may not occur.

Overview

We are 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. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the STACK. We generate revenue principally by the production and sale of oil, natural gas and NGLs. We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners.

As a result of the Business Combination, our identifiable assets acquired and liabilities assumed by our parent company 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 presentations separate our presentations into two distinct periods, the period before the consummation of the Business Combination (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented. Accordingly, the period January 1, 2018 to February 8, 2018 is referred to as the Predecessor Period.

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

As of June 30, 2019, we have a highly contiguous position of approximately 130,000 net acres in the up-dip, naturally-fractured oil portion of the STACK primarily in eastern Kingfisher and south-eastern Major counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. After the Business Combination, we conducted development activities using a spacing array of 6 to 10 wells per section and running up to 9 rigs at the peak activity level. In late 2018, our production across the acreage evidenced that the well spacing was not delivering the well level production that we expected. During January 2019, we suspended our development program to allow our new management team to conduct a full operational and economic review. We restarted our development program in March 2019 with a less dense spacing pattern of up to five wells per section. In addition, we have worked to improve our economic returns by reducing well costs, general and administrative expense and other operating expense.

We have operated 2 rigs since restarting the program, however following the redetermination of the borrowing base of the Alta Mesa RBL in August 2019, we have decided to operate 1 rig starting in September. We will continue to evaluate how much, if any, development is appropriate going forward.

Outlook, Market Conditions and Commodity Prices

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

Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and ~~it is uncertain whether the increase in market prices experienced since the end of 2018 will be sustained. As a result,~~ we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues. In the event that oil, 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 the Alta Mesa RBL.

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Key performance indicators

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

• Production;

• General and administrative costs (excluding strategic costs);

• Lease operating expense;

• Well drilling and completion costs; and

• Adjusted EBITDAX.

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

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

Going concern

Our present level of indebtedness and the ~~impact~~current of commodity ~~prices~~price atenvironment ~~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~~As a result of our updated forecasted production levels and pressures created by lower commodity prices, in the absence of one or more deleveraging transactions, we ~~may~~do benot atanticipate ~~risk~~maintaining ~~of non-~~compliance with the ~~Consolidated~~consolidated ~~Total~~total ~~Leverage~~leverage ~~Ratio~~ratio ~~Covenant~~covenant in the Alta Mesa RBL as early as the ~~June~~measurement date of September 30, 2019 ~~measurement date~~. In ~~addition~~Also, ~~the~~in ~~lenders~~August ~~under~~2019 the ~~Alta~~lenders ~~Mesa~~exercised ~~RBL~~their ~~have an~~ ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019~~. If~~, ~~the~~and ~~outstanding~~via ~~borrowings~~this ~~under~~redetermination, ~~the~~our ~~Alta Mesa RBL were to exceed the~~ borrowing base ~~due~~was reduced to ~~any~~$200 ~~such~~million. As ~~redetermination~~such, we ~~would~~are be required to repay the $162.4 million of combined excess of our borrowings and letters of credit outstanding ratably over five months in $32.5 million installments, which ~~could~~will have an adverse impact on our liquidity. The first payment is due in September 2019. If we are unable to make repayment of this amount, we will be in default under the Alta Mesa RBL. As a consequence of both reduced operating cash flow and a reduced borrowing base, we may have limited ability to obtain the capital necessary to conduct our operations at desired levels. Our general partner’s board of directors 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, occurs and the Alta Mesa RBL lenders were to accelerate repayment, it may result in an ~~event~~acceleration of ~~default and an acceleration under~~ the 2024 Notes. We have concluded that these and other circumstances create substantial doubt regarding our ability to continue as a going concern. ~~For~~We acurrently ~~more~~anticipate ~~detailed~~that ~~discussion,~~our ~~please~~indebtedness ~~read~~will ~~“Item~~accelerate ~~1A.~~prior ~~Risk~~to ~~Factors”~~July in1, ~~Part~~2020 Iand therefore, have reported all of our ~~2018~~debt ~~10-K~~as current at June 30 2019.

If an agreement is reached with our creditors and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court. We may also conclude it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are otherwise unable to reach an agreement with our creditors. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims, including our secured and unsecured creditors, will receive substantially less than the amount of their claims. Our Risk Factors described in our 2018 10-K contain important information.

Derivatives

23The objective of our hedging program is to produce, over time, relative revenue stability. However, in the short-term, both settlements and fair value changes in our derivatives can significantly impact our results of operations, and we expect these gains and losses to continue to reflect the impact of changes in oil and gas prices. Our derivatives are reported at fair value and are sensitive to changes in the price of oil and gas. Changes in derivatives are reported as gain (loss) on derivatives, which include both the unrealized increase and decrease in their fair value, as well as the effect of realized settlements during the period. For the six months ended June 30, 2019, we recognized a net loss on our derivatives of $11.4 million, which includes $0.9 million in cash received upon derivative settlements.

Impairments

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~~The~~In ~~objective~~late offourth ~~our~~quarter ~~hedging~~of ~~program~~2018, isthe tocombination ~~reduce~~of ~~price~~depressed ~~volatility~~prevailing ~~for~~oil ~~our~~and ~~production~~gas ~~over time. However~~prices, inchanges ~~the~~to ~~short-term,~~assumed ~~both~~spacing ~~settlements and fair value changes~~ in ~~our~~conjunction ~~derivatives~~with ~~can~~evolving ~~significantly~~views ~~impact~~on ~~our~~the ~~results~~viability of ~~operations,~~multiple benches and wereduced ~~expect~~individual ~~these~~well ~~gains~~expectations ~~and~~resulted ~~losses~~in toimpairment ~~continue~~charges toof ~~reflect~~$2.0 ~~the~~billion ~~impact~~to ofour ~~changes~~proved inand unproved oil and gas ~~prices.~~properties ~~Our~~during ~~derivatives~~the ~~are~~quarter ~~reported~~ended atDecember 31, ~~fair~~2018. ~~value~~Individual ~~and~~well ~~are~~expectations ~~sensitive~~were toimpacted ~~changes~~by reductions in ~~the~~estimated ~~price~~reserve recovery of original oil and gas in place. In ~~Changes~~the infuture, ~~derivatives~~we ~~are~~may ~~reported~~recognize asfurther ~~gain~~impairments ~~(loss)~~of onproved ~~derivatives,~~and ~~which~~unproved ~~include~~oil ~~both~~and ~~the~~gas ~~unrealized~~properties ~~increase~~if ~~and~~commodity ~~decrease~~prices indecline ~~their~~from ~~fair~~current ~~value~~levels, asincremental ~~well~~downward asrevisions ~~the~~to ~~effect~~production offorecasts ~~realized~~occur ~~settlements~~or ~~during~~operating ~~the~~costs ~~period~~increase. ~~For~~Prolonged ~~the~~low ~~quarter~~commodity ~~ended~~prices ~~March~~may ~~31,~~also ~~2019,~~result wein ~~recognized~~additional aimpairments ~~net~~of ~~loss~~other onassets ~~our~~and ~~derivatives~~could ofcause ~~$23.8 million,~~us ~~which~~to ~~includes~~delay ~~$0.4 million~~or inabandon ~~cash~~anticipated ~~settlements~~development ~~received for derivatives~~activities.

Impairments

In late fourth quarter of 2018, the combination of depressed prevailing oil and gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations resulted in impairment charges of $2.0 billion to our proved 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 future, we may recognize further impairments of 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 additional impairments of other assets and could cause us to delay or abandon anticipated development activities.

Factors affecting future performance

The primary factors affecting our production levels, (which may be interrelated), are current commodity prices, capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of ~~identified~~ drilling ~~locations~~prospects. In addition, our wells have significant natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped resources, well recompletions and other enhanced recovery methods. Sustaining our production levels or our future growth will depend on our ability to continue to develop reserves, including our ability to fund such development. Our ability to add reserves through drilling and other development techniques is dependent on current market conditions and our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenue and, as a result, our cash flow from operations.

Results of Operations

For the Three Months Ended ~~March~~June 3130, 2019 (“Second Quarter 2019”) Compared to the ~~Periods~~Three ~~February 9,~~Months ~~2018~~Ended ~~Through March 31~~June 30, 2018 (~~Successor)~~“Second ~~and~~Quarter ~~January 1,~~ 2018 ~~Through February 8, 2018 (Predecessor~~”).

The tables included below set forth financial information for the Successor Periods and Predecessor Period, which are distinct reporting periods as a result of the Business Combination. The Predecessor Period amounts below exclude operating results related to discontinued operations. We refer to the 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.”23

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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)	Second Quarter 2019			Second Quarter 2018
(in thousands, except per unit data)	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018 Through February 8, 2018
Net production:
Net production:
Oil (Mbbls)	1,545			1,123
Oil (Mbbls)	1,619			651			494
Natural gas (MMcf)	6,283			3,944
Natural gas (MMcf)	5,831			2,248			1,609
NGLs (Mbbls)	819			554
NGLs (Mbbls)	795			223			151
Total (MBoe)	3,411			2,334
Total (MBoe)	3,386			1,249			914
Average net daily production volumes:
Average net daily production volumes:
Oil (Mbblsd)	17.0			12.3
Oil (Mbblsd)	18.0			12.8			12.7
Natural gas (MMcfd)	69.0			43.3
Natural gas (MMcfd)	64.8			44.1			41.2
NGLs (Mbblsd)	9.0			6.1
NGLs (Mbblsd)	8.8			4.4			3.9
Total (MBoed)	37.5			25.6
Total (MBoed)	37.6			24.5			23.4
Average sales prices:
Average sales prices:
Oil (per bbl)	$	58.67		$	67.09
Oil (per bbl)	$	53.34		$	61.84		$	62.68
Effect of realized derivatives settlements (per bbl)	0.12			(12.80		)
Effect of realized derivatives settlements (per bbl)	1.08			(7.93		)	(6.44		)
Oil, after hedging (per bbl)	$	58.79		$	54.29
Oil, after hedging (per bbl)	$	54.42		$	53.91		$	56.24
Percentage of unhedged realized oil price to NYMEX oil price	97		%	99		%
Percentage of unhedged realized oil price to NYMEX oil price	97		%	99		%	99		%
Natural gas (per Mcf)	$	1.97		$	2.02
Natural gas (per Mcf)	$	3.16		$	2.32		$	2.66
Effect of realized derivatives settlements (per Mcf)	0.06			—
Effect of realized derivatives settlements (per Mcf)	(0.24		)	0.25			0.94
Natural gas, after hedging (per Mcf)	$	2.03		$	2.02
Natural gas, after hedging (per Mcf)	$	2.92		$	2.57		$	3.60
NGLs (per bbl)	$	12.52		$	18.47
NGLs (per bbl)	$	14.11		$	21.18		$	26.41
Effect of realized derivatives settlements (per bbl)	—			—
Effect of realized derivatives settlements (per bbl)	—			—			—
NGLs, after hedging (per bbl)	$	12.52		$	18.47
NGLs, after hedging (per bbl)	$	14.11		$	21.18		$	26.41
Revenue
Revenue
Oil sales	$	90,668		$	75,291
Oil sales	$	86,363		$	40,278		$	30,972
Natural gas sales	12,384			7,980
Natural gas sales	18,450			5,210			4,276
NGL sales	10,251			10,241
NGL sales	11,216			4,714			4,000
Total sales revenue	$	113,303		$	93,512
Total E&P sales revenue	$	116,029		$	50,202		$	39,248

Oil ~~revenue~~sales for the ~~2019~~Second Quarter 2019 increased ~~compared to the 2018 Quarter~~ due to an ~~increase in~~increased production ~~in the 2019 Quarter~~, partially offset by lower average sales prices before hedging. The increase in production ~~in the 2019 Quarter~~ was due to the extensive development program conducted following the Business Combination.

Natural gas ~~revenue~~sales for the ~~2019~~Second Quarter 2019 increased ~~compared~~ toprimarily ~~the 2018 Quarter~~ due to anincreased ~~increase in~~ production ~~in the 2019 Quarter~~ as a result of the extensive development program ~~during~~conducted ~~2018~~following ~~and~~the ~~higher~~Business ~~prevailing market prices~~Combination.

25NGL sales for the Second Quarter 2019 increased modestly due to increased 2019 production, mostly offset by lower average prices. The increase in production volume was primarily due to the impact of our development activities after the Business Combination.

Derivatives

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



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

~~Gain~~Decreases ~~(loss)~~and onincreases ~~sale~~in offuture ~~assets~~commodity ~~and~~prices ~~other~~during ~~for~~each ~~the~~period ~~2019~~compared ~~Quarter~~to ~~included~~futures aprices ~~gain~~in ~~from~~effect at the ~~sale~~time of ~~seismic~~execution ~~data~~of ~~totaling~~our ~~$1.5~~outstanding ~~million compared~~derivatives toresulted ain ~~similar~~the ~~gain~~gains ofand ~~$5.9~~losses ~~million~~recognized, respectively, during ~~the~~each ~~2018 Quarter~~quarter.

Derivatives

	Successor						Predecessor
(in thousands)	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 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

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

Operating Expenses

	Successor				Predecessor
(in thousands, except per unit data)	Second Quarter 2019		Second Quarter 2018
(in thousands, except per unit data)	Three Months EndedMarch 31, 2019		February 9, 2018ThroughMarch 31, 2018		January 1, 2018ThroughFebruary 8, 2018
Operating expenses:
Operating expenses:
Lease operating	$	19,123	$	12,679
Lease operating	$	25,108	$	8,317	$	4,408
Transportation and marketing	19,614		11,206
Transportation and marketing	17,761		5,582		3,725
Production taxes	5,117		2,606
Production taxes	5,483		1,415		953
Workovers	412		333
Workovers	197		1,245		423
Exploration	3,289		8,083
Exploration	2,054		1,585		7,003
Depreciation, depletion and amortization	34,504		26,670
Depreciation, depletion and amortization	34,675		11,038		11,670
Impairment of assets	6,500		—
General and administrative	2015,~~947~~723		3417,~~654~~811		~~21,234~~
Total operating expense	$	~~106~~104,~~225~~282	$	6379,~~836~~388	$	~~49,416~~
Operating expenses per BOE:
Lease operating	$	75.4261	$	65.6643	$	~~4.82~~
Transportation and marketing	5.2575		4.4780		~~4.08~~
Production taxes	1.6250		1.1312		~~1.04~~
Workovers	0.0612		10.0014		~~0.46~~
Depreciation, depletion and amortization	10.2412		811.8443		~~12.77~~

Lease operating expense for the ~~2019~~Second Quarter 2019 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.

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

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

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

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

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

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



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

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

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Index to Financial Statements

~~Transportation~~Below ~~and~~is ~~marketing~~a ~~expense~~reconciliation ~~for~~of ~~the~~our ~~2019~~income ~~Quarter~~(loss) ~~increased~~from ~~compared~~continuing tooperations ~~the~~before ~~2018~~income ~~Quarter~~taxes ~~primarily due~~ to ~~higher volumes. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for~~ our ~~residue~~Adjusted ~~gas at the tailgate of the plant.~~ EBITDAX:

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.



(in thousands)	Second Quarter 2019			Second Quarter 2018
Income (loss) from continuing operations before income taxes	$	7,746		$	(22,470	)

Interest expense	14,071			10,361
Depreciation, depletion and amortization	34,504			26,670
Exploration	3,289			8,083
Loss (gain) on unrealized hedges	(11,868		)	14,860
Impairment of assets	6,500			—
Equity-based compensation	1,396			3,621
Severance costs	609			—
Strategic costs	4,061			—
Business Combination	—			443
Adjusted EBITDAX	$	60,308		$	41,568

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

	Successor						Predecessor
(in thousands)	Second Quarter 2019			Second Quarter 2018
(in thousands)	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 8, 2018
Alta Mesa RBL	$	5,204		$	—
Exploration expense:
2024 Notes	9,844			9,844
Geological and geophysical costs	$	312		$	451		$	2,440
Bond premium amortization	(1,231		)	(1,231		)
Dry hole expense	—			—			—
Deferred financing cost amortization	94			80
Other exploration expense, including expired leases	1,695			833			4,504
Other	160			1,668
ARO settlements in excess of recorded liabilities	47			301			59
Total interest expense	14,071			10,361
Total exploration expense	$	2,054		$	1,585		$	7,003
Interest income and other	(54		)	(820		)
Total other expense, net	$	14,017		$	9,541

~~Exploration~~Interest expense for the ~~2019~~Second Quarter ~~decreased~~2019 ~~compared~~increased due primarily to ~~the~~increased ~~2018~~levels ~~Quarter~~of ~~primarily~~borrowings ~~due~~under tothe ~~our~~Alta ~~cost~~Mesa ~~reduction~~RBL. Other ~~efforts~~interest ~~and~~expense aincludes ~~decrease~~commitment infees ~~expenses~~and ~~relating~~interest expense related to ~~expired~~our orjoint ~~expiring~~development ~~leaseholds~~agreement with BCE.

	Successor				Predecessor
(in thousands)	Three Months EndedMarch 31, 2019		February 9, 2018ThroughMarch 31, 2018		January 1, 2018ThroughFebruary 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

General and administrative expense for the 2019 Quarter decreased compared to the 2018 Quarter primarily due to nonrecurring strategic costs and professional fees incurred in the 2018 Quarter for advisors helping to value and integrate the acquired business pursuant to the Business Combination. General and administrative expense in the Successor Periods also include equity-based compensation awards with no similar activity in the Predecessor Period. Employee-related costs primarily increased due to higher employee expenses compared to the 2018 Quarter reflecting the increase in production activity during 2018. Following a reassessment of 2019 activity levels, we implemented a reduction in force program during the 2019 Quarter which resulted in an increase in severance costs for the current period.

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

Table of Contents

Index to Financial Statements

	Successor						Predecessor
(in thousands)	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 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

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

The ~~Company’s~~tables ~~management~~included ~~believes~~below ~~Adjusted~~set ~~EBITDAX~~forth isfinancial ~~useful~~information ~~because~~for itthe ~~allows~~Successor ~~users~~Periods toand ~~more~~Predecessor ~~effectively evaluate our operating performance~~Period, ~~compare~~which ~~the~~are ~~results~~distinct ofreporting ~~our~~periods. The ~~operations~~Predecessor ~~from~~Period ~~period~~amounts tobelow ~~period~~exclude ~~and~~operating ~~against~~results ~~our~~related ~~peers without regard~~ to ~~our~~discontinued ~~financing~~operations. For ~~methods~~simplicity, ~~or capital structure and because it highlights trends~~ in our ~~business~~discussion ~~that~~below, ~~may~~we ~~not~~refer ~~otherwise~~to bethe ~~apparent~~combined ~~when~~periods ~~relying~~February ~~solely~~9, on2018 ~~GAAP~~through ~~measures.~~June ~~Adjusted EBITDAX should not be considered as an alternative to our net income (loss)~~30, ~~operating~~2018 ~~income (loss) or other performance measures derived in accordance with GAAP~~ and ~~may~~January ~~not~~1, be2018 ~~comparable~~through toFebruary ~~similarly~~8, ~~titled~~2018 ~~measures~~as inthe ~~other~~“2018 ~~companies’ reports~~period”.

Revenue

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



	Successor						Predecessor
(in thousands, except per unit data)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Net production:
Oil (Mbbls)	3,164			1,774			494
Natural gas (MMcf)	12,114			6,192			1,609
NGLs (Mbbls)	1,614			777			151
Total (MBoe)	6,797			3,583			914

Average net daily production volumes:
Oil (Mbblsd)	17.5			12.5			12.7
Natural gas (MMcfd)	66.9			43.6			41.2
NGLs (Mbblsd)	8.9			5.5			3.9
Total (MBoed)	37.6			25.2			23.4

Average sales prices:
Oil (per bbl)	$	55.94		$	65.16		$	62.68
Effect of realized derivatives settlements (per bbl)	0.61			(11.01		)	(6.44		)
Oil, after hedging (per bbl)	$	56.55		$	54.15		$	56.24
Percentage of unhedged realized oil price to NYMEX oil price	97		%	99		%	99		%

Natural gas (per Mcf)	$	2.55		$	2.13		$	2.66
Effect of realized derivatives settlements (per Mcf)	(0.08		)	0.09			0.94
Natural gas, after hedging (per Mcf)	$	2.47		$	2.22		$	3.60

NGLs (per bbl)	$	13.30		$	19.25		$	26.41
Effect of realized derivatives settlements (per bbl)	—			—			—
NGLs, after hedging (per bbl)	$	13.30		$	19.25		$	26.41

Revenue
Oil sales	$	177,031		$	115,569		$	30,972
Natural gas sales	30,834			13,190			4,276
NGL sales	21,467			14,955			4,000
Total sales revenue	$	229,332		$	143,714		$	39,248

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Index to Financial Statements

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

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

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

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

Derivatives



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

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

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Index to Financial Statements

Operating Expenses



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

Operating expenses per BOE:
Lease operating	$	6.51	$	5.86	$	4.82
Transportation and marketing	5.50		4.69		4.08
Production taxes	1.56		1.12		1.04
Workovers	0.09		0.44		0.46
Depreciation, depletion and amortization	10.18		10.52		12.77

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

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

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

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



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

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Index to Financial Statements

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

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



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

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

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Index to Financial Statements

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



	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Income (loss) from continuing operations before income taxes	$	(16,979	)	$	(57,071	)	$	(7,116	)

Interest expense	26,901			15,557			5,511
Depreciation, depletion and amortization	69,179			37,708			11,670
Exploration	5,343			9,668			7,003
Loss (gain) on unrealized hedges	12,274			32,896			(8,959		)
Loss on sale of property and equipment	—			63			—
Impairment of assets	6,500			—			—
Equity-based compensation	3,057			6,389			—
Severance costs	4,584			—			—
Strategic costs	4,061			—			—
Business Combination	10			23,717			17,040
Adjusted EBITDAX	$	114,930		$	68,927		$	25,149

Other (Income) Expense

	Successor						Predecessor
(in thousands)	~~Three~~Six Months ~~EndedMarch~~EndedJune 3130, 2019			February 9, ~~2018ThroughMarch~~2018ThroughJune 3130, 2018			January 1, 2018ThroughFebruary 8, 2018
Alta Mesa RBL	$	38,~~579~~783		$	~~278~~252		$	815
2024 Notes	919,~~844~~688			616,~~561~~406			3,281
Bond premium amortization	(12,~~231~~462		)	(~~820~~2,051		)	—
Deferred financing cost amortization	45139			—80			171
Other	~~593~~753			~~(823~~870		)	1,244
Total interest expense	1226,~~830~~901			515,~~196~~557			5,511
Interest income and other	(2781		)	(~~546~~1,366		)	(172		)
Total other expense, net	$	1226,~~803~~820		$	414,~~650~~191		$	5,339

Interest expense for the 2019 ~~Quarter~~period increased ~~$2.1 million compared to the 2018 Quarter~~ primarily due to increased levels of borrowing under the Alta Mesa RBL. ~~Deferred financing costs related to the Alta Mesa RBL and the premium associated with our 2024 Notes are being amortized over the remaining term of each obligation.~~ Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, development activities and to satisfy our contractual obligations related to servicing our debt and hedges. During ~~the~~ 2019 ~~Quarter~~, our main sources of liquidity and capital resources ~~came~~have come from operating cash flow and borrowings under the Alta Mesa RBL, including a $66.5 million draw in April 2019.

28During April 2019, our borrowing base was reduced from $400.0 million to $370.0 million as part of the semi-annual redetermination. At June 30, 2019, we had outstanding borrowings of approximately $344.5 million and outstanding letters of credit of $20.2 million, leaving us $5.3 million of remaining borrowing capacity. We held $78.3 million of cash and cash equivalents on hand at June 30, 2019. We do not anticipate maintaining compliance with the consolidated total leverage ratio

Table of Contents

Index to Financial Statements

~~During~~covenant ~~April~~in ~~2019,~~the ~~our~~Alta ~~borrowing~~Mesa ~~base~~RBL ~~was~~as ~~reduced~~early ~~from~~as ~~$400.0~~the ~~million~~measurement todate ~~$370~~of September 30, 2019.0 ~~million~~Also, asin ~~part~~August of2019 the ~~semi-annual~~lenders ~~redetermination. We~~exercised ~~currently~~their ~~have~~ability ~~outstanding~~to ~~borrowings~~make ofan ~~approximately~~optional ~~$350.0million~~redetermination ~~and~~of ~~outstanding~~our ~~letters~~borrowing ofbase ~~credit~~ahead of ~~$20.0~~the ~~million,~~regular ~~leaving~~redetermination usscheduled noin ~~additional~~October ~~remaining~~2019, ~~borrowing~~and ~~capacity. We~~via ~~had~~this ~~$93.7~~redetermination, ~~million~~our ofborrowing ~~cash~~base atwas ~~May~~reduced ~~31,~~to ~~2019~~$200 million. WeAs ~~have not obtained covenant relief~~such, ~~but~~we ~~that~~are ~~remains~~required anto ~~important~~repay ~~objective~~the ~~for us~~$162. As4 ~~referenced~~million ~~above,~~of wecombined ~~may~~excess beof atour ~~risk~~borrowings ofand ~~non-compliance~~letters ~~with~~of ~~the~~credit ~~Consolidated~~outstanding ~~Total~~ratably ~~Leverage~~over ~~Ratio~~five ~~Covenant~~months in ~~the~~$32.5 ~~Alta~~million ~~Mesa~~installments, ~~RBL~~which aswill ~~early~~have asan ~~the~~adverse ~~June~~impact ~~30,~~on ~~2019~~our ~~measurement date~~liquidity. InThe ~~addition,~~first ~~the~~payment ~~lenders~~is ~~under~~due ~~the~~in ~~Alta~~September ~~Mesa~~2019. If ~~RBL~~we ~~have~~are anunable ~~ability~~ to make anrepayment ~~optional~~of ~~redetermination~~this ~~ahead~~amount, ofwe ~~the~~will ~~regular~~be ~~redetermination~~ in ~~October~~default ~~2019. If the outstanding borrowings~~ under the Alta Mesa RBL. As ~~were~~a toconsequence ~~exceed~~of ~~the~~both ~~borrowing~~reduced ~~base~~operating ~~due~~cash toflow ~~any~~and ~~such~~a ~~redetermination~~reduced borrowing base, we ~~would~~may behave ~~required~~limited ability to ~~repay~~obtain the ~~excess~~capital ~~ratably~~necessary ~~over~~to ~~five~~conduct ~~months,~~our ~~which~~operations ~~could~~at ~~have~~desired ~~an adverse impact on our liquidity~~levels. Our general partner’s board of directors 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, occurs and the Alta Mesa RBL lenders were to accelerate repayment, it may result in an ~~event~~acceleration of ~~default and an acceleration under~~ the 2024 Notes. We have concluded that these and other circumstances create substantial doubt regarding our ability to continue as a going concern. ~~Assuming~~ ~~covenant~~We ~~relief~~currently ~~can~~anticipate ~~be obtained, we believe~~ that our ~~combined~~indebtedness ~~future operating cash flow and cash currently on our balance sheet~~ will beaccelerate ~~sufficient~~prior to ~~allow~~July ~~us to carry out our desired 2019 development program~~1, ~~despite~~2020 ~~the associated negative free cash flow. Our ability to reduce well costs~~ and totherefore, ~~more~~have ~~precisely~~reported ~~assess~~all ~~the productivity~~ of ~~wells under~~ our ~~new~~debt ~~spacing design tests are important to our success in 2019~~ as wecurrent ~~evaluate~~at ~~our~~June ~~future~~30 ~~prospects and opportunities~~2019.

Our future drilling plans and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, midstream availability, other working interest owner participation and regulatory matters. Any deferral of planned capital expenditures, particularly with respect to bringing new wells onto production, could reduce our anticipated production, revenue and cash flow, and 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.

WeAlthough we are currently capitally constrained, we strive to maintain financial flexibility and, if ~~they are~~ available ~~to us~~ on terms we find acceptable, we may access the capital markets to facilitate 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 which would have an adverse impact on our ability to develop our acreage as we would have otherwise planned.

WeWith ~~expect~~our $370.0 million borrowing base, we expected to operate 2-3 rigs during the remainder of 2019 to develop our assets, particularly to focus on testing the spacing patterns we believe to be optimal, and to ~~implement~~continue executing our cost reduction strategies begun earlier in 2019. If Prior ~~we have adequate liquidity~~ to ~~fund~~the ~~such~~August ~~operations~~2019 redetermination, we ~~expect~~anticipated todrilling ~~drill~~ and ~~bring~~bringing online approximately 60 to 65 wells during 2019 while incurring approximately $140.0 million to $155.0 million of capital expenditures ~~related~~under toa ~~this~~2-rig ~~development~~ program. We also ~~expect~~expected that an additional $1820.0 million to $2330.0 million could be incurred for other non-operated projects, leasehold costs and capitalized workover activity. Following the redetermined borrowing base of $200 million in August 2019, we decided to operate 1 rig starting in September. We will continue to evaluate how much, if any, development is appropriate going forward. We do not expect our 2019 operating cash flow alone to provide sufficient proceeds to meet ~~this~~our ~~level~~2019 ofcapital expenditure, ~~which~~levels ~~will~~and ~~require~~we uswould tobe ~~most~~required ~~likely~~to utilize existing cash on hand.

As we execute our business strategy, we will ~~continually~~ monitor the capital resources available to meet future financial obligations and planned capital expenditures. We ~~believe our cash flows provided by operating activities and available cash on hand will allow us to pursue our currently planned development activities. We~~ cannot provide assurance that operations and other needed capital will be available on acceptable terms, or at all, and our development pace may need to change based on our evolving liquidity profile.

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Index to Financial Statements

Cash ~~flow~~Flow Analysis

	Successor						Predecessor
(in thousands)	~~Three~~Six Months ~~EndedMarch~~EndedJune 3130, 2019			February 9, ~~2018ThroughMarch~~2018ThroughJune 3130, 2018			January 1, 2018ThroughFebruary 8, 2018
Cash from operating activities	$	2961,~~935~~818		$	(4945,~~311~~489	)	$	26,336
Cash from investing activities	(~~133~~180,~~077~~138		)	(~~129~~307,~~310~~743		)	(37,913		)
Cash from financing activities	~~117~~183,~~000~~500			~~425~~417,~~272~~913			16,932
Net increase in cash, cash equivalents and restricted cash	$	1365,~~858~~180		$	~~246~~64,~~651~~681		$	5,355

Cash flow from operating activities

	Successor						Predecessor
(in thousands)	Three Months EndedMarch 31, 2019			February 9, 2018ThroughMarch 31, 2018			January 1, 2018ThroughFebruary 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

During the 2019 period, cash-based items of net income (loss), including revenue (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense totaled $73.9 million compared to $29.2 million during the 2018 period, due largely to higher revenues associated with increased production and the lack of costs associated with the Business Combination that were incurred in 2018. Approximately $12.0 million of cash was used to increase working capital during the six months ended June 30, 2019. During the 2018 period, cash totaling $48.4 million was used to increase working capital primarily due to increases in trade receivables and amounts due from related parties for administrative services provided, including certain other transactions, and to reduce liabilities arising prior to or as a result of the Business Combination.

During the 2019 Quarter, cash-based items of net income (loss), including revenue (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense were $35.7 million as compared to $1.4 million during the 2018 Quarter. Changes in working capital and other assets and liabilities resulted in a decrease in cash of approximately $5.7 million as compared to a decrease of $24.4 million during the 2018 Quarter. The increase in cash from operating activities of $52.9 million is primarily related to Business Combination Costs of $40.7 million incurred in the 2018 Quarter. In addition, the 2018 Quarter included net loss from Discontinued Operations of $7.7 million.

Cash flow from investing activities

	Successor						Predecessor
(in thousands)	~~Three~~Six Months ~~EndedMarch~~EndedJune 3130, 2019			February 9, ~~2018ThroughMarch~~2018ThroughJune 3130, 2018			January 1, 2018ThroughFebruary 8, 2018
Cash provided by (used for)
Capital expenditures	$	(~~133~~180,~~077~~138	)	$	(~~129~~319,~~310~~042	)	$	(36,695	)
Acquisition of acreage	—			—			(1,218		)
Cash from investing activities	$	(133,077	)	$	(129,310	)	$	(37,913	)
Proceeds from sale of property and equipment	—			11,299			—
Cash from investing activities	$	(180,138	)	$	(307,743	)	$	(37,913	)

During the 2019 ~~Quarter~~period, ~~cash spent for~~ capital expenditures included $8491.26 million for additions to property and equipment that occurred prior to December 31, 2018. Capital spending during 2019 has decreased significantly from 2018 as a result of the reassessment of our current drilling plans due to the results obtained from our 2018 drilling program and our existing liquidity concerns. We ran as many as 9 rigs during the 2018 period.

Cash flow from financing activities

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Index to Financial Statements

	Successor					Predecessor
(in thousands)	~~Three~~Six Months ~~EndedMarch~~EndedJune 3130, 2019		February 9, ~~2018ThroughMarch~~2018ThroughJune 3130, 2018			January 1, 2018ThroughFebruary 8, 2018
Cash provided by (used for)
Proceeds from long-term debt borrowings	$	~~117~~183,~~000~~500	$	—		$	60,000
Repayments of long-term debt	—		(134,065		)	(43,000		)
Capital contributions (distributions), net	—		~~560~~553,344			(68		)
Other	—		(1,~~007~~366		)	—
Cash from financing activities	$	~~117~~183,~~000~~500	$	~~425~~417,~~272~~913		$	16,932

During the 2019 ~~Quarter~~period, our outstanding balance owed under the Alta Mesa RBL increased by $~~117~~183.05 million from December 31, 2018, largely related to borrowings to fund of our capital expenditures, including those expenditures incurred in 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~~.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk and Hedges

WeOur ~~forecast~~major ~~our~~market risk exposure is to prices for oil, gas and NGLs, which have historically been volatile. As such, future ~~production~~results ~~based~~are onsubject ~~information~~to change due to changes in ~~our~~these ~~December 31,~~prices. ~~2018~~Realized ~~reserve~~prices ~~report~~are ~~for~~primarily ~~all~~driven ~~reserve~~by ~~categories~~the ~~using~~prevailing ~~estimates~~worldwide price for ~~future~~oil ~~pricing,~~and ~~costs~~regional prices for gas. We have used, and ~~other~~expect ~~assumptions~~to ~~that~~continue ~~may~~to ~~prove~~use, derivatives to bereduce ~~inaccurate~~our exposure to the risks of price changes. ~~Our~~ ~~actual~~Pursuant ~~production~~to ~~will~~our ~~vary~~risk ~~from~~management ~~the~~policy, ~~amounts~~we ~~estimated~~engage in ~~the~~these ~~report,~~activities ~~perhaps~~as ~~materially~~a hedging mechanism against low prices and price volatility associated with developed and undeveloped reserves.

~~Our~~Forecasted ~~major~~production ~~market~~from ~~risk~~proved ~~exposure~~reserves is ~~associated~~estimated ~~with~~in ~~prices~~our ~~for oil~~December 31, ~~gas~~2018 ~~and~~reserve ~~NGLs,~~report ~~which~~using ~~have historically been volatile. As such~~prices, ~~future~~costs ~~results~~and ~~are~~other ~~subject~~assumptions torequired ~~change~~by ~~due~~SEC ~~to changes in these prices~~rules. Our ~~Realized~~actual ~~prices~~production ~~are~~will ~~primarily~~vary ~~driven~~from by the ~~prevailing~~amounts ~~worldwide~~estimated ~~price~~in ~~for~~the ~~oil~~report, ~~and~~perhaps ~~regional prices for gas~~materially. Our WeRisk ~~have~~Factors ~~used,~~in ~~and expect to continue to use, derivatives to reduce~~ our ~~exposure~~2018 to10-K ~~the~~contain ~~risks~~discussions of ~~price~~significant ~~changes.~~matters ~~Pursuant~~related to ~~our~~future ~~risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated with developed and undeveloped reserves~~production.

The fair value of our oil and gas derivatives and basis swaps at ~~March~~June 3130, 2019 was a net ~~liability~~asset of $6.72 million. A 10% increase or decrease in oil and gas prices (with all other factors held constant) would result in an unrealized loss or gain in the fair value of our oil and gas derivatives for the ~~2019~~six ~~Quarter~~months ended June 30, 2019 of $~~24,429~~7.7 million and $18.9 million,~~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, and are lenders under the Alta Mesa RBL.

Our principal ongoing exposures to credit risk are from joint interest receivables and receivables from the sale of our oil and gas production. 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~~a ~~first~~portion ~~quarter~~ of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs~~. Effective~~ asfor ofa ~~June~~marketing 1,fee ~~2019,~~that weis ~~have~~deducted ~~terminated~~from ~~our~~sales ~~oil~~proceeds ~~and~~collected ~~NGL~~by ~~marketing~~ARM ~~agreement~~from ~~with~~purchasers. ~~ARM~~The ~~and~~sales ~~will~~are ~~market~~generally ~~such~~made ~~products~~under ~~internally. We~~short-term ~~have~~contracts ~~extended~~with ~~the~~month-to-month ~~term~~pricing ofbased ~~our~~on ~~gas~~published ~~marketing~~regional ~~agreement~~indices, ~~with~~adjusted ~~ARM~~for ~~through~~transportation, ~~November~~location ~~30,~~and ~~2019~~quality. In March 2019, in preparation for ~~the~~handling ~~return~~oil ofand NGL marketing responsibilities internally, we began receiving

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~~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~~As of June 1, ~~with~~2019, ~~respect~~we toterminated ~~gas~~our ~~sales,~~oil ~~ARM~~and ~~continues~~NGL tomarketing ~~collect~~agreement ~~payments~~with ~~from~~ARM ~~purchasers,~~and ~~deducts~~have ~~their~~begun marketing ~~fee~~such ~~and~~products ~~remits~~internally. We have extended the ~~balance~~term toof usour gas marketing agreement with ARM through November 30, 2019.

For the ~~2019~~six ~~Quarter~~months ended June 30, 2019, ARM marketed $8391.85 million, or 7139.98% of our operating revenue for the period.

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

Interest Rates

We are subject to interest rate risk under the Alta Mesa RBL. We currently have no open interest rate derivatives. A 100 basis point increase in interest rates would increase annual interest expense on the Alta Mesa RBL by approximately $23.84 million, based on the balance outstanding at ~~March~~June 3130, 2019.

Inflation

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15 and 15d-15 of the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, performed an evaluation of our disclosure controls and procedures. Our controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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


•	establishment of formal policies and procedures;


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


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


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

Changes in Internal Control Over Financial Reporting (ICFR)

While we have made progress in multiple areas to improve ICFR, management is continuing to implement the remediation plan described in our 2018 ~~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 operations subsequent to the Business Combination.

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

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. There have been no material changes during the 2019 ~~Quarter~~period to the risk factors described under ~~Item 1A.~~ Risk Factors in our 2018 ~~Annual Report on Form~~ 10-K.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

~~On June 10, 2019, Mr~~None. 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.37

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.

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Item 6. Exhibits

ExhibitNumber	Description of Exhibit
2.1	Contribution Agreement, dated as of August 16, 2017, by and among High Mesa Holdings, LP, High Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, Silver Run Acquisition Corporation II, and, solely for certain provisions therein, the Contributor Owners party thereto (incorporated by reference to Exhibit 2.1 to Alta Mesa Holdings, LP’s Form 8-K filed with the SEC on August 17, 2017 (File No. 333-173751))
3.1	Articles of Organization of Alta Mesa Holdings GP, LLC, dated September 26, 2005 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.2	Sixth Amended and Restated Limited Liability Company Agreement of Alta Mesa Holdings GP, LLC, dated February 9, 2018 (incorporated by reference from Exhibit 3.2 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on February 14, 2018 (File No. 333-173751)).
3.3	Certificate of Limited Partnership of Alta Mesa Holdings, LP, dated September 26, 2005 (incorporated by reference from Exhibit 3.3 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.4	Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa Holdings, LP, dated as of February 9, 2018 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on February 14, 2018 (File No. 333-173751)).
3.5	Certificate of Incorporation of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.7 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.6	Bylaws of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.8 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
4.1	Indenture, dated December 8, 2016, by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated by reference from Exhibit 4.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on December 8, 2016 (File No. 333-173751)).
4.2	Registration Rights Agreement, dated December 8, 2016, by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp., the Guarantors named therein and Wells Fargo Securities, LLC, as representative of the Initial Purchasers (incorporated by reference from Exhibit 4.2 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on December 8, 2016 (File No. 333-173751)).
10.1	~~Employment~~Separation Agreement, dated as of ~~January~~July 72, 2019, by and between Ronald J. Smith and Alta Mesa Services, LP ~~and John C. Regan~~ (incorporated by reference from ~~Exhibit~~exhibit 10.81 to Alta Mesa Holdings, LP’s ~~annual~~current report on Form 108-K filed with the SEC on ~~May~~July 178, 2019 (~~file~~File No. 333-173751)).
10.2	Separation Agreement dated as of March 26, 2019 by and between Craig W. Collins and Alta Mesa Services, L.P. (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on March 28, 2019 (File No. 333-173751)).
10.4	Independent Manager Agreement, dated June 12, 2019, between Alta Mesa Holdings GP, LLC and Patrick J. Bartels Jr. (incorporated by reference from Exhibit 10.4 to Alta Mesa Holdings, LP’s Quarterly Report on Form 10-Q filed with the SEC on June 13, 2019.)
10.3	Form 2019 Incentive Program Letter Agreement (incorporated by reference from Exhibit 10.2 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on March 28, 2019 (File No. 333-173751)).
10.4*	Independent Manager Agreement, dated June 12, 2019, between Alta Mesa Holdings GP, LLC and Patrick J. Bartels Jr.
31.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101*	Interactive data files.

* filed herewith.

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SIGNATURES

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

		ALTA MESA HOLDINGS, L.P.
		ALTA MESA HOLDINGS, LP
		By: Alta Mesa Holdings GP, LLC
		Its general partner
		(Registrant)
By	/s/ John C. Regan
	John C. Regan
	Chief Financial Officer (Principal Financial Officer)
	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
Dated	~~June~~August 1327, 2019

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