10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_______________________________________

FORM 10-K

_______________________________________

(Mark One)

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

For the fiscal year ended: December 31, 2019

OR

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

For the transition period from            to

Commission file number: 001-38040

_______________________________________

ALTA MESA RESOURCES, INC.

(Exact name of registrant as specified in its charter)

_______________________________________

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

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

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes  ☐    No  ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    

Yes  ☐     No  ☒  

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files.)    Yes  ☒    No  ☐ 

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

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

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

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of June 28, 2019 (the last business day of the registrant’s most recently completed second fiscal quarter) was $16,522,531 based on the closing price of the shares of common stock on that date.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes  ☐    No  ☐ 

As of January 31, 2020, there were 182,791,388 shares of Class A Common Stock and 199,987,976 shares of Class C Common Stock, par value $0.0001 per share outstanding. The shares of Class A Common Stock shown as outstanding do not include 477,797 unvested restricted stock awards outstanding as of January 31, 2020.

Portions of the registrant’s definitive Proxy Statement for its 2020 annual meeting of shareholders, which will be filed with the Securities and Exchange Commission on Schedule 14A within 120 days after the end of 2019, will be incorporated by reference into Part III of this Form 10-K to the extent indicated therein upon such filing.

Table of Contents

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		Page
	Glossary	i
	Cautionary Statement Regarding Forward-Looking Statements	1
	PART I
Item 1.	Business	2
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	10
Item 2.	Properties	10
Item 3.	Legal Proceedings	15
Item 4.	Mine Safety Disclosures	18
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	18
Item 6.	Selected Financial Data	19
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	37
Item 8.	Financial Statements and Supplementary Data	38
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	96
Item 9A.	Controls and Procedures	96
Item 9B.	Other Information	98
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	98
Item 11.	Executive Compensation	98
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	98
Item 13.	Certain Relationships and Related Transactions, and Director Independence	98
Item 14.	Principal Accounting Fees and Services	98
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	99
Item 16.	Form 10-K Summary	102
	Signatures	103

Glossary of Terms

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

Company Specific Terms -
2018 Predecessor Period -	The period from January 1, 2018 through February 8, 2018.
2018 Successor Period -	The period from February 9, 2018 through December 31, 2018.
2024 Notes -	$500 million outstanding principal amount of senior unsecured notes of Alta Mesa bearing interest at 7.875%, payable semi-annually, scheduled to mature in December 2024.
Additional Debtors -	The KFM Debtors and the SRII Debtors combined.
Alta Mesa -	Alta Mesa Holdings, LP, which conducts our Upstream activities.
Alta Mesa GP -	Alta Mesa Holdings GP, LLC, a majority owned subsidiary of SRII Opco, LP.
Alta Mesa RBL -	Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, as amended. This credit agreement is a reserve based loan or RBL.
AMH Debtors -	Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP.
AMH PSA -	Amended & Restated Purchase and Sale Agreement by and among Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp., Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP, as Seller and BCE-Mach III LLC, as Buyer, and Alta Mesa Resources, Inc., dated January 17, 2020.
AMH Sale Transaction -	The expected sale by the AMH Debtors of substantially all of their assets to BCE-Mach III LLC pursuant to the AMH PSA.
AMR -	Alta Mesa Resources, Inc.
ARM -	ARM Energy Management, LLC, a company that markets our oil and gas production and provides services relating to our derivatives.
Bankruptcy Code -	Chapter 11 of the United States Bankruptcy Code.
Bankruptcy Court -	United States Bankruptcy Court for the Southern District of Texas.
BCE -	BCE-STACK Development LLC, a fund advised by Bayou City Management, LLC.
Business Combination -	The acquisition by Alta Mesa Resources, Inc. of controlling interests in Alta Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, and KFM Midstream, LLC.
Buyer -	BCE-Mach III LLC.
Debtors -	The Initial Debtors and Additional Debtors combined.
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.
Initial Debtors -	Alta Mesa Resources, Inc., Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP.
KFM -	Kingfisher Midstream, LLC, which conducts our Midstream activities.
KFM Credit Facility -	Kingfisher Midstream, LLC amended and restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent.
KFM Debtors -	Kingfisher Midstream, LLC, Kingfisher STACK Oil Pipeline, LLC, Oklahoma Produced Water Solutions, LLC and Cimarron Express Pipeline, LLC.
KFM PSA -	Amended and Restated Purchase and Sale Agreement by and among Kingfisher Midstream, LLC, Oklahoma Produced Water Solutions, LLC, Kingfisher STACK Oil Pipeline, LLC and Cimarron Express Pipeline, LLC, as Seller, and BCE-Mach III LLC, as Buyer, dated January 17, 2020.
KFM Sale Transaction -	The expected sale by the KFM Debtors of substantially all of their assets to BCE-Mach III LLC pursuant to the KFM PSA.
Midstream -	Reportable business segment representing our midstream activities.
PSAs -	The AMH PSA and KFM PSA combined.

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PSU's -	Performance-based restricted stock units issued to employees under the Alta Mesa Resources, Inc. 2018 Long-Term Incentive Plan.
Riverstone Contributor -	Riverstone VI Alta Mesa Holdings, L.P.
Sale Transactions -	The AMH Sale Transaction and KFM Sale Transaction combined.
Sponsor -	Silver Run Sponsor II, LLC.
SRII Debtors -	SRII Opco, LP and SRII Opco GP, LLC.
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.
Tax Receivable Agreement -	Tax Receivable Agreement dated as of February 9, 2018, among Alta Mesa Resources, Inc., SRII Opco, LP, Riverstone VI Alta Mesa Holdings, L.P., and High Mesa Holdings LP.
Upstream -	Reportable business segment representing our exploration and production activities.
Wind down -	This represents the post-sale activities to conclude the affairs of the Company, including final settlement of the Company's estate.
Oil, Gas and Other Terms -
3D Seismic -	(Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional seismic data.
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 of energy content between natural gas and oil, and does not represent the price equivalency of natural gas to oil or natural gas liquids.
Boed -	One Boe per day.
Btu or British Thermal Unit -	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion -	The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil.
Condensate -	A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Cryogenic -	The process of using extreme cold to separate NGLs from the natural gas stream.
DD&A -	Depreciation, depletion and amortization.
Developed acreage -	The number of acres that are allocated or assignable to productive wells or wells capable of production.
Developed reserves -	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.

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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 exploratory 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.
EBITDA -	Earnings before interest, taxes, depreciation, depletion and amortization.
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.
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 economic quantity of production.
Horizontal drilling -	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.
Lease operating expenses -	The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a well. Such expenses include labor, supplies, repairs, utilities, environmental and safety, maintenance, allocated overhead costs, severance taxes, insurance and other expenses incidental to production, but excluding lease acquisition, drilling or completion expenses.
Mbbl -	One thousand barrels of crude oil, condensate, natural gas liquids, or produced water.
Mbbld -	One thousand barrels per day.
MBoe -	One thousand Boe.
MBoed -	One thousand Boe per day.
Mcf -	One thousand cubic feet of natural gas.
Mcfd -	One thousand cubic feet per day.
Mcfe -	One thousand cubic feet equivalent determined using the ratio of one barrel of oil, condensate or natural gas liquids to six Mcf of natural gas.
Mcfed -	Mcfe per day.
MMBoe -	One million boe.
MMBtu -	One million British thermal units.
MMBtud -	One million British thermal units per day.
MMcf -	One million cubic feet of natural gas.
MMcfd -	One million cubic feet per day.
MMcfe -	Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMcfed -	MMcfe per day.
MMBbl -	One million barrels of crude oil, condensate or natural gas liquids.

iii

Net acres -	The total acres a working interest owner has attributable to a particular number of acres, or a specified tract.
Net production -	Portion of production owned by us after production attributable to royalty and other owners.
Net revenue interest -	A working interest owner’s working interest in production after deducting royalty, overriding royalty, production payments and net profits interests.
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.
P&A -	Plug and Abandonment (P&A) is the permanent dismantlement and removal of production equipment and facilities from service at the end of an asset’s economic life.
PDNP -	Proved developed non-producing reserves.
PDP -	Proved developed producing reserves.
Produced water -	Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs.
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 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, or from existing wellbores where a relatively major expenditure is required to make the well producible.
PV-10 -	The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenue. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
Realized price -	The cash market price less all expected quality, transportation and demand adjustments.
Reserves -	Estimated remaining quantities of oil and natural gas anticipated to be economically producible from known accumulations.
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.
Royalty -	An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage.
SEC -	United States Securities and Exchange Commission.
Service well -	A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, produced water disposal, water supply for injection, observation, or injection for in-situ combustion.
Spacing -	The distance between wells producing from the same reservoir. Spacing in horizontal development plays is often expressed in terms of feet, e.g., 1000 foot spacing, and is often established by regulatory agencies.

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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.
Standardized Measure -	Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the U.S. Securities and Exchange Commission, without giving effect to non-property related expenses such as certain general and administrative expenses, interest expense and depletion, discounted using an annual discount rate of 10%.
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.
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. 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 a well or borehole.
Working interest -	The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs.
Workover -	Operations on a producing well to restore or increase production.

v

Cautionary Statement Regarding Forward-Looking Statements

The information in this Annual 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 Annual Report, regarding our 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 Annual 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.

Forward-looking statements may include statements about:

• the expected closing of the Sale Transactions;

• our expectations of outcomes in our bankruptcy proceedings;

• our ability to fulfill the transition services agreement with the buyer of our assets;

• our ability to continue as a going concern;

• our ability to comply with the requirements imposed by our bankruptcy process;

• our business strategy;

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

• 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 and our midstream services;

• the timing and amount of our future production;

• competition and government regulation;

• our ability to obtain permits and governmental approvals;

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

• our marketing of our production;

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

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

• 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;

• pending legal and environmental matters;

• our ability to retain qualified personnel during our wind-down period and the sufficiency of resources to conduct the wind down;

• general economic conditions;

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

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

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. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, the Buyer’s ability and willingness to close the Sale Transactions, orders by the Bankruptcy Court that impact the ability to fund and conduct our operations, liabilities resulting from litigation or the SEC investigation, 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, 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, cyber-attacks, title defects, limited control over non-operated properties, our ability to satisfy future cash obligations, restrictions in our debt agreements, and the other risks with the wind down of our operations.

Estimating quantities of oil, natural gas and NGL reserves is complex and inexact. The process 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 a number of economic assumptions, such as oil, natural gas and NGL prices, the relative mix of oil,

1

natural gas and NGLs that will be ultimately produced, drilling and operating expenses, 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 prices and costs assumed for purposes of these estimates.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously.

Should one or more of the risks or uncertainties described in this Annual Report 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 Annual Report.

PART I

Item 1. Business

Overview

Alta Mesa Resources, Inc. (“AMR”), together with its consolidated subsidiaries (“we”, “us”, “our” or “the Company”), is an independent exploration and production company focused on the development of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generates revenue primarily through long-term, fee-based contracts. Our principal offices are at 15021 Katy Freeway, Suite 400, Houston, Texas 77094 and our main phone number is (281) 530-0991.

We were originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II. On March 29, 2017, we consummated our initial public offering (“IPO”). Proceeds from the IPO and a private sale of warrants were placed in a trust account and were used on February 9, 2018, to acquire the interests in Alta Mesa, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and KFM through a newly formed subsidiary, SRII Opco, LP (“SRII Opco”) in a transaction referred to as the “Business Combination” at which time we changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.”.

On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).

On January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.

The Initial and Additional Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

On December 31, 2019, the Initial Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “AMH PSA”) with BCE-Mach III LLC (the “Buyer”) pursuant to which the AMH Debtors agreed to sell to the Buyer substantially all of our upstream assets for an unadjusted purchase price of $232.0 million in cash, subject to customary purchase price adjustments (such transaction, the “AMH Sale Transaction”). On December 31, 2019, the KFM Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “KFM PSA” and, together with the AMH PSA, the “PSAs”) with the Buyer pursuant to which the KFM Debtors agreed to sell to the Buyer substantially all of our midstream assets for an unadjusted purchase price of $88.0 million in cash, subject to customary purchase price adjustments (such transaction, the “KFM Sale Transaction” and, together with the AMH Sale Transaction, the “Sale Transactions”).

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The Sale Transactions are expected to close no later than mid-April 2020, after which we will no longer own any operating assets. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

In March 2020, AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the “AMR Plan”). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH’s creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A common stock and class C common stock in the Company are expected to be canceled.

The AMR Plan will be subject to approval by the Bankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent that the AMR Plan is confirmed by the Bankruptcy Court, AMR expects the AMR Plan to become effective and be consummated shortly thereafter.

In March 2020, the KFM Debtors filed a Chapter 11 plan (the “KFM Plan”). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors’ estates. Under the KFM Plan, the KFM Debtors will appoint a plan administrator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation.

The KFM Plan is subject to approval by the Bankruptcy Court and the KFM Debtors are expected to solicit votes on the KFM Plan from certain of the KFM Debtors’ creditors pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the KFM Plan in April 2020. To the extent that the KFM Plan is confirmed by the Bankruptcy Court, KFM expects the KFM Plan to become effective and be consummated shortly thereafter.

Our Class A Common Stock and public warrants to purchase Class A Common Stock, sold as part of the shares issued in the IPO, were initially traded on the NASDAQ Capital Market (“NASDAQ”), but due to our failure to continue to meet the NASDAQ’s listing requirements, trading in our stock and public warrants was suspended in September 2019, and are now traded over the counter on the OTC Pink Marketplace under the symbols “AMRQQ” and “AMRWQ”, respectively. In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act. Accordingly, we do not anticipate filing any additional current, quarterly or annual reports with the SEC.

Going Concern

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.

We expect to sell substantially all of our assets no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

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These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.

Organizational Structure

The following diagram illustrates our ownership structure as of December 31, 2019.

Business Combination

As described further in Item 8 of this Annual Report, the Business Combination was consummated on February 9, 2018, that resulted in our acquisition of interests in Alta Mesa, Alta Mesa GP and KFM through a newly formed subsidiary, SRII Opco. Prior to the Business Combination, Alta Mesa was controlled by High Mesa, Inc. (“HMI”).

Immediately prior to the closing of the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and liabilities to High Mesa Holdings, LP (“High Mesa”), such that Alta Mesa’s only remaining oil and gas assets and liabilities were located in the STACK. As described elsewhere, High Mesa owes us a substantial sum for amounts arising before and after the Business Combination, and it had indemnified us for liabilities arising from non-STACK oil and gas assets. We believe there is substantial doubt about its ability to make payment and honor its indemnification given HMI’s filing for bankruptcy protection in January 2020. Information related to Alta Mesa’s non-STACK oil and gas assets and liabilities that were sold or distributed is disclosed as discontinued operations in Item 8 of this Annual Report.

Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values and pushed those values down to the financial records of our respective subsidiaries. This resulted in our financial presentation being separated into two distinct periods - the period before the Business Combination on February 9, 2018 (“Predecessor”) and the period after the Business Combination (“Successor”).

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Principal Products, Markets and Customers

Our Upstream segment sells our production of oil, natural gas and NGLs to customers generally at prevailing spot prices in effect at the time of the sale. Our Midstream segment derives its revenue from fees assessed for gathering and processing natural gas, gathering and transporting oil, the sale of processed residue gas and NGLs and produced water gathering and disposal services. Natural gas is processed on behalf of the producer and the resulting gas, condensate and NGLs are sold at market prices. We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense. Collateral or other security is generally not required with regard to our trade receivables.

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

For 2019, ARM marketed $123.0 million, or 24.6% of our total operating revenue for the period.

Other than our natural gas marketing agreement with ARM, we had one customer, Phillips 66, that accounted for $202.6 million, or 40.5% of our total operating revenue for 2019.

Seasonality

Weather conditions affect the demand for, and prices of, oil and gas. During the winter, natural gas demand for heating by residential and commercial consumers generally increases whereas high summer temperatures can result in an increase in demand from the power sector. Natural gas in storage typically increases from April through October. Crude oil markets tend to be stronger in the fourth quarter when demand for heating oil is impacted by colder weather and inventory build. Hurricanes and other severe weather (particularly along the Gulf Coast) can also impact supplies by causing disruptions in the level of oil and gas production. Due to these fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Competition

We compete with other companies in all areas of our operations, including, in the past, the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies and independent oil and gas companies. Many of our competitors are large, well-established companies with substantially greater resources and better credit than us and have been engaged in the oil and gas business for a longer period of time than we have. Our filings for bankruptcy protection and restrictions placed on our spending by the Bankruptcy Court have also put us at a competitive disadvantage. This may allow our competitors to have an advantage over us with respect to:

• maintaining production levels on existing oil and gas properties;

• evaluations of properties;

• utilization of midstream assets; and

• absorption of price changes and the costs and implementation of evolving federal, state and local laws and regulations.

In the past, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe, materials (including drilling and completion fluids) and personnel. We are unable to predict when, or if, such future shortages will occur or their impact on our operations.

Regulatory Environment

Our Upstream and Midstream operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental agencies, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Among other things, these laws and regulations may:

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• require various permits before drilling and other regulated activities commence;

• require installation of pollution control equipment and place other conditions on our operations;  

• place restrictions on the use of materials for our operations and upon the disposal of by-products from our operations;  

• restrict the types, quantities and concentrations of various substances that can be released into the environment or used for our operations;  

• limit our operations on lands lying within wilderness, wetlands and other protected areas;

• require remedial measures to mitigate pollution from former and ongoing operations, including site restoration, pit closure and plugging of abandoned wells; and

• impose specific safety and health criteria addressing worker protection.

These laws, rules and regulations often impose difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in remedial or corrective action obligations.

Resource Conservation and Recovery Act

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of non-hazardous and hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. As part of our operations, we generate some amounts of ordinary industrial wastes that may be deemed as hazardous wastes by regulatory authorities. Drilling fluids, produced waters, and most of the other wastes associated with our operations, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that regulations could change and cause wastes now classified as non-hazardous to be classified as hazardous wastes.

Comprehensive Environmental Response, Compensation and Liability Act

The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability on classes of persons considered to be responsible for the release of hazardous substances and other classes of materials. Under CERCLA, such persons may be subject to joint and several, strict liability for costs of investigation and remediation and for damages without regard to fault or legality of the original conduct. These classes of persons, referred to as potentially responsible parties (“PRPs”), include the current and past owners or operators of a site where the hazardous substance release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable statutes.

Federal Water Pollution Control Act

The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

Safe Drinking Water Act

Our underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state and local laws and regulations. The UIC program includes administrative requirements for produced water disposal and prohibits migration of fluid containing any contaminant into underground sources of drinking water. State regulations require permits to operate underground injection wells. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of

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liability by third-parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced waters and other substances, which could affect our business.

Furthermore, in response to recent seismic events near produced water disposal wells, federal and some state agencies are investigating whether such wells have contributed to increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. In response to these concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations.

National Environmental Policy Act

Our operations on federal lands may be subject to the federal National Environmental Policy Act (“NEPA”), which requires federal agencies, including the EPA, to evaluate major agency actions having the potential to significantly impact the environment. As part of such evaluations, an agency will conduct an environmental assessment that assesses the potential impacts of a proposed project and may require the preparation of a detailed environmental impact statement for public review and comment. Our current and future operations on federal lands will be subject to NEPA, which could delay or impose additional conditions and costs on us. Moreover, this process could involve protest, appeal or litigation, any or all of which may impact our operations.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes enacted to protect the health and safety of workers. In addition, comparable state statutes require that we organize and/or disclose information about hazardous materials attendant to our operations to our employees, state and local governmental authorities and citizens.

Our processing plant operations are also subject to standards designed to ensure the safety of our processes, such as the Occupational Safety and Health Administration’s Process Safety Management standard, which is designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The Process Safety Management standard imposes requirements on regulated entities related to managing these hazards. These requirements include conducting process hazard analyses for processes involving highly hazardous chemicals, developing detailed written operating procedures, including procedures for managing change, and evaluating the mechanical integrity of critical equipment. We conduct periodic audits of Process Safety Management systems at each of our locations subject to this standard.

Hydraulic Fracturing

We perform hydraulic fracturing in horizontally drilled wells. Currently, most of our hydraulic fracturing activities are regulated at the state level, given that the EPA only has limited authority to regulate fracturing activities. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the hydraulic fracturing process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater into surface waters; and disposal or storage of fracturing wastewater in unlined pits.

Clean Air Act

Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state laws and regulations that restrict the emission of air pollutants. These laws and regulations may require us to obtain approval for the construction or modification of certain facilities expected to produce or significantly increase air emissions, comply with stringent air permitting requirements and also utilize equipment or technologies to control emissions. Obtaining such permits could delay our operations.

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Climate Change Regulations and Legislation

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at all levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential sources of significant pollutant emissions. Sources subject to these permitting requirements must meet “best available control technology” standards for those GHG emissions. Additionally, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including, among others, onshore and offshore oil and gas production, processing, transmission, storage and distribution facilities, which include certain of our operations.

Federal agencies also directly regulate emissions of methane, a GHG, from oil and gas operations. In August 2016, the EPA issued a final New Source Performance Standards (“NSPS”) rule, known as Subpart OOOOa, which requires certain new, modified or reconstructed facilities in the oil and gas sector to reduce methane gas and volatile organic compound emissions. These Subpart OOOOa standards expanded the previously issued NSPS published by the EPA in 2012, and known as Subpart OOOO, by using certain equipment-specific emissions control practices. However, in August 2019, the EPA proposed two options for further rescinding the Subpart OOOOa standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for volatile organic compounds, and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural gas category the natural gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the Subpart OOOOa standards applicable to all oil and natural gas sources, without removing any sources from that source category (and still requiring control of volatile organic compounds in general). Future implementation of this rule is uncertain at this time.

Other Regulation of the Oil and Gas Industry

Our operations are also subject to various other types of regulation at the federal, state and local level. These types of regulations include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate may also regulate:

• the location of wells;

• the method of drilling and casing wells;

• the timing of conducting our activities, including seasonal wildlife closures;  

• the rates of production;  

• the surface use and restoration of properties where we operate;  

• the plugging and abandoning of wells;

• interactions with surface owners and other third parties; and

• abandonment of pipelines and midstream facilities.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. We rely upon the Oklahoma “forced pooling” process to facilitate working interest owners’ participation in our operations.  Under this process, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may initiate “forced pooling”. Under current regulations, drilling and spacing units for our targeted horizons are based on a maximum of four to eight horizontal wells, depending on the formation, on a 640-acre section. In a forced pooling action, the proposed operator files an application for a pooling order with the Oklahoma Corporation Commission (“OCC”) and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair value of the mineral interests in the unit is determined in an administrative proceeding by reference to market transactions involving nearby oil and gas rights, including nearby mineral lease costs.

Assuming the application for a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair value for their interest, usually in the form of a cash payment, an overriding royalty, or some

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combination, based on the fair value established and approved through the administrative hearing. The pooling order typically addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.

The availability of forced pooling normally means that it is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Oil and gas companies in Oklahoma generally attempt to lease as much of the mineral interests in a particular area as are readily available at acceptable rates, and then use the forced pooling process to proceed with the desired development of the well. In this manner, we have the ability to expand into and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas.

The gross production tax, or severance tax, is a value-based tax levied at a basic rate of 7% upon the production of oil and gas in Oklahoma. As an economic incentive to develop its resources, Oklahoma has historically offered a “tax holiday” with rates ranging from 1% for 48 months to 2% for 36 months for production from horizontal wells. Through June 2018, Oklahoma imposed a tax of 2% of gross production for the first 36 months of production and then at 7% thereafter on wells drilled after July 1, 2015. Effective July 2018, the 2% tax rate was increased to 5% for wells drilled after July 1, 2015 that were still within their first 36 months of production. For the period beyond 36 months, the tax rate remains at 7% for the remaining productive life of each well. All wells drilled after July 1, 2018 are taxed at 5% of gross production for the first 36 months of production and then at 7% thereafter. In addition, a longstanding excise tax of 0.095% continues to be levied.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations covering these procedures. Some state agencies and municipalities have binding requirements related thereto.

Regulation of Natural Gas Sales and Transportation

The rates, terms and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the Federal Energy Regulatory Commission (the “FERC”), as common carriers, under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In March 2016, the PHMSA issued a Notice of Proposed Rulemaking proposing to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines, including both high consequence areas (“HCAs”) and non-HCAs. In October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines, and enhanced emergency order procedures. The gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA is expected to issue the second and third parts of the gas Mega Rule in the near future. The safety and hazardous liquid pipelines rule would extend leak detection requirements to all non-gathering hazardous liquid pipelines and require operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. Finally, the enhanced emergency procedures rule focuses on increased emergency safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety.

Any transportation of our crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA, and the DOT’s Federal Railroad Administration (“FRA”)

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under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids. In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters.

Gathering Pipeline Regulation

Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation by the FERC under the NGA. We believe that our Midstream assets meet the tests the FERC has used to determine exemption from its jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services.

Other

The oil and gas industry is also subject to other federal, state and local regulations and laws relating to resource conservation and employment standards.

Employees

As of December 31, 2019, we had 151 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.

Insurance

We maintain customary insurance against some, but not all, of the operating risks to which our business is exposed such as general liability (includes sudden and accidental pollution), physical damage to our assets, control of wells, auto liability, worker’s compensation and employer’s liability.

We regularly execute master services contracts with our third-party vendors, suppliers and contractors in which they agree to indemnify us for injuries and deaths of their employees and contractors. Similarly, we generally agree to indemnify them against claims made by our other vendors, suppliers, contractors and employees. Additionally, each party is generally responsible for damage to its own property.

Available Information

We disseminate information about the Company through required filings we make with the SEC and, at our discretion, on our website at www.altamesa.net. In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act. Accordingly, we do not anticipate filing any additional current, quarterly or annual reports with the SEC.

Information contained on or connected to our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report or any other filings we make with the SEC. The SEC maintains a site that contains reports, proxy and information statements and other information regarding reporting issuers. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K are filed electronically and are available free of charge at http://www.sec.gov. Additionally, the Company will provide electronic or paper copies free of charge upon request to our Secretary at 15021 Katy Freeway, Suite 400, Houston, Texas 77094 or by calling (281) 530-0991.

Item 1A.  Risk Factors

Not required.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Upstream Segment

Overview

As of December 31, 2019, we held a highly contiguous position of approximately 127,100 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. This position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet.

At December 31, 2019, we had an average 66% net working interest in 814 gross producing wells.

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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 expected well level production. 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 and began operating 2 rigs, however following our filing for bankruptcy protection in September 2019, we discontinued further development activities.

Bayou City Joint Development Agreement

In January 2016, we entered into a joint development agreement (as subsequently amended, the “JDA”) with BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City Management, LLC, to fund a portion of our drilling operations with the intent to accelerate our development. The JDA established a development plan of 60 wells in three tranches, and provided opportunities for the parties to potentially agree to an additional 20 wells. As of December 31, 2019, 61 joint wells had been drilled or spudded.

Under the JDA, up to 100% of our well costs could be funded up to a specified total well cost. In exchange for BCE carrying the drilling and completion costs, they received 80% of our working interest in each funded well until attaining a 15% internal rate of return for the entire tranche, at which time their interest reduces to 20%. If a tranche attains a 25% internal rate of return, their interest reduces to 12.5%.

During the 2018 Successor Period, we brought 25 horizontal wells on production that were funded through the JDA. At December 31, 2019, there were no JDA wells in progress, and none have been developed in 2020. 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. The JDA expired in January 2020 pursuant to its terms.

Our Oil and Gas Reserves

Our proved reserves and production profile as of December 31, 2019 was as follows:

Total Estimated Proved Reserves (MMBoe)	Percent Proved Developed	PV-10 ($ in millions)(1)	Standardized Measure ($ in millions)(1)	Net Producing Wells(2)	Average 2019 Daily Net Production (MBoe/d)
46.5	100%	$346.3	$326.9	535	35.0

_________________

(1) PV-10 is a non-GAAP measure of the estimated future net cash flows from proved reserves before giving effect to income taxes, discounted at an annual rate of 10 percent. The calculation of PV-10 also does not give effect to potential derivatives or hedging transactions. Standardized measure is the after-tax estimated future net cash flows from proved reserves discounted at an annual rate of 10 percent and may (depending upon a registrant’s derivative and hedging policy) include the effects of hedges, all determined in accordance with GAAP.  We believe PV-10 is a useful measure of the value of our proved reserves because it allows users of our financial statements to compare relative values and sizes of proved reserves among exploration and production companies without regard to their corporate structure and the resulting income tax burden.  The difference between PV-10 and standardized measure is the discounted effect of income taxes, totaling $19.4 million, on our share of expected future net cash flows, without taking into consideration the utilization of net operating loss carryforwards.

(2) Calculated as gross wells multiplied by our working interest percentage for each well.

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Key information and assumptions used in determining our estimated net proved reserves at the end of each period is set forth in Item 8. All of our reserves are located in the United States.

Oil and NGLS (Mbbls)
	Successor				Predecessor
	December 31, 2019		December 31, 2018		February 8, 2018
Proved Reserves (1)
Developed	27,431		45,064		30,693
Undeveloped	—		—		77,256
Total	27,431		45,064		107,949
Average market prices (per bbl) - oil(2)	$	55.69	$	65.56	$	52.89
Average realized prices (per bbl) - NGLs(2)	$	14.60	$	22.44	$	27.48

Natural Gas (MMcf)
	Successor				Predecessor
	December 31, 2019		December 31, 2018		February 8, 2018
Proved Reserves (1)
Developed	114,443		144,148		126,231
Undeveloped	—		—		284,571
Total	114,443		144,148		410,802
Average market prices (per MMBtu) - natural gas(2)	$	2.58	$	3.10	$	2.99

Total (MBoe)
	Successor		Predecessor
	December 31, 2019	December 31, 2018	February 8, 2018
Proved Reserves (1)
Developed	46,505	69,089	51,731
Undeveloped	—	—	124,685
Total	46,505	69,089	176,416

_________________

(1) Proved reserves were calculated using oil and gas parameters established by current SEC guidelines and accounting rules. Reserve estimates are based on various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Actual future production, oil and gas prices, revenue, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary from these estimates. In addition, we may adjust our estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

(2) Average market prices represent an unweighted arithmetic average of the market price on the first day of each month during the last 12 months.

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Proved Undeveloped Reserves

Based on Alta Mesa’s bankruptcy filing and/or our inability to fund development costs, we did not recognize any PUDs as of December 31, 2019 and 2018. The information presented during the 2018 Predecessor Period includes amounts related to discontinued operations. Changes in our proved undeveloped reserves during the 2018 Successor Period and the 2018 Predecessor Period were (in MBoe):

	Successor				Predecessor
	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Beginning of period	—		124,685		125,101
Converted into proved developed reserves	—		(18,999	)	—
Extensions and discoveries	—		43,354		—
Reserves acquired	—		3,738		—
Reserves sold/distributed(1)	—		—		(1,129	)
Revisions(2)	—		(152,778	)	713
End of period	—		—		124,685
Percentage of total proved reserves	—	%	—	%	71	%

_________________

(1) Reserves sold/distributed during the period January 1, 2018 to February 8, 2018, represent amounts related to our non-STACK properties that are classified as discontinued operations in our financial statements.

(2) Effective as of December 31, 2018, due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves, we removed all of our PUDs from our total estimated proved reserves.

During 2019, we did not incur any expenses to develop PUD reserves, compared to approximately $160.6 million incurred during the 2018 Successor Period. PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the original date of their recognition. As a result of Alta Mesa’s bankruptcy filing and the expected Sale Transactions, we do not expect to incur any further development of our properties. Thus, we have concluded that we do not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our available drilling locations.

Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

Our policies and practices regarding internal controls over reserve recognition are structured to objectively and accurately estimate our oil and gas reserves quantities and their present value in compliance with SEC standards.  The reserve estimation process begins with our Corporate Reserves department, which gathers and analyzes much of the data used as inputs to estimating reserves. Working and net revenue interests are sourced from our division order system in our land department.  Lease operating expenses are provided by our accounting department and our operations team provides capital expenses.  Our Vice President of Planning and Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:

• Over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves; and

• Bachelor of Science Degree in Petroleum Engineering from the University of Texas in 1980, Master of Business Administration from Oklahoma City University in 1988.

Our methodologies include reviews of production trends, material balance calculations, analogy to comparable properties, and volumetric analysis, with performance methods preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on analogy to offset production in the same area.

We maintain internal controls that we believe result in the proper amount and value of our reported reserves. These controls, which we determined to be effective for all periods presented, include:

• we follow comprehensive SEC-compliant internal policies to determine and report proved reserves;

• reserve estimates are made by experienced reservoir engineers or under their direct supervision; and

• annually, our Chief Operating Officer and Chief Executive Officer review all significant reserves changes and new proved undeveloped reserves additions.

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Ryder Scott Company, LP (“Ryder Scott”), a third-party petroleum engineering consulting firm, audited approximately 97% of our 2019 proved reserves on a 6:1 Mcf per Bbl conversion basis. Their report is filed with this Annual Report as Exhibit 99.1. The reserve audit by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202. The qualifications of the technical person at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.

Miles R. Palke with Ryder Scott earned a B.S. in Petroleum Engineering from Texas A&M University in College Station, Texas and a Master of Science in Petroleum Engineering from Stanford University in Palo Alto California.  Mr. Palke graduated Magna Cum Laude and with University Honors from Texas A&M University and is a registered Professional Engineer in the State of Texas.  Based on his educational background, professional training and more than 23 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Palke has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.

A reserves audit and a financial audit are separate activities with unique and different processes and results. A reserves audit under SEC standards is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities.

Oil and Gas Production, Production Prices and Production Costs

Information relating to our oil and gas production, sales prices for our products produced and production costs is included in Item 7.

Drilling and Other Exploratory and Development Activities

	Successor		Predecessor
	Year Ended December 31, 2019	February 9, 2018 Through December 31, 2018	January 1, 2018 Through February 8, 2018
Development wells drilled (net):
Productive	48.8	123.8	7.0
Dry	—	—	—
Total development wells	48.8	123.8	7.0
Exploratory wells drilled (net):
Productive	—	—	—
Dry	—	1.0	—
Total exploratory wells	—	1.0	—

Activities at Year End

At December 31, 2019, we had no wells that were in progress for drilling or completion operations.

Delivery Commitments

Information about our firm transportation commitments is included in Part II, Item 8.

Productive Wells, Developed and Undeveloped Acreage

The following sets forth information with respect to our wells and acreage under lease as of December 31, 2019, all of which is located in the United States:

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	December 31, 2019
	Gross	Net
Number of producing wells principally targeting (1):
Oil	792	521.8
Gas	22	13.2
Total wells	814	535
Properties:
Developed acres	176,455	110,412
Undeveloped acres	39,085	16,647
Total acres	215,540	127,059
Undeveloped acreage expirations (2):
Year ending December 31, 2020	11,301	4,504
Year ending December 31, 2021	17,428	5,969
Total	28,729	10,473

_________________

(1) A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractional working interests we own in gross wells, including joint development wells.

(2) Our lease acreage is typically subject to expirations if a well is not drilled and producing before the end of the primary term. The primary term of our leasehold ranges from 3 to 5 years. As is customary in our industry, our undeveloped leasehold may be maintained through: (i) commencing operations for drilling, completion and production, (ii) pooling, (iii) extensions or renewals and (iv) other operational extensions, including shut-in payments and continuous operations.

Title to Properties

We typically conduct a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, at the time we acquire properties. We believe that title to our interests is satisfactory and consistent with the standards in our industry.

Midstream Segment

Our KFM assets include a gas and oil gathering network, a cryogenic gas processing plant with off-take capacity, field compression facilities and a produced water disposal system. These assets are located in the Anadarko Basin in Oklahoma.

KFM expanded its gas gathering system northward into Major County, Oklahoma, with a high-pressure line to connect the existing system in Kingfisher County, Oklahoma to new low-pressure gathering pipelines in southeastern Major County.

Prior to November 2019, KFM held a 50% equity interest in a partnership to develop a long-haul crude oil pipeline project, the Cimarron Express Pipeline (“Cimarron”), that was designed to link the existing crude oil storage tank located at the KFM Lincoln Terminal to a crude oil terminal site at Cushing, Oklahoma.  Based on lower oil prices, less development wells and lower expected volumes from new wells, we determined in the fourth quarter of 2018 that the project was not likely to be completed and recognized an impairment to reduce our investment to its estimated fair value at December 31, 2018. In November 2019, Cimarron redeemed its 50% membership interest from the third party for one-half of the remaining cash in Cimarron plus an immaterial amount of other equipment. Following this transaction, Cimarron became our wholly owned subsidiary.

In November 2018, Alta Mesa sold substantially all of its produced water assets to a subsidiary of KFM, consisting of over 200 miles of produced pipelines, and related facilities and equipment, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations.

Item 3. Legal Proceedings

We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business, the outcomes of which 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,

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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. The commencement of the Chapter 11 proceedings automatically stayed most of these actions against the Company.

Bankruptcy

On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).

On January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.

Adversary Proceeding

On September 12, 2019, an adversary proceeding was commenced by certain of the AMH Debtors against KFM, Oklahoma Produced Water Solutions, LLC, SRII Opco, HMI, Michael E. Ellis, and Harlan H. Chappelle (together, the “Defendants”), alleging, among other things, that (i) the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions and KFM and its subsidiaries could be rejected, (ii) certain amendments to the crude oil and gas gathering agreements were constructive and actual fraudulent transfers, (iii) the Defendants breached their respective fiduciary duties owed to the AMH Debtors by entering related-party crude oil and gas gathering agreements, which as a result are subject to rescission, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement is therefore terminated. Pursuant to the adversary proceeding complaint, AMH is seeking declaratory judgements that the gathering agreements cannot continue to burden AMH or its estates and could therefore be rejected or avoided under the Bankruptcy Code. On October 25, 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFM and Oklahoma Produced Water Solutions, LLC as Defendants.

On December 6, 2019, the Bankruptcy Court held that the dedication provisions of the crude oil, gas and water gathering agreements “ran with the land” and therefore could not be rejected under the Bankruptcy Code, granting summary judgment in favor of the defendants on that count of the complaint.  All other counts were reserved for trial, which commenced on December 9, 2019, but was subsequently stayed by the Bankruptcy Court at the request of the parties.  The litigation remains stayed as of the date hereof.

Litigation

On January 30, 2019, the Company, James T. Hackett, our then interim Chief Executive Officer and Chairman of the Board, certain of our former and current directors, Thomas J. Walker, our former Chief Financial Officer, and Riverstone Investment Group LLC were named as defendants in a putative securities class action filed in the United States District Court for the Southern District of New York (“SDNY Complaint”). The plaintiff, Plumbers and Pipefitters National Pension Fund, alleges that the defendants disseminated a false and misleading proxy statement in connection with the Business Combination and, therefore, violated Section 14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 14-9 promulgated thereunder. In addition, the plaintiff alleges that Riverstone and the individual defendants violated Section 20(a) of the Exchange Act. The plaintiff is seeking compensatory and/or rescissory damages against the defendants. The District Court transferred this action to the U.S. District Court for the Southern District of Texas.

On March 14 and 19, 2019, two additional putative securities class action complaints were filed in the U.S. District Court for the Southern District of Texas (“SDTX Complaints”) against the same defendants named in the SDNY Complaint, and Harlan H. Chappelle, our former President and Chief Executive Officer, and Michael A. McCabe, our former Chief Financial Officer. These complaints include the same claims asserted in the initial complaint, but also add claims under Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder against us and certain of our current and former officers and directors on behalf of all persons or entities who purchased or otherwise acquired Silver Run or AMR securities between March 24, 2017,

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and February 25, 2019. The new claims are based upon alleged misstatements contained in our proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants.

On December 19, 2019, the U.S. District Court for the Southern District of Texas consolidated the three putative securities class action lawsuits into a single action. On January 16, 2020, the Court entered a stipulated order appointing Plumbers and Pipefitters National Pension Fund and the First New York Group (consisting of FNY Partners Fund LP, FNY Managed Accounts LLC, and Paul J. Burbach) as co-lead plaintiffs and appointing Camelot Event Driven Fund as an additional consolidated class representative. The amended Consolidated Putative Securities Class Action complaint is due March 16, 2020. The commencement of the Chapter 11 proceedings automatically stayed these actions against the Company.

The outcome of the above consolidated class actions is uncertain, and while we believe that we have valid defenses to the plaintiff’s claims and intend to defend the lawsuits vigorously, no assurance can be given as to the outcome of the lawsuits.

On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to KFM in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants.  We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves. The Mustang litigation was automatically stayed on the commencement of the Chapter 11 proceedings.

Mustang filed an adversary proceeding (Mustang Gas Products LLC v. Oklahoma Energy Acquisitions, LP et al., Adversary Proceeding No. 20-03015 (Bankr. S.D. Tex.)) against Oklahoma Energy Acquisitions, LP (“OEA”) and other defendants on January 20, 2020, alleging that gas dedication covenants running with the land have a value of not less than $37 million, and entitle Mustang to a corresponding portion of the proceeds of the forthcoming sale of all or substantially all of OEA’s assets. OEA denies these allegations and intends to defend the case vigorously. OEA’s time to respond to Mustang’s complaint has been extended until 15 days after the bankruptcy court enters an order on the pending motion to dismiss filed by the Administrative Agent to the Alta Mesa RBL. It is not possible at this stage of the case to estimate the likelihood of an unfavorable outcome or the range of damages that may be awarded.

In August 2017, Biloxi Marsh Lands (“Biloxi”) filed suit in the 34th District Court for the Parish of St. Bernard, Louisiana, against Meridian Resource & Exploration LLC (“Meridian”, a subsidiary of HMI), Alta Mesa, and other defendants.  Biloxi alleges negligent construction, installation, maintenance, use and operation of a pipeline. In lieu of litigating corporate structure allegations and to reduce potential litigation expenses, Alta Mesa stipulated with respect to Biloxi that it would be bound by and assume liability and responsibility for any unpaid debts, obligations or final judgments that may be entered against Meridian in favor of Biloxi in this matter. However, these allegations relate to non-STACK oil and gas assets that Alta Mesa distributed to a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Consequently, we believe that any potential damages incurred by Alta Mesa or Meridian as a result of these allegations are the responsibility of HMI. There is no guarantee that HMI will pay any settlement amounts or judgments rendered against Alta Mesa or Meridian. In addition, Alta Mesa’s ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI, which recently filed for relief under Chapter 7 of the Bankruptcy Code in the Bankruptcy Court. The commencement of the Chapter 11 proceedings automatically stayed these against the Company. 

SEC Investigation

The SEC is conducting a formal investigation into, among other things, the facts involved in the fair value measurements used in accounting for the Business Combination and the impairment charge recognized during 2018. We are cooperating with this investigation. At this point we are unable to predict the timing or outcome of this investigation. If the SEC determines that violations of the federal securities laws have occurred, the agency has a broad range of civil penalties and other remedies available, some of which, if imposed on us, could be material to our business, financial condition or results of operations.

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Environmental Claims

Various landowners have sued Alta Mesa in lawsuits concerning several fields in which Alta Mesa’s subsidiaries have, or historically had, operations.  The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from its oil and gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims as of December 31, 2019.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

(a)  Market Information

Our Class A Common Stock and Public Warrants are currently listed on the OTC Pink Marketplace under the symbols “AMRQQ” and “AMRWQ,” respectively. Over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

Our Class C Common Stock does not trade on any market however, holders of our Class C Common Stock hold an equal number of SRII Opco Common Units that were issued upon the closing of the Business Combination. Holders of Class C Common Stock have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for an equal number of shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. Upon such an exchange, a corresponding number of shares of Class C Common Stock would be canceled.

In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act. Further, as part of the AMR Liquidation Plan, we expect all outstanding shares of Class A Common Stock and Class C Common Stock will be cancelled.

(b)  Holders

As of January 31, 2020, there were 39 holders of record of our Class A Common Stock, 9 holders of record of our Class C Common Stock and 6 holders of record of our Public Warrants. The number of record holders of our Class A Common Stock and Public Warrants does not include DTC participants or beneficial owners holding shares of Public Warrants through nominee names.

(c)  Dividends

We have not paid any cash dividends on our Class A Common Stock to date. The payment of any cash dividends on our Class A Common Stock is within the discretion of our Board of Directors (the “Board”) but, our ability to declare dividends is generally prohibited by our debt agreements and our bankruptcy filing. Holders of our Class C Common Stock are not entitled to dividends at any time.

(d)  Securities Authorized for Issuance Under Equity Compensation Plans

Shares of Class A Common Stock that were issuable under our existing equity compensation plans as of December 31, 2019:

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Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders(1)				40,016,725
Stock options	3,803,287	$	8.79
PSUs(2)	2,841,434	N/A
Total	6,644,721			40,016,725

_________________

(1) There were no equity compensation plans not approved by security holders.

(2) Assumes maximum achievement of performance targets at 200% for the 2019 and 2020 performance periods. Performance-based restricted stock units have no exercise price. In February 2020, we settled the 2019 tranche of the PSUs with an immaterial cash payment.

On February 11, 2020, we filed a post-effective amendment to our registration statement on Form S-8 (Registration No. 333-224248) to deregister unissued and unsold shares of Class A Common Stock issuable to participants under the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan.

(e)  Performance Graph

Not required.

(f) Recent Sales of Unregistered Securities

None.

(g)  Purchases of Equity Securities by the Issuer and Affiliated Purchasers

In August 2018, our Board authorized the repurchase of up to $50.0 million of the Company’s outstanding Class A Common Stock, exclusive of any fees, commissions or other expenses related to such repurchases. Prior to our bankruptcy filing, repurchases could have been made at the Company’s discretion in accordance with applicable securities laws from time to time in open market or private transactions. All shares repurchased were retired. The authorization has no expiration date.

There were no repurchases and retirements during the quarter ended December 31, 2019 and no additional repurchases are anticipated.

Item 6.  Selected Financial Data

Not required.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Annual Report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the Buyer’s ability and willingness to close the Sale Transactions, the volatility of oil and gas prices, production timing and volumes, our ability to continue as a going concern, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

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Overview

Alta Mesa Resources, Inc. (“AMR”), together with its consolidated subsidiaries (“we”, “us”, “our” or “the Company”), is an independent exploration and production company focused on the development of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generates revenue primarily through long-term, fee-based contracts.

On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).

On January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.

The Initial and Additional Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

On December 31, 2019, the Initial Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “AMH PSA”) with BCE-Mach III LLC (the “Buyer”) pursuant to which the AMH Debtors agreed to sell to the Buyer substantially all of our upstream assets for an unadjusted purchase price of $232.0 million in cash, subject to customary purchase price adjustments (such transaction, the “AMH Sale Transaction”). On December 31, 2019, the KFM Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “KFM PSA” and, together with the AMH PSA, the “PSAs”) with the Buyer pursuant to which the KFM Debtors agreed to sell to the Buyer substantially all of our midstream assets for an unadjusted purchase price of $88.0 million in cash, subject to customary purchase price adjustments (such transaction, the “KFM Sale Transaction” and, together with the AMH Sale Transaction, the “Sale Transactions”).

The Sale Transactions are expected to close no later than mid-April 2020, after which we will no longer own any operating assets. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

In March 2020, AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the “AMR Plan”). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH’s creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A common stock and class C common stock in the Company are expected to be canceled.

The AMR Plan will be subject to approval by the Bankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent that the AMR Plan is confirmed by the Bankruptcy Court, AMR expects the AMR Plan to become effective and be consummated shortly thereafter.

In March 2020, the KFM Debtors filed a Chapter 11 plan (the “KFM Plan”). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors’ estates. Under the KFM Plan, the KFM Debtors will appoint a plan administr

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ator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation.

The KFM Plan is subject to approval by the Bankruptcy Court and the KFM Debtors are expected to solicit votes on the KFM Plan from certain of the KFM Debtors’ creditors pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the KFM Plan in April 2020. To the extent that the KFM Plan is confirmed by the Bankruptcy Court, KFM expects the KFM Plan to become effective and be consummated shortly thereafter.

Additional information relating to the formation of the Company and the acquisition of Alta Mesa and KFM on February 9, 2018, may be found in Item 8. Immediately prior to the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa. We have reported these distributed assets as discontinued operations for all periods presented.

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

Accordingly, for purposes of explaining our segment results, we have presented the 2019 results with the 2018 Successor Period and the 2018 Predecessor Period results of Alta Mesa, our Upstream segment. As KFM, our Midstream segment, was acquired on February 9, 2018, our discussion of our Midstream segment results covers the 2019 results and the 2018 Successor Period results.

Outlook, Market Conditions and Commodity Prices

Our revenue and profitability depend on many factors, particularly the prices of oil, gas and NGLs, which are beyond our control.  Our business has been 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 at depressed levels compared to past years, which have had a negative impact on the value of our oil and gas properties and our midstream assets, and the future outlook for prices continues to be unpredictable. 

Ability to Continue as a Going Concern

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.

We expect to sell substantially all of our assets no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.

Delisting from Stock Exchange

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As a result of our failure to comply with the continued listing requirements of the NASDAQ, trading in our Class A Common Stock and public warrants was suspended in September 2019, and they are now traded over the counter under the trading symbols “AMRQQ” and “AMRWQ”, respectively. In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.

Derivatives

We previously operated a hedging program in accordance with requirements under the Alta Mesa RBL. Settlements and fair value changes in our derivatives had significant impacts on our results of operations. Our derivatives were reported at fair value and were sensitive to changes in the price of oil and gas. Changes in derivatives were 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.

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

For 2019, we recognized a net loss on our derivatives of $11.7 million, which includes $7.6 million in cash settlements received for derivatives.

Impairments

2019

As noted above, the Initial Debtors filed for bankruptcy protection in September 2019 and the Additional Debtors filed for bankruptcy protection in January 2020. As a result of our bankruptcy filings and previous restrictions by our lenders on our ability to access additional capital, our ability to incur the levels of spending necessary to continue to develop our upstream properties and expand our midstream operations were significantly restricted. This negatively impacted our future drilling plans and our expectations regarding production levels, which contributed to lower throughput expectations for our midstream processing assets. In addition, the Sale Transactions reflect prices of $232.0 million for substantially all of the upstream properties and assets and $88.0 million for our midstream assets. As these prices were below the carrying value of the respective assets, we adjusted our carrying values down to the expected sales prices, after estimated direct sales costs, as we believe the Buyer has the intent and ability to close the Sale Transactions.

Additionally, as a result of the expected sales of our assets described above and our expectations of contracts that will be rejected in bankruptcy, we also recognized impairments of our operating lease right-of-use assets and a long-term prepaid asset due to our inability to recover the carrying value of these assets.

2018

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.  Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place based on our 2018 drilling results.

In May 2018, a subsidiary of KFM entered into agreements with a third party to jointly construct and operate a new crude oil pipeline via creation of Cimarron that we accounted for under the equity method. Cimarron’s proposed pipeline was to extend from our processing plant to Cushing, Oklahoma and was to be constructed and operated by Cimarron, which we determined was controlled by the third-party.

As the late-2018 outlook for Alta Mesa volumes and third-party volume opportunities in the area were significantly lower than initially projected, we suspended future contributions to Cimarron and elected to abandon the project. We conducted an impairment analysis resulting in the recognition of an impairment charge of $16.0 million during the 2018 Successor Period to reduce the carrying value of our investment in Cimarron to its estimated fair value at December 31, 2018.

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Based on an estimation of the fair value of KFM utilizing an income approach that took into consideration the late 2018-outlook for Alta Mesa and third-party volumes available for processing, we determined that a portion of the value of KFM’s plant and equipment and all of KFM’s intangible assets and goodwill were impaired at December 31, 2018.

The summary of impairment expense follows (there was no impairment expense during the 2018 Predecessor Period):  

(in millions)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Impairment attributable to:
Upstream
Unproved properties	$	31.0	$	742.1
Proved properties	484.8		1,291.6
Operating lease right-of-use assets	13.3		—
Other long-term assets	27.3		—
Total Upstream	556.4		2,033.7
Midstream
Investment in Cimarron	—		16.0
Property and equipment	348.6		68.4
Operating lease right-of-use assets	0.3		—
Intangible assets	—		395.0
Goodwill	—		692.0
Total Midstream	348.9		1,171.4
Total impairment of assets	$	905.3	$	3,205.1

Results of Operations

Business Segments

Our discussion of results of operations is presented on a segment basis.  Our two reportable segments are (1) Upstream and (2) Midstream, which separately feature distinct revenue producing activities.  We evaluate Upstream and Midstream segment performance using Adjusted EBITDAX and Adjusted EBITDA, respectively.

The Company’s management believes Adjusted EBITDAX and Adjusted EBITDA are useful because they allow users to more effectively evaluate our operating performance, compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure and because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDAX and Adjusted EBITDA should not be considered as an alternative to our segments’ 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.  The Company’s applicable corporate activities have also been allocated to the supported business segments.

For the year ended December 31, 2019 compared to the periods from February 9, 2018 through December 31, 2018 (2018 Successor Period) and January 1, 2018 through February 8, 2018 (Predecessor Period)

The tables included below set forth financial information for the year ended December 31, 2019. The 2018 Successor Period and the Predecessor Period are distinct reporting periods as a result of the Business Combination. The Predecessor Period amounts below exclude operating results related to discontinued operations. We refer to the combined 2018 Successor Period from February 9, 2018 through December 31, 2018 and the Predecessor Period from January 1, 2018 through February 8, 2018 as the “2018 Period”.

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Upstream Segment Results of Operations

Our Upstream segment was impacted by the Business Combination, which caused our 2018 results to be separately presented between Successor and Predecessor Periods. In preparing the following discussion, we have provided a combined total to arrive at a full year 2018 amount and context for the change of such full year amount to the 2019 comparable amount. We view 2018 as a single reporting period since the impact of the Business Combination was limited to the items described below. We believe that this approach:

• allows readers of our financial statements to see how management has evaluated the operating results; and

• provides readers of our financial statements with adequate context for their analysis of our operating results.

The impact to our Upstream results following the Business Combination primarily relates to increased depletion expense associated with a step-up for proved oil and gas properties and to impairment expense which is associated with the step-up for both unproved and proved oil and gas properties. We do not believe that the presentation of full pro forma segment results is more preferable than the information that follows.

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:

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	Successor				Predecessor
(in thousands, except per unit data)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Net production:
Oil (Mbbl)	5,885		5,053		494
Natural gas (MMcf)	24,802		16,913		1,609
NGLs (Mbbl)	2,760		2,268		151
Total (MBoe)	12,779		10,140		914
Average net daily production volume:
Oil (Mbbld)	16.1		15.4		12.7
Natural gas (MMcfd)	67.9		51.9		41.2
NGLs (Mbbld)	7.6		7.0		3.9
Total (MBoed)	35.0		31.1		23.4
Average sales prices before hedging:
Oil (per bbl)	$	55.79	$	63.99	$	62.68
Natural gas (per Mcf)	$	2.16	$	2.57	$	2.66
NGLs (per bbl)	$	14.50	$	18.98	$	26.41
Revenue
Oil sales	$	328,386	$	323,299	$	30,972
Natural gas sales	53,693		43,407		4,276
NGL sales	40,026		43,039		4,000
Total Upstream sales revenue	$	422,105	$	409,745	$	39,248
Gain on sale of assets	$	1,488	$	4,751	$	840

Oil revenue for 2019 decreased compared to the 2018 Period due to a decrease in average market prices in 2019, which was partially offset by an increase in production. The increase in production in 2019 was due to an increase in the number of wells drilled and new wells on production as a consequence of the significant 2018 capital expenditure program.

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NGL revenue for 2019 decreased compared to the 2018 Period due to a decrease in average market prices in 2019, which was partially offset by an increase in production. The pricing reduction primarily relates to our election of the treatment of ethane volumes in our contract with KFM. Under our gathering contract with KFM, we have an ability to determine ethane recovery volumes as either a fixed recovery or at the actual levels that the plant can recover. In 2019, we elected to recover ethane volumes at a fixed rate until August, which had the impact of increasing the NGLs volume but decreasing the price received per barrel as the total sales value remained unchanged. Beginning in August 2019, we elected to recover actual ethane volumes. The increase in production volume was primarily due to our 2018 development activities.

Gain on sale of assets primarily includes gains from the sale of seismic data in 2019 and the 2018 Period.

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives:
Realized gains (losses) -
Oil	$	6,858		$	(36,505	)	$	(3,819	)
Natural gas	784			(2,456		)	1,523
Total realized gains (losses)	7,642			(38,961		)	(2,296		)
Unrealized gains (losses)	(19,386		)	28,714			8,959
Total gain (loss) on derivatives	$	(11,744	)	$	(10,247	)	$	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 twelve month period.

In connection with Alta Mesa’s bankruptcy filing, we cancelled (prior to contract settlement date) all open derivative contracts in September 2019 for net proceeds of approximately $4.0 million.

Operating Expenses

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	Successor				Predecessor
(in thousands, except per unit data)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Operating expenses:
Lease operating	$	79,884	$	60,547	$	4,408
Transportation and marketing	70,324		50,038		3,725
Production taxes	19,455		16,865		953
Workovers	2,652		5,563		423
Exploration	52,354		34,085		7,003
Depreciation, depletion and amortization	120,617		133,554		11,670
Impairment of assets	556,427		2,033,712		—
General and administrative	59,897		114,735		21,234
Total Upstream operating expense	$	961,610	$	2,449,099	$	49,416
Select operating expenses per BOE:
Lease operating	$	6.25	$	5.97	$	4.82
Transportation and marketing	5.50		4.93		4.08
Production taxes	1.52		1.66		1.04
Workovers	0.21		0.55		0.46
Depreciation, depletion and amortization	9.44		13.17		12.77

Lease operating expense for 2019 increased primarily due to an increase in net production coupled with the impact of additional costs for produced water disposal after our asset sale to KFM in the fourth quarter of 2018 and a non-cash charge to reduce the carrying value of certain supplies to realizable value.

Transportation and marketing expense for 2019 increased primarily due to increase in net production. 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 increase is also due to an increase in committed capacity which went unused during 2019.

Production taxes for 2019 increased primarily due to an increase in production volumes 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 for 2019 decreased primarily due to less workover projects undertaken due to our efforts to reduce costs. Workovers are associated with maintenance and other efforts to increase production.

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Exploration expense:
Geological and geophysical costs	$	1,246	$	6,755	$	2,440
Exploratory dry hole expense	23		1,954		—
Other exploration expense, including expired leases	51,010		24,374		4,504
ARO settlements in excess of recorded liabilities	75		1,002		59
Total exploration expense	$	52,354	$	34,085	$	7,003

Exploration expense for 2019 increased primarily due to an increase in expired and expiring leases, primarily for those in Major and Kingfisher counties in Oklahoma. Geological and geophysical costs decreased as a result of headcount reductions.

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Depreciation, depletion and amortization expense for 2019 decreased as a result of a significantly lower depletable base due to impairments recorded during 2018 and 2019.

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Impairment of assets:
Impairment of unproved properties	$	31,023	$	742,065	$	—
Impairment of proved properties	484,830		1,291,647		—
Impairment of operating lease right-of-use assets	13,245		—		—
Impairment of other long-term assets	27,329		—		—
Total impairment of assets	$	556,427	$	2,033,712	$	—

Impairment of assets for 2019 consisted of impairment of our proved and unproved properties, operating lease right-of-use assets and a long-term prepaid asset. Our oil and gas properties were impaired during the third quarter of 2019 based on our impairment analysis resulting from our bankruptcy filing and further impaired during the fourth quarter of 2019 after taking into consideration the expected purchase price of the AMH Sale Transaction, net of estimated direct costs, for substantially all of our upstream assets. Operating lease right-of-use assets were impaired during the second quarter 2019 based on our inability to fully recover cash outflows due to lessors for certain unused office space. A further impairment of the remaining value of our operating lease right-of-use assets, as well as significant portion of a long-term prepaid asset, was taken as of December 31, 2019, due to the expected sale of substantially all of our assets and the expected rejection of certain leases and contracts that indicated we would not be able to fully recover the carrying value of those assets. We believe the Buyer has the intent and ability to close the Sale Transactions.

For the 2018 Period, impairment largely related to a decrease in commodity prices, as well as the results of exploratory and development drilling and well performance, which reduced the value of our assets. A significant decline in spot and future estimated commodity prices late in the fourth quarter of 2018, and the impact of changes in our individual well reserve recovery estimates triggered a downward revision in the future cash flows expected to be generated by our oil and gas properties, which required us to reduce the carrying value of those properties to estimated fair value.

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
General and administrative expense:
Employee-related costs	$	22,018	$	18,203	$	1,032
Equity-based compensation	5,718		20,000		—
Professional fees	8,289		12,981		1,019
Strategic costs	8,116		—		—
Business Combination	—		23,717		17,040
Severance costs	4,865		8,357		—
Information technology	4,002		4,654		—
Operating leases	4,193		3,267		208
Provision for uncollectible receivables	1,218		22,438		—
Other	1,478		1,118		1,935
Total general and administrative expense	$	59,897	$	114,735	$	21,234

General and administrative expense for 2019 decreased compared to the 2018 Period primarily due to (i) nonrecurring expenses in the 2018 Period related to the Business Combination and professional fees for various advisors, (ii) a $22.4 million provision for certain related party receivables (including notes receivable) we assessed as uncollectible, and (iii) higher equity-based compensation expense and severance costs associated with the departure of certain members of executive management in late 2018. General and administrative expense during 2019 also included costs for legal and strategic financial advisory services associated with financial restructuring activities, including negotiations with representatives of our lenders and other third

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parties, as well as severance costs associated with a reduction in force in early 2019. All professional fees incurred from the filing of the Initial Bankruptcy Petitions forward, and directly related to the bankruptcy, are reported in Reorganization items, net.

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

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Loss from continuing operations before income taxes	$	(597,510	)	$	(2,076,370	)	$	(7,116	)
Interest expense	49,823			38,265			5,511
Depreciation, depletion and amortization	120,617			133,554			11,670
Exploration	52,354			34,085			7,003
Loss (gain) on unrealized hedges	19,386			(28,714		)	(8,959		)
Loss (gain) on sale of property and equipment	—			388			—
Impairment of assets	556,427			2,033,712			—
Equity-based compensation	5,718			20,000			—
Provision for uncollectible related party receivables(1)	886			22,438			—
Severance costs	4,865			—			—
Strategic costs	8,116			—			—
Business combination	—			23,717			17,040
Non-cash lease operating expense	3,835			—			—
Reorganization items, net	(449		)	—			—
Upstream Adjusted EBITDAX	$	224,068		$	201,075		$	25,149

_________________

(1) Represents a provision for the estimated uncollectibility of certain related party receivables (including notes receivable).

Other (Income) Expense

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Alta Mesa RBL	$	24,541		$	2,807		$	815
2024 Notes	27,453			35,273			3,281
Bond premium amortization	(3,432		)	(4,512		)	—
Deferred financing cost amortization	195			221			171
Other	1,066			4,476			1,244
Total interest expense	49,823			38,265			5,511
Interest income	(154		)	(1,983		)	(172		)
Reorganization items, net	(449		)	—			—
Total other (income) expense, net	$	49,220		$	36,282		$	5,339

Interest expense for 2019 increased due to higher average debt balances outstanding under the Alta Mesa RBL coupled with higher default and borrowing base deficiency interest rates beginning in September 2019. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.

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Reorganization items, net

(in thousands)	Year Ended December 31, 2019
Unamortized deferred financing fees and premiums	$	(24,725	)
Terminated contracts	(1,435		)
Legal and other professional advisory fees	25,711
Reorganization items, net	$	(449	)

Midstream Segment Results of Operations

Revenue

Our Midstream revenue was primarily derived from product sales, gas gathering and processing, crude oil gathering, and produced water gathering and disposal fees.

(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Sales of gathered production	$	37,195	$	31,506
Midstream revenue	84,763		63,199
Produced water disposal fees	24,988		5,320
Total Midstream revenue	$	146,946	$	100,025
KFM gas volumes (MMcf)	49,147		35,058
KFM crude oil gas volumes (Mbbls)	1,104		1,739
KFM produced water gathering volumes (Mbbls)	25,295		5,320

Sales of gathered production for 2019 increased compared to the 2018 Successor Period due to increased oil and gas gathering volumes and the impact of a second cryogenic processing train commissioned in mid-2018. We process the gas on behalf of the producer and sell the resulting gas, condensate and NGLs at a market price. Product sales are recognized when sold to the third-party purchaser. Amounts recognized in product sales are dependent on whether we are acting in the role of a principal or agent in our contracts with our customers. We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense.

Midstream revenue for 2019 increased compared to the 2018 Successor Period due to increased gas gathering volumes and the impact of a second cryogenic processing train commissioned in mid-2018. The level of drilling and well completion activity of our customers impacts the fees we earn from the throughput of gas we gather and process and the volume of crude oil we gather each period. 

Produced water disposal fees resulted from the acquisition of produced water disposal assets from Alta Mesa during the fourth quarter of 2018. The level of drilling and well completion activity of our customers impacts the amount of fees we generate from the produced water that we gather and dispose of.

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Expenses

(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Midstream operating	$	24,719	$	15,221
Cost of sales for purchased gathered production	34,529		31,247
Transportation and processing	9,659		9,911
Workovers	537		—
Depreciation and amortization	11,675		27,388
Impairment of assets:
Impairment of Cimarron investment	—		15,963
Impairment of property and equipment	348,597		68,407
Impairment of operating lease right-of-use assets	269		—
Impairment of intangible assets	—		394,999
Impairment of goodwill	—		691,970
Total Midstream impairment of assets	348,866		1,171,339
General and administrative	35,427		14,025
Total operating expenses	$	465,412	$	1,269,131

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

Cost of sales for purchased gathered production for 2019 increased compared to the 2018 Successor Period due to increase in sales of gathered production. The margin for net sales increased due to plant efficiency improvements during 2019.

Depreciation and amortization expense for 2019 decreased compared to the 2018 Successor Period due to amortization expense related to intangible customer relationship assets that were fully impaired at December 31, 2018. This impact was coupled with a decrease in tangible asset depreciation as a result of significantly lower book asset values due to impairments recorded during 2018 and 2019, partially offset by depreciation on the produced water assets acquired in the fourth quarter of 2018.

Impairment of assets for 2019 decreased compared to the 2018 Successor Period. During 2019, property and equipment was impaired during the third quarter of 2019 as a result of our impairment analysis arising from the bankruptcy filing by Alta Mesa. We further impaired these assets during the fourth quarter 2019, after taking into consideration the expected purchase price of the KFM Sale Transaction, net of estimated direct costs, for substantially all of our assets. We believe the Buyer has the intent and ability to close the Sale Transactions.

During the 2018 Successor Period, impairment of assets consisted of write-downs of our equity method investment in Cimarron, certain property and equipment and full write-offs of the carrying amount of our intangible assets and goodwill. The fair value of the Midstream segment was negatively impacted by a significant decline in commodity prices in the fourth quarter of 2018 and the related impact on our and other producers’ future upstream operating plans. Our upstream operations contribute a significant portion of the volumetric throughput to the KFM plant. A decline in such throughput negatively impacts future expected profitability, and thus, fair value of the Midstream segment.

We reduced the carrying amount of our investment in Cimarron to adjust its carrying value to fair value at December 31, 2018 due to our decision to abandon the project.

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(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
General and administrative expenses:
Employee-related costs	$	14,569	$	8,199
Equity-based compensation	694		1,190
Professional fees	2,092		1,743
Strategic costs	11,479		10
Severance costs	2,162		—
Information technology	214		240
Operating leases	348		253
Provision for uncollectible receivable	2,310		—
Other	1,559		2,390
Total general and administrative expense	$	35,427	$	14,025

General and administrative expense for 2019 increased compared to the 2018 Successor Period primarily due to increased employee-related costs allocable to KFM, increased costs for legal and strategic financial advisory services associated with financial restructuring activities, and a provision to fully reserve a receivable from KFM’s former owner due to our assessment regarding collectibility. Moreover, following a reassessment of 2019 activity levels, we implemented a reduction in force program during 2019, which along with the departure of our Vice President and Chief Operating Officer - Midstream, resulted in severance costs during the period.

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

(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018
Loss from continuing operations before income taxes	$	(323,975	)	$	(1,174,131	)
Interest expense	11,636			5,031
Depreciation and amortization	11,675			27,388
Loss on sale of property and equipment	106			—
Impairment of assets	348,866			1,171,339
Equity-based compensation	694			1,190
Severance costs	2,162			—
Strategic costs	11,479			—
Provision for uncollectible related party receivables	2,310			—
Gain on equity method investment	(5,503		)	—
Adjusted EBITDA	$	59,450		$	30,817

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Other Income (Expense)

(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018
KFM Credit Facility	$	10,728		$	3,062
Deferred financing cost amortization	463			305
Other	445			1,664
Total interest expense	11,636			5,031
Interest income	(17		)	(6		)
Equity in earnings of unconsolidated subsidiaries	(6,216		)	—
Total other (income) expense	$	5,403		$	5,025

Interest expense for 2019 increased primarily due to higher average debt balances outstanding under the KFM Credit Facility. Other interest primarily relates to commitment fees.  

Equity in earnings of unconsolidated subsidiaries represents our share of earnings due to our equity method investment in Cimarron. In November 2019, we obtained control of Cimarron. As a result, we recognized a gain of $5.5 million to adjust our investment to the fair value of the assets to be received upon consolidating this entity.

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations and to satisfy our contractual obligations. During 2019, our main sources of liquidity and capital resources came from cash on hand, operating cash flow and borrowings under the Alta Mesa RBL and KFM Credit Facility.

On September 11, 2019, the Initial Debtors filed for bankruptcy protection, which constituted an event of default under the Alta Mesa RBL that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the lenders under the Alta Mesa RBL are stayed from taking any action against the AMH Debtors as a result of an event of default. As of December 31, 2019, we had $355.9 million in outstanding borrowings under the Alta Mesa RBL, plus $1.9 million in outstanding letters of credit.

In August 2019, our lenders elected to exercise their right to an off-cycle borrowing base redetermination, whereby they reduced our borrowing base from $370.0 million to $200.0 million. As a condition to the borrowing base reduction, we were required to make monthly installments of $32.5 million for five months, beginning in September 2019, to reduce our outstanding borrowings to the revised borrowing base. AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments. Subsequent to Alta Mesa’s bankruptcy filing, we began operating under a cash collateral order issued by the Bankruptcy Court that allows Alta Mesa to use its cash collateral. The terms and conditions of the cash collateral order include, without limitation, adherence to a lender approved budget with an agreed upon variance and provides for certain monthly reporting obligations.

On September 23, 2019, KFM received a reservation of rights letter from its lenders asserting an event of default under the KFM Credit Agreement, thereby eliminating its ability to access capital under its revolver, pending a cure of the alleged event of default. As a result, KFM utilized cash on hand and cash flow from operations to fund required expenditures and satisfy contractual obligations during the fourth quarter 2019.

On January 12, 2020, the KFM Debtors filed for bankruptcy protection under Chapter 11 of the bankruptcy code, which constituted an event of default under the KFM Credit Facility that accelerated KFM’s obligations thereunder. Under the Bankruptcy Code, the lenders under the KFM Credit Facility are stayed from taking any action against the KFM Debtors as a result of an event of default. As of December 31, 2019, outstanding borrowings under the KFM Credit Facility totaled $224.0 million and there were no outstanding letters of credit. Subsequent to KFM’s bankruptcy filing, we began operating under a cash collateral order issued by the Bankruptcy Court that allows KFM to use its cash collateral. The terms and conditions of the cash collateral order include, without limitation, adherence to a lender approved budget with an agreed upon variance and provides for certain monthly reporting obligations.

Alta Mesa and KFM expect to sell substantially all of their assets no later than mid-April 2020 for a combined price of $320.0 million before deductions for direct costs. Following the expected sale, we intend to provide certain transition services to th

32

e Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

2024 Notes

Alta Mesa has $500.0 million in aggregate principal amount of outstanding notes bearing interest at 7.875% per annum, payable semi-annually each June 15 and December 15. The 2024 Notes mature in December 2024.

Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default including acceleration. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.

Related Party Receivables

On September 29, 2017, Alta Mesa entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC, which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured on February 28, 2019. At December 31, 2019 and 2018, amounts due under the promissory note totaled $1.7 million. HMS defaulted under the terms of that promissory note when it was not paid when due on February 28, 2019, and HMS has failed to cure such default. Alta Mesa subsequently declared all amounts owing under the note immediately due and payable. Alta Mesa also has an $8.5 million promissory 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. As of December 31, 2019, and 2018, the note receivable amounted to $11.7 million. HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to Alta Mesa. We oppose HMI’s claims and believe HMI’s obligation under the notes to be valid assets of Alta Mesa and that the full amount is payable to Alta Mesa. We are pursuing remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. As a result of the potential conflict of interest of certain of our directors who are also controlling holders and directors of HMI, our disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2019, we established an allowance for doubtful accounts for the promissory notes totaling $13.4 million, the expense for which is included in general and administrative expense in 2018.

Interest income on the promissory notes amounted to approximately $0.9 million and $0.1 million for the 2018 Successor Period and the 2018 Predecessor Period, respectively, all recorded as paid-in-kind and added to the balance due thereunder. Due to our assessment of collectability, we did not recognize interest income related to this receivable in 2019.

In connection with the Business Combination, we distributed our non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI 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 “HMI Agreement”) with HMI with respect to its non-STACK assets. Under the HMI 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 HMI 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, (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the HMI 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 Alta Mesa 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 HMI Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the HMI Agreement, and pursuant to the HMI Agreement as “Receivables due from related party” in the balance sheets. As of December 31, 2019 and December 31, 2018, we had receivables of approximately $9.8 million and $10.1 million for costs and expenses incurred on HMI’s behalf. Subsequent to

33

year-end 2018, we billed HMI $0.8 million for incremental MSA costs incurred and have received approximately $1.1 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. We are pursuing remedies under applicable law in connection with repayment of this receivable. We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. As a result, as of December 31, 2019, we have recognized an allowance for uncollectible accounts of $9.8 million to fully provide for the unremitted balance. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities and expect such liabilities, if any, to be addressed in connection with our pending bankruptcy proceedings.

Tax Receivable Agreement  

We are party to a Tax Receivable Agreement (“TRA”) with SRII Opco, High Mesa, and Riverstone VI Alta Mesa Holdings, L.P. This agreement generally provides for the payment by us of 85% of the amount of any realized net cash savings, in U.S. federal, state and local income tax in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for AMR Class A Common Stock (or, in certain circumstances, cash) pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by KFM or otherwise used in KFM’s midstream business, and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the TRA. Also, under the TRA, we retain the benefit of the remaining 15% of these cash savings.

As of December 31, 2019, there had been one exchange of SRII Common Units which would trigger a payment under the TRA. This exchange occurred in November 2018 when 2,752,312 SRII Opco Common Units then held by High Mesa were converted into the same number of shares of AMR Class A Common Stock. We have calculated the tax basis increase resulting from this exchange, and the resulting potential future net cash savings in U.S. federal, state and local income tax, multiplied by 85% to arrive at a potential Tax Receivable Agreement liability. This amount would be due and payable by us if we actually realized these future cash tax savings. However, as of December 31, 2019, we have recorded a full valuation allowance on our other deferred tax assets determined in accordance with GAAP, and therefore we have not realized any savings and have not recorded a liability for such at this time. As a result of our bankruptcy filings and the expected sale of substantially all of our assets, we do not anticipate any payments being required under the TRA.

Cash Flows

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Cash from operating activities	$	143,798		$	86,809		$	26,336
Cash from investing activities	(320,329		)	(560,547		)	(37,913		)
Cash from financing activities	244,724			501,205			16,932
Net increase in cash, cash equivalents and restricted cash	$	68,193		$	27,467		$	5,355

Cash from operating activities

Cash provided by operating activities during 2019 increased compared to the 2018 Successor Period and the 2018 Predecessor Period primarily due to collection of receivables, which were higher at December 31, 2018 as compared to December 31, 2019 due to our bankruptcy filing. Additionally, our 2018 operating cash flow was burdened by nonrecurring costs associated with (i) certain administrative services provided to HMI and its subsidiaries that were subsequently determined to be uncollectible and (ii) the Business Combination. Partially offsetting these factors was an increased use of cash in 2019 associated with prepayment of legal and professional advisor fees relating to our bankruptcy filing as well as a prepayment of transportation fees under a long-term customer contract.

34

Cash from investing activities

Cash used in investing activities during 2019 decreased compared to the 2018 Successor Period and the 2018 Predecessor Period, primarily due to significantly reduced capital expenditures resulting from the suspension of our development activities in conjunction with Alta Mesa’s bankruptcy filing in September 2019. The 2018 Successor Period included activity relating to the Business Combination, which was funded through proceeds withdrawn from a trust account that was established upon the initial public offering of the Company in 2017.

Cash from financing activities

Cash provided by financing activities during 2019 decreased compared to the 2018 Successor Period and the 2018 Predecessor Period. Our ability to borrow funds during 2019 was terminated upon Alta Mesa’s bankruptcy filing in September 2019 and restrictions imposed by the lenders under the KFM Credit Facility due to an alleged default. During the 2018 Successor Period, we received $400.0 million from the sale of our Class A Common Stock and warrants pursuant to a forward purchase agreement, which was partially offset by deferred underwriting payments and certain other costs associated with the Business Combination plus repurchases of our common stock.

Risk Management Activities — Commodity Derivative Instruments

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

Off-Balance Sheet Arrangements

As of December 31, 2019, other than as described below, we had no guarantees of third-party obligations.  Alta Mesa was contingently liable for bonds posted in the aggregate amount of $1.3 million, primarily to cover future abandonment costs, and $1.9 million in letters of credit provided under the Alta Mesa RBL. Upon closing of the expected Sale Transactions, we would be released from these obligations. We have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity and capital resources.

Alta Mesa and HMI are both parties to a payment and indemnity agreement with our current surety provider in connection with regulatory bonds executed prior to the Business Combination covering STACK and non-STACK assets. The surety bonds in place covered by the payment and indemnity agreement for HMI non-STACK properties total approximately $15 million. The surety asserts that Alta Mesa is jointly and severally liable pursuant to the payment and indemnity agreement, but Alta Mesa disputes that claim asserting that the Business Combination evidenced separation between the STACK and non-STACK assets thereby removing any exposure of Alta Mesa to liabilities associated with non-STACK assets. As a result of the dispute, the surety has filed liens on Alta Mesa and KFM assets in order to establish a claim against Alta Mesa in the event HMI is unable to post collateral or otherwise satisfy its obligations with respect to the surety bonds. The closing of the expected Sale Transactions is not expected to impact these outstanding surety bonds.

Critical Accounting Policies and Estimates

Our financial statements are prepared in accordance with GAAP. In connection with preparing our financial statements, we are required to make assumptions and estimates about future events and apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, we review the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.

Our significant accounting policies are discussed in our audited financial statements included elsewhere in this Annual Report. We believe that the following accounting estimates are those most critical to fully understanding and evaluating our reported financial results, and they require our most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.

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Oil and Gas Reserves

Policy Description

Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In calculating cash inflows for reserves, we use an unweighted average of the preceding 12-month first-day-of-the-month prices for determination of proved reserve values and for annual proved reserve disclosures. We assume continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geological maps, well stimulation techniques, well test data and reservoir simulation modeling.

In calculating cash outflows for reserves, we use well costs and operating costs prevailing during the preceding year, but more heavily weighted toward recent demonstration levels, which are then held constant into future periods. Our estimates of proved reserves are determined and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental policies.

We limit our future development program to only those wells that we expect to be developed within five years of their initial recognition.

Judgments and Assumptions

All of our reserve information is based on estimates. Estimates of gas reserves are prepared in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating recoverable underground accumulations of oil and gas. There are numerous uncertainties inherent in estimating recoverable quantities of proved oil and gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, proved reserve estimates may be different from the quantities of oil and gas that are ultimately recovered.

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. We have used estimates of proved reserves in the past to assess for impairment, and we also rely heavily on them in the calculation of depletion expense. For example, if estimates of proved reserves decline, the depletion rate and resulting expense will increase, resulting in a decrease in net income. A decline in estimates of proved reserves have also caused us in previous periods to perform an impairment analysis to determine whether the carrying amount of oil and gas properties exceeds fair value, which would result in an impairment charge, reducing net income.

Successful Efforts Method of Accounting for Oil and Gas Properties

Policy Description

Oil and gas producing activities are accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Accounting policies include:

Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts incurred to obtain a mineral interest or right in a property, such as a lease, options to lease, and related broker and other fees. Properties are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties, or when leases expire or are sold.

Proved Oil and Gas Properties — Costs incurred to lease, drill, complete and equip proved reserves are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment — Our unproved properties consist of leasehold and other capital costs incurred for properties for which no proved reserves have been identified. In determining whether unproved property is impaired, we consider numerous factors including recent leasing activity, recent drilling results in the area, our geologists’ evaluation of the property and the remaining

36

lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated resource potential and, combined with a market approach, estimate fair value of our properties. Our cash flow estimates for probable and possible resource potential is reduced by additional risk-weighting factors. We then reduce the carrying amount of unproved properties, if higher, to estimated fair value.

The capitalized costs of proved oil and gas properties are reviewed at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level or the likely cash flow from sale of the assets to the carrying value of the assets. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value. For our proved oil and gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Judgments and Assumptions

Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.

Key assumptions used to determine the undiscounted future cash flows could include estimates of future production, timing of new wells coming on line, differentials, net estimated operating costs, anticipated capital expenditures and future commodity prices. Our discussion of the judgments inherent in reserve estimation above has information with direct bearing on the judgments surrounding our depletion calculation and impairment analysis. However, in conducting our impairment analysis, we also replace pricing assumptions with future price estimates and we include values for our probable and possible resource potential in determining fair value.

Lower net undiscounted cash flows can result in the carrying amount of our oil and gas properties exceeding the net undiscounted cash flows, which results in an impairment expense. Changes in forward commodity prices and differentials, changes in levels and timing of capital and operating expenses, and changes in production among other items can result in lower net undiscounted cash flows. Forward commodity prices can change quickly and unexpectedly which can negatively impact forward commodity prices, causing lower undiscounted net cash flows. Similarly, future capital and lease operating costs are uncertain and can change quickly based on regional oil and gas drilling activity, steel and other raw material prices, transportation costs and regulatory requirements, among other factors. Increased capital and lease operating costs would result in lower net undiscounted cash flows. Production estimates are determined based on field activities and future drilling plans.

Drilling and field activities require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. As such, actual results may materially differ from predicted results, which could lower production and net undiscounted cash flows.

Recent Accounting Pronouncements

Our audited financial statements in Item 8 contain a description of recent accounting pronouncements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Not required.

37

Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

	Page
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm	39
Consolidated Statements of Operations	40
Consolidated Balance Sheets	41
Consolidated Statements of Cash Flows	43
Consolidated Statements of Changes in Stockholders’ Equity	44
Consolidated Statement of Changes in Partners’ Capital	45
Notes to Consolidated Financial Statements	46
Note 1 — Description of Business	46
Note 2 — Summary of Significant Accounting Policies	47
Note 3 — Chapter 11 Proceedings	57
Note 4 — Impairment of Assets	62
Note 5 — Adoption of ASU No. 2016-02, Leases	63
Note 6 — Receivables	65
Note 7 — Earnings Per Share	67
Note 8 — Supplemental Cash Flow Information	68
Note 9 — Significant Acquisitions and Divestitures	68
Note 10 — Property and Equipment	71
Note 11 — Discontinued Operations (Predecessor)	71
Note 12 — Fair Value Measurements	72
Note 13 — Derivatives	73
Note 14 — Intangible Assets	74
Note 15 — Equity Method Investment	74
Note 16 — Asset Retirement Obligations	75
Note 17 — Long-Term Debt, Net	75
Note 18 — Accounts Payable and Accrued Liabilities	78
Note 19 — Commitments and Contingencies	78
Note 20 — Employee Benefit Plans	80
Note 21 — Significant Concentrations	81
Note 22 — Stockholders’ Equity and Partners’ Capital	81
Note 23 — Equity-Based Compensation (Successor)	83
Note 24 — Income Taxes	86
Note 25 — Related Party Transactions	87
Note 26 — Business Segment Information	89
Note 27 — Supplemental Oil and Natural Gas Disclosures (Unaudited)	91

38

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Alta Mesa Resources, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Alta Mesa Resources, Inc. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity (Successor), changes in partners’ capital (Predecessor) and cash flows for the year ended December 31, 2019, the period from February 9, 2018 to December 31, 2018 (Successor), and the period from January 1, 2018 to February 8, 2018 (Predecessor), and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the year ended December 31, 2019, the period from February 9, 2018 to December 31, 2018 (Successor), and the period from January 1, 2018 to February 8, 2018 (Predecessor), in conformity with U.S. generally accepted accounting principles.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has suffered recurring losses from operations and its liquidity outlook, along with the risks and uncertainties related to its Chapter 11 voluntary petition, raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2018.

Houston, Texas

March 5, 2020

39

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

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Successor						Predecessor
	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Revenue
Oil	$	328,386		$	323,299		$	30,972
Natural gas	53,693			43,407			4,276
Natural gas liquids	40,026			43,039			4,000
Sales of gathered production	37,195			31,506			—
Midstream revenue	30,590			27,460			—
Other	10,330			4,762			888
Operating revenue	500,220			473,473			40,136
Gain on sale of assets	1,382			4,751			840
Gain (loss) on derivatives	(11,744		)	(10,247		)	6,663
Total revenue	489,858			467,977			47,639
Operating expenses
Lease operating	63,755			56,827			4,408
Transportation, processing and marketing	21,042			19,293			3,725
Midstream operating	24,719			15,221			—
Cost of sales for purchased gathered production	34,529			31,247			—
Production taxes	19,455			16,865			953
Workovers	3,189			5,563			423
Exploration	52,354			34,085			7,003
Depreciation, depletion and amortization	132,292			160,942			11,670
Impairment of assets	905,293			3,205,051			—
General and administrative	107,655			131,052			21,234
Total operating expenses	1,364,283			3,676,146			49,416
Operating income	(874,425		)	(3,208,169		)	(1,777		)
Other income (expense)
Interest expense	(61,459		)	(43,296		)	(5,511		)
Interest income and other	243			2,049			172
Equity in earnings of unconsolidated subsidiaries	6,216			—			—
Reorganization items, net	(197		)	—			—
Total other income (expense), net	(55,197		)	(41,247		)	(5,339		)
Loss from continuing operations before income taxes	(929,622		)	(3,249,416		)	(7,116		)
Income tax expense (benefit)	—			(69		)	—
Loss from continuing operations	(929,622		)	(3,249,347		)	(7,116		)
Loss from discontinued operations, net of tax	—			—			(7,746		)
Net loss	(929,622		)	(3,249,347		)	$	(14,862	)
Net loss attributable to non-controlling interest	(479,084		)	(1,724,648		)
Net loss attributable to Alta Mesa Resources, Inc. stockholders	$	(450,538	)	$	(1,524,699	)
Net loss per common share attributable to Alta Mesa Resources, Inc. stockholders:
Basic and diluted	$	(2.48	)	$	(8.71	)

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

40

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

CONSOLIDATED BALANCE SHEETS

(in thousands, except shares and per share data)

	December 31, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	95,367	$	26,854
Restricted cash	681		1,001
Accounts receivable, net	61,187		87,842
Other receivables	1,344		6,331
Related party receivables	—		3,341
Prepaid expenses and other	8,047		1,125
Derivatives	—		16,423
Total current assets	166,626		142,917
Property and equipment
Oil and gas properties, successful efforts method, net	215,352		763,337
Other property and equipment, net	107,028		444,269
Total property and equipment, net	322,380		1,207,606
Other assets
Operating lease right-of-use assets, net	—		—
Equity method investment	—		1,100
Deferred financing costs, net	1,581		3,195
Deposits and other long-term assets	7,993		65
Derivatives	—		2,947
Total other assets	9,574		7,307
Total assets	$	498,580	$	1,357,830

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

41

	December 31, 2019			December 31, 2018
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt	$	224,000		$	690,123
Accounts payable and accrued liabilities	64,137			247,439
Advances from non-operators	811			5,193
Advances from related party	3,175			9,839
Asset retirement obligations, current portion	34			2,079
Operating lease liability, current portion	88			—
Derivatives	—			1,710
Total current liabilities not subject to compromise	292,245			956,383
Long-term liabilities
Asset retirement obligations, net of current portion	13,149			9,473
Long-term debt, net	—			174,000
Operating lease liabilities, net of current portion	189			—
Derivatives	—			180
Other long-term liabilities	3,360			1,667
Total long-term liabilities not subject to compromise	16,698			185,320
Liabilities subject to compromise	896,862			—
Total liabilities	1,205,805			1,141,703
Commitments and contingencies (Note 19)
Preferred stock, $0.0001 par value
Class A: 1,000,000 shares authorized; 3 shares issued; 2 outstanding	—			—
Class B: 1,000,000 shares authorized; 1 share issued and outstanding	—			—
Stockholders’ equity
Common stock, $0.0001 par value
Class A: 1,200,000,000 shares authorized; 182,774,952 and 180,072,227 issued and outstanding at December 31, 2019 and December 31, 2018, respectively.	18			18
Class C: 280,000,000 shares authorized; 199,987,976 and 202,169,576 issued and outstanding at December 31, 2019 and December 31, 2018, respectively.	20			20
Additional paid in capital	1,512,716			1,503,382
Accumulated deficit	(1,983,351		)	(1,532,813		)
Total stockholders’ equity	(470,597		)	(29,393		)
Noncontrolling interest	(236,628		)	245,520
Total equity	(707,225		)	216,127
Total liabilities and stockholders’ equity	$	498,580		$	1,357,830

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

42

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

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Successor						Predecessor
	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Cash flows from operating activities:
Net loss	$	(929,622	)	$	(3,249,347	)	$	(14,862	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	132,292			160,942			12,554
Non-cash lease expense	3,122			—			—
Provision for uncollectible receivables	3,528			22,438			—
Impairment of assets	905,293			3,205,051			5,560
Non-cash reorganization items, net	(26,160		)	—			—
Amortization of deferred financing costs	658			526			171
Amortization of debt premium	(3,432		)	(4,512		)	—
Equity-based compensation expense	6,412			22,025			—
Non-cash exploration expense	43,412			26,055			4,575
(Gain) loss on derivatives	11,744			10,247			(6,663		)
Cash settlements of derivatives	7,642			(38,961		)	(2,296		)
Premium paid on derivatives	(1,906		)	—			—
Interest converted into debt related to Founder notes	—			—			103
Interest added to notes receivable from related party	—			(949		)	(85		)
Loss on sale of property and equipment	106			388			1,923
Equity in earnings of unconsolidated subsidiaries	(6,216		)	—			—
Impact on cash from changes in:
Accounts receivable	26,323			18,011			(21,184		)
Other receivables	4,988			(4,045		)	(662		)
Related party receivables and payables	145			(11,468		)	(117		)
Prepaid expenses and other assets	(29,078		)	11,149			(591		)
Advances from related party	(6,664		)	(37,668		)	24,116
Settlement of asset retirement obligations	(234		)	(1,610		)	(63		)
Accounts payable, accrued liabilities and other liabilities	4,216			(41,463		)	23,857
Operating lease obligations	(2,771		)	—			—
Cash from operating activities	143,798			86,809			26,336
Cash flows from investing activities:
Capital expenditures	(327,567		)	(762,760		)	(36,695		)
Acquisitions, net of cash acquired	—			(823,778		)	(1,218		)
Proceeds withdrawn from Trust Account	—			1,042,742			—
Proceeds from (Contribution to) equity method investment and other	7,238			(17,063		)	—
Proceeds from sale of assets	—			312			—
Cash from investing activities	(320,329		)	(560,547		)	(37,913		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	254,362			431,500			60,000
Repayments of long-term debt	(9,496		)	(273,565		)	(43,000		)
Payment of taxes withheld on equity-based compensation awards	(142		)	—			—
Deferred financing costs paid	—			(3,722		)	—
Purchase and retirement of Class A common shares	—			(14,750		)	—
Capital contributions (distributions)	—			—			(68		)
Proceeds from issuance of Class A shares	—			400,000			—
Repayment of sponsor note	—			(2,000		)	—
Repayment of deferred underwriting compensation	—			(36,225		)	—
Redemption of Class A common shares	—			(33		)	—
Cash from financing activities	244,724			501,205			16,932
Net increase in cash, cash equivalents and restricted cash	68,193			27,467			5,355
Cash, cash equivalents and restricted cash, beginning of period	27,855			388			4,990
Cash, cash equivalents and restricted cash, end of period	$	96,048		$	27,855		$	10,345

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

43

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

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Successor)

(in thousands)

	Common Stock																				Total
	Class A				Class B					Class C					Paid-In			Accumulated			Stockholders’			Noncontrolling			Total
	Shares		Amount		Shares		Amount			Shares		Amount			Capital			Deficit			Equity			Interests			Equity
Balance at February 8, 2018	3,862		$	—	25,875		$	3		—		$	—		$	3,106		$	(8,114	)	$	(5,005	)	$	—		$	(5,005	)
Conversion of common shares from Class B to Class A at closing of Business Combination	25,875		3		(25,875	)	(3		)	—		—			—			—			—			—			—
Class A common shares released from possible redemption	99,638		10		—		—			—		—			996,374			—			996,384			—			996,384
Class A common shares redeemed	(3	)	—		—		—			—		—			(33		)	—			(33		)	—			(33		)
Sale of Class A common shares	40,000		4		—		—			—		—			399,996			—			400,000			—			400,000
Class C common shares issued in connection with the closing of the Business Combination	—		—		—		—			213,402		21			(21		)	—			—			—			—
Noncontrolling interest in SRII Opco issued in the Business Combination	—		—		—		—			—		—			—			—			—			2,058,635			2,058,635
Balance at February 9, 2018	169,372		17		—		—			213,402		21			1,399,422			(8,114		)	1,391,346			2,058,635			3,449,981
Additional Class C common shares issued in connection with the settlement of the purchase consideration in the business combination	—		—		—		—			1,109		—			—			—			—			—			—
Noncontrolling interest in SRII Opco assumed in the business combination	—		—		—		—			—		—			—			—			—			8,758			8,758
Redemption of noncontrolling interests and Class C common shares for Class A common shares	12,341		1		—		—			(12,341	)	(1		)	105,593			—			105,593			(105,599		)	(6		)
Purchase and retirement of Class A common shares and related sale of SRII Opco Common Units	(3,102	)	—		—		—			—		—			(25,589		)	—			(25,589		)	10,839			(14,750		)
Restricted stock awards vested	1,944		—		—		—			—		—			2,465			—			2,465			(2,465		)	—
Equity-based compensation expense	—		—		—		—			—		—			22,025			—			22,025			—			22,025
Shares withheld/retired for taxes on equity awards	(483	)	—		—		—			—		—			(534		)	—			(534		)	—			(534		)
Net loss	—		—		—		—			—		—			—			(1,524,699		)	(1,524,699		)	(1,724,648		)	(3,249,347		)
Balance at December 31, 2018	180,072		18		—		—			202,170		20			1,503,382			(1,532,813		)	(29,393		)	245,520			216,127
Conversion of commons shares from Class C shares to Class A shares	2,182		—		—		—			(2,182	)	—			2,756			—			2,756			(2,756		)	—
Restricted stock awards vested, net of taxes	521		—		—		—			—		—			166			—			166			(308		)	(142		)
Equity-based compensation expense	—		—		—		—			—		—			6,412			—			6,412			—			6,412
Net loss	—		—		—		—			—		—			—			(450,538		)	(450,538		)	(479,084		)	(929,622		)
Balance at December 31, 2019	182,775		$	18	—		$	—		199,988		$	20		$	1,512,716		$	(1,983,351	)	$	(470,597	)	$	(236,628	)	$	(707,225	)

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

44

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

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(in thousands)

໿

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

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

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ALTA MESA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2019

NOTE 1 — DESCRIPTION OF BUSINESS

Alta Mesa Resources, Inc. (“AMR”), together with its consolidated subsidiaries (“we”, “us”, “our” or “the Company”), is an independent exploration and production company focused on the development of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generates revenue primarily through long-term, fee-based contracts.

We were originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II. On March 29, 2017, we consummated our initial public offering (“IPO”). Proceeds from the IPO and a private sale of warrants were placed in a trust account and were used on February 9, 2018, to acquire the interests in Alta Mesa, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and KFM through a newly formed subsidiary, SRII Opco, LP (“SRII Opco”) in a transaction referred to as the “Business Combination” at which time we changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.”.

On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).

On January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.

The Initial and Additional Debtors continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

On December 31, 2019, the Initial Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “AMH PSA”) with BCE-Mach III LLC (the “Buyer”) pursuant to which the AMH Debtors agreed to sell to the Buyer substantially all of our upstream assets for an unadjusted purchase price of $232.0 million in cash, subject to customary purchase price adjustments (such transaction, the “AMH Sale Transaction”). On December 31, 2019, the KFM Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “KFM PSA” and, together with the AMH PSA, the “PSAs”) with the Buyer pursuant to which the KFM Debtors agreed to sell to the Buyer substantially all of our midstream assets for an unadjusted purchase price of $88.0 million in cash, subject to customary purchase price adjustments (such transaction, the “KFM Sale Transaction” and, together with the AMH Sale Transaction, the “Sale Transactions”).

The Sale Transactions are expected to close no later than mid-April 2020, after which we will no longer own any operating assets. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

In March 2020, AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the “AMR Plan”). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH’s creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A common stock and class C common stock in the Company are expected to be canceled.

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The AMR Plan will be subject to approval by the Bankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent that the AMR Plan is confirmed by the Bankruptcy Court, AMR expects the AMR Plan to become effective and be consummated shortly thereafter.

In March 2020, the KFM Debtors filed a Chapter 11 plan (the “KFM Plan”). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors’ estates. Under the KFM Plan, the KFM Debtors will appoint a plan administrator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation.

The KFM Plan is subject to approval by the Bankruptcy Court and the KFM Debtors are expected to solicit votes on the KFM Plan from certain of the KFM Debtors’ creditors pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the KFM Plan in April 2020. To the extent that the KFM Plan is confirmed by the Bankruptcy Court, KFM expects the KFM Plan to become effective and be consummated shortly thereafter.

Our Class A Common Stock and public warrants to purchase Class A Common Stock, sold as part of the shares issued in the IPO, were initially traded on the NASDAQ Capital Market (“NASDAQ”), but due to our failure to continue to meet the NASDAQ’s listing requirements, trading in our stock and public warrants was suspended in September 2019, and are now traded over the counter on the OTC Pink Marketplace under the symbols “AMRQQ” and “AMRWQ”, respectively. In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.

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

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Bankruptcy Accounting

As discussed further in Note 3, on September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Initial Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on our statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy process have been classified as “liabilities subject to compromise” on our balance sheet at December 31, 2019. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. The accompanying financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on stockholders’ deficit accounts of any changes that may be made to our capitalization; or (iv) the effect on operations of any changes that may be made to our business. While operating as debtor-in-possession under Chapter 11 of the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected on its consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications on our historical financial statements.

47

Also, as described further in Note 3, on January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases. The Additional Debtors also continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

Ability to Continue as a Going Concern

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.

As described further in Note 1, we expect to sell substantially all of our assets no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.

Basis of Accounting and Presentation

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  We had no items of other comprehensive income during any period presented. Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation, but had no impact on net income (loss), stockholders’ equity or partners’ capital.  

As a result of the Business Combination, we are the acquirer for accounting purposes and Alta Mesa and KFM are the acquirees. The identifiable assets acquired and liabilities assumed were recorded at their estimated fair values, which were pushed down to each entity. As a result, our financial statements and certain footnotes separate our presentation into two distinct periods, the periods before the consummation of the Business Combination (“Predecessor Periods”) and the period after that date (the “Successor Period”). Our financial statements reflect Alta Mesa as the “Predecessor” for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, reflecting the consolidation of Alta Mesa and KFM beginning on February 9, 2018. The period January 1, 2018 to February 8, 2018 is referred to as the 2018 Predecessor Period. The 2018 Predecessor Period and the periods prior to January 1, 2018 are collectively referred to as the “Predecessor Periods”.

As noted above, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa in connection with the closing of the Business Combination. We determined the non-STACK oil and gas assets and related liabilities are discontinued operations during the Predecessor Periods and have segregated their financial information from ours in the financial statements.

Principles of Consolidation

The financial statements include the accounts of the Company and its subsidiaries, and eliminate all intercompany transactions and balances. The Company’s interests in oil and gas upstream ventures and partnerships are proportionately consolidated. Noncontrolling interest (“NCI”) represents third-party ownership interests in SRII Opco and is presented as a component of equity. The portion of SRII Opco earnings that are not attributable to the Company are separately presented in our statements of operations.

48

Segment Reporting (Successor) 

We operate in two reportable business segments: (i) Upstream and (ii) Midstream. Alta Mesa conducts our Upstream activities and owns proved and unproved oil and gas properties. KFM operates our Midstream segment and owns gas gathering, processing and produced water disposal assets and crude oil gathering and transportation assets. Both segments are conducted in the United States and all revenue was derived from customers located in the United States. 

Use of Estimates

Preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported revenue and expenses during the reporting period. Estimates of reserves and their value are used to determine depletion and to conduct impairment analysis of oil and gas properties and can significantly affect future estimated cash flows utilized to assess goodwill and intangible assets for impairment. Estimating reserves has inherent uncertainty, including the projection of future rates of production and the timing of development expenditures.

Other significant estimates are utilized to determine amounts reported under GAAP related to collectibility of receivables, asset retirement obligations, federal and state taxes and contingencies. We base certain of our estimates on historical experience and various other assumptions that we believe to be reasonable. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. We regularly maintain cash balances that exceed federally insured amounts, but we have experienced no losses associated with these amounts.

Restricted Cash

Cash balances that are legally, contractually or otherwise restricted as to withdrawal or usage are considered restricted cash. As of December 31, 2019, and 2018, our restricted cash represents cash received for production where the final division of ownership is in dispute or there is unclaimed property for pooling orders in Oklahoma. 

Accounts Receivable

Our receivables arise primarily from (i) the sale of our production, (ii) joint interest owners’ portion of operating costs for properties in which we are the operator, and (iii) for midstream services provided to third-party customers. The purchasers of our production and our midstream customers are concentrated in the oil and gas industry and therefore they are similarly affected by prevailing industry conditions.  Accounts receivable are generally not collateralized.  We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties we operate and market the production.

We routinely assess the recoverability of our receivables to determine their collectibility. We establish a valuation allowance to reduce receivables to their estimated collectible amounts, based upon several factors including, our historical experience, the length of time a receivable has been outstanding, communication with customers and the current and projected financial condition of specific customers.

Property and Equipment 

Our oil and gas property is accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts to obtain a mineral interest or right in a property, including related broker and other fees. These costs are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties

49

and become subject to depletion, or when we abandon plans to develop leases are impaired, at which time the costs are expensed as exploration costs. Unproved properties are not subject to depletion.

Proved Oil and Gas Properties — We capitalize costs incurred to drill, complete and equip proved reserves. Proved property costs include all costs incurred to drill and equip successful exploratory wells, development wells (regardless of success), development-type stratigraphic test wells and service wells, plus costs transferred from unproved properties.

Accounting policies for Midstream and other assets include:

Other Property and Equipment — Other property and equipment, such as land, buildings, plant equipment, assets associated with produced water disposal, vehicles, office furniture and office equipment, are recorded at cost.  Maintenance, repairs and minor renewals are expensed as incurred.  Plant and equipment also includes costs for our cryogenic gas processing facility along with gas gathering pipelines and compression, including rights of way, and a crude oil gathering system and crude oil storage facility.

Other important accounting policies affecting property and equipment include:

Depreciation and Depletion — Depletion of proved oil and gas properties is computed using the unit-of-production method based upon produced volumes and estimated proved reserves. Because all of our oil and gas properties are located in a single basin, we apply depletion on a single cost center. We deplete leasehold acquisition costs and the cost to acquire proved properties (generally proved undeveloped costs) based upon total estimated proved reserves. We deplete costs to drill, complete and equip wells plus the related lease costs (generally proved developed costs) over estimated proved developed reserves. 

Through December 31, 2019, we depreciated our Midstream property and equipment using the straight-line method over the estimated useful lives of the assets, which included 35 years for our produced water disposal assets, processing plant and pipelines and 25 years for our compressors. Leasehold improvements were depreciated over the shorter of their useful lives or the term of the lease. Vehicles and office furniture and office equipment were depreciated over their estimated useful lives, ranging from three years to seven years.  As a result of the expected sale of substantially all of our assets no later than mid-April 2020, we will depreciate any assets that are not to be acquired by the Buyer over our expected wind-down period, expected to be less than one year.

Impairment — Because proved reserves have not been ascribed to unproved property, in determining whether it is impaired, we consider numerous factors including recent leasing activity, recent drilling results in the area, our geologists’ evaluation and the remaining lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated proved and unproved reserves and, combined with a market approach, estimate fair value. Our cash flow estimates for unproved reserves are reduced by additional risk-weighting factors. We then reduce the carrying amount, if higher, to estimated fair value.

We review proved oil and gas properties at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows to the carrying value. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value, which we estimate by discounting the projected future cash flows using an appropriate risk-adjusted rate.

We evaluate whether the value of all other long-lived assets, including our midstream assets, is impaired when circumstances indicate the carrying value of those assets may not be recoverable. Such circumstances could result from events such as changes in the condition of an asset, changes to planned throughput or a change in our intent to utilize the asset. The determination of recovery is based on undiscounted cash flow projections or the likely cash flow from sale of the assets compared to the carrying value of the assets. If the carrying amount exceeds undiscounted future net cash flows, we adjust the carrying amount of the assets to their estimated fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent comparable sales, estimated replacement cost, an internally-developed, market participant-based discounted cash flow analysis, an analysis from outside professional advisors or, if the long-lived asset is to be sold, utilizing the likely cash flow from sale as the best estimate of fair value.

Exploration Expense

50

Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired or expiring leases with no expected development, delay rentals, gains or losses on settlement of asset retirement obligations, salaries for geologically-focused employees and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well yields commercial reserves.  If the exploratory well is determined to be unsuccessful, the cost is expensed as exploration expense in the period of that determination. If the exploratory well yields commercial reserves, it is transferred to proved oil and gas properties. Exploratory well costs may continue to be capitalized for several reporting periods if the assessment of commerciality is ongoing.

Equity Method Investment

We account for investments that we do not control, but in which we can exercise significant influence, using the equity method of accounting. Such investments are originally recorded at our acquisition cost. The investment is adjusted by our proportionate share of the investee’s net income, increased by contributions made and decreased by distributions received.

We assess the carrying value of our equity method investments for impairment when indicators exist indicating an impairment may be other-than-temporary. If an impairment is deemed to be other-than-temporary, we adjust the carrying value to fair value, if lower.

In November 2019, we acquired the remaining 50% interest in Cimarron Express Pipeline, LLC (“Cimarron”), which we previously accounted for under the equity method, and consolidated this entity beginning in November 2019.

Deferred Financing Costs

Deferred financing costs reflect fees paid to lenders and third parties that are directly related to our establishment of our long term debt. Prior to the bankruptcy filing by the Initial Debtors, the costs associated with the Alta Mesa RBL were amortized over the term of the Alta Mesa RBL as additional interest expense, with the remaining unamortized costs written off to “reorganization items, net” in our statement of operations upon the bankruptcy filing. The costs associated with the KFM Credit Facility are reported as non-current assets and are amortized over the term of the KFM Credit Facility as additional interest expense but were written off in January after it filed for bankruptcy. During the Predecessor Periods, costs associated with the issuance of our 7.875% senior unsecured notes maturing in December 2024 (the “2024 Notes”) were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense. These Predecessor defined financing costs were eliminated with the Business Combination’s adjustment to 2024 Notes to fair value.

Acquisitions

Business combinations are accounted for using the acquisition method. The results of operations of any acquired businesses are included in our results of operations from the closing date. The total cost of each acquisition is allocated to tangible and intangible assets acquired and liabilities assumed based on their estimated fair values at the time of the acquisition.

Intangible Assets 

In connection with the acquisition of KFM, we recognized the estimated fair value of acquired customer contracts and related customer relationships as intangible assets, which were valued using the income approach. These intangible assets, all of which related to the Midstream segment, had finite lives and were subject to amortization utilizing an accelerated attrition method to approximate the benefit received over their economic lives.

Goodwill

We recognized goodwill as the excess of the purchase price over the estimated fair value of the identified assets and liabilities acquired in the Business Combination. Goodwill was not amortized but was subject to periodic impairment assessment at least annually, or whenever events and circumstances indicated an impairment may exist. 

Asset Retirement Obligations 

We recognize liabilities for the anticipated future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets by increasing the carrying amount of the related long-lived asset at the time it is legally incurred.  The

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fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The asset retirement cost is recognized as depletion or depreciation over the life of the asset.  Accretion expense represents the increase to the discounted liability toward its expected settlement value and is included in “Depreciation, depletion and amortization” in the statements of operations.  Asset retirement obligations are subject to revision primarily for changes related to the estimated timing and cost of abandonment.

There are no material legal or contractual obligations relating to dismantlement, decommissioning or removal of our Midstream assets, other than for certain of our produced water assets, for which asset retirement obligations have been established as of December 31, 2019.

Bond Premium on 2024 Notes  

In connection with the Business Combination, we estimated the fair value of our $500.0 million 2024 Notes at $533.6 million.  The excess fair value above the face value was recognized as a bond premium, which was being amortized as a reduction in interest expense over the remaining term of the notes prior to the time of the bankruptcy filing by the Initial Debtors. The remaining unamortized premium was written off to “reorganization items, net” in our consolidated statement of operations upon the Initial Debtors’ bankruptcy filing.

Derivatives 

We present our derivatives as assets or liabilities at estimated fair value. Changes in fair value of our derivatives, along with realized gains or losses from settlements, are recognized as “Gain (loss) on derivatives” in the statements of operations. Settlements of derivatives are classified as operating cash flows. Where master netting agreements are in place, we net the value of our derivative assets and liabilities with the same counterparty.

Income Taxes

Successor

Deferred income taxes are provided for the temporary differences between the basis of assets and liabilities for financial reporting and income tax purposes. We classify deferred tax assets and liabilities as noncurrent.

We assess the ability to realize our deferred tax assets on a quarterly basis. Deferred tax assets may be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. A valuation allowance is established to reduce deferred tax assets to the amount expected to be realized when we determine that it is more likely than not that some or all of the deferred tax assets are not realizable.

We are also subject to the Texas margin tax, which is considered an income-based tax. We recognize tax (current and deferred) based on taxable income, as determined using the rules for the margin tax as a component of our income tax provision.

We assess uncertain tax positions using a two-step process. If we determine it is more likely than not that the income tax position will be sustained upon examination by the taxing authorities, we recognize the largest amount that is greater than 50% likely to be realized upon ultimate settlement. We have considered our exposure under the standard at both the federal and state tax levels. We did not record any liabilities for uncertain tax positions as of December 31, 2019 or December 31, 2018.

We record interest and penalties for the taxation, as a component of income tax expense. We did not incur any material tax interest or penalties for any period presented.

Alta Mesa’s tax returns for the years ended December 31, 2016 and forward remain open for examination, but none are currently under examination by the relevant authorities.

Predecessor

Alta Mesa historically elected to be treated as an individual partnership for tax purposes. Accordingly, its items of income, expense, gains and losses flowed through to the partners and were taxed at the partner level. Accordingly, no tax provision for federal income taxes was recognized by the Predecessor.

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Predecessor net income (loss) for financial statement purposes differed significantly from taxable income (loss) reported to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under Alta Mesa’s amended and restated partnership agreement.  As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes could not be readily determined due to some tax basis differences being determined at the partner level and Alta Mesa’s lack of information about each unitholder’s tax attributes in Alta Mesa.

Revenue Recognition

Predecessor -

Oil, natural gas, and NGL revenue were recognized when production was sold to a purchaser at a fixed or determinable price, when delivery had occurred and title had transferred, and collectibility of the revenue was reasonably assured. During the Predecessor Periods, we followed the sales method of accounting for revenue. Under this method of accounting, revenue was recognized based on volumes sold. There were no material gas imbalances during the periods presented.

Successor (Upstream) -

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU and the associated subsequent amendments (collectively, “ASC 606”), superseded virtually all of the revenue recognition guidance under GAAP. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services.

Our revenue from contracts with customers includes the sale of crude oil, natural gas, and NGLs. These sales are recognized as revenue when production is sold to a customer in fulfillment of performance obligations under the terms of the underlying contracts. Performance obligations primarily comprise delivery of our production at a delivery point, as negotiated within each contract. Each unit of oil, natural gas, and NGL is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.

Performance obligations are satisfied once control of the product has been transferred to the customer. We consider a variety of facts and circumstances in assessing the point control is transferred, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, our right to payment, and transfer of legal title. Moreover, as part of the process of applying the five-step model, we also evaluated AMH’s and KFM’s arrangement in following the principal-versus-agent guidance under ASC 606. As a principal seller to the customer, revenues are recognized on a gross basis, and as an agent, revenue are recognized on a net basis.

Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price or at purchaser posted prices for the producing area. For oil contracts, AMH is considered to be the principal seller to its customers, and we record sales and related expenses on a gross basis upon satisfaction of our performance obligations.

Our natural gas production is primarily sold to purchasers at prevailing market prices. We evaluate the contract terms of our gas processing arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis based on the assessment of control and, when applicable, principal versus agent guidance under ASC 606. During the Successor Period, we determined that we controlled the products during processing (i.e., control transfers at the tailgate of the processing plant) or until the processor’s sale to the end customers in downstream markets (i.e., the processor is our agent and we are the principal selling party). Accordingly, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the customer and the gathering and processing services are rendered, similar to the accounting treatment required under previous revenue accounting guidance. However, instances in which all or a significant percentage of the proceeds from the sale must be returned to the producer, we are deemed to be the agent. As a result, the purchase and sale are presented as a net transaction with our margin included in gathering and processing revenue. When evaluating the principal-versus-agent guidance under ASC 606 and its impact on AMH and KFM, all facts and circumstances are considered and judgment is often required in making this determination.

Customers are invoiced once our performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30-60 days. There are no significant judgments that

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affect the amount or timing of revenue from contracts with customers. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities, apart from production receivables.

Our receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates, as well as for unbilled costs for wells subject to Oklahoma’s forced pooling process in which mineral owners have the option to participate in the drilling of pooled wells. Depending on the mineral owner’s decision, these costs will be billed to them or added to our oil and gas properties or lease operating expense. Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts.

We have concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors and have reflected this disaggregation of revenue for all periods presented.

We do not have material unsatisfied performance obligations for contracts as all contracts have either an original expected length of one year or less or the entire future consideration is variable and allocated entirely to a wholly unsatisfied performance obligation.

Midstream -

We have the following significant revenue sources each of which we consider to be a distinct service and each of which possesses a single performance obligation:

• Natural gas gathering, processing and sale of residue gas and NGLs for Alta Mesa and third parties;

• Crude oil gathering for Alta Mesa; and

• Produced water gathering and disposal for Alta Mesa and third parties.

We provide our services pursuant to a variety of contracts that set forth our fees, including in certain contracts, the percentage of the proceeds from the sale of our customers’ products in addition to the specified fee. Our services are typically billed on a monthly basis in the month following services or delivery of the product with payment typically due within 30 days. We do not offer extended payment terms and we have no contracts with financing components. Our gathering contracts have initial terms that span multiple years up to the life of the dedicated properties. Our most significant produced water contract has an initial term of 15 years.

We recognize revenue principally under contracts that contain one or more of the following arrangements:

Fee-based arrangements

Revenue for fee-based arrangements are recognized over the contract term with revenue recognized for each month of service based on the volumes delivered by the customer. Both natural gas gathering and processing plus crude oil gathering services are recognized in gathering and processing revenues. Produced water services are recognized as produced water disposal fees.

For service rates that are unchanged over the contract term or escalate only due to inflation, we recognize revenue at the rate in effect during the month of service. We have instances where we also charge supplemental fees for an early period of time during the contract term and this revenue is recognized over the expected period of customer benefit, which is generally the remaining term of the contract. The difference between the amount billed and collected for such early term fees billed during the initial contract term and the amount recorded as revenue is deferred and recognized as contract liabilities. At December 31, 2019 and 2018, we had recognized a deferral of $3.4 million and $1.7 million, respectively, of these early term fees which is included in other long-term liabilities.

Percent-of-proceeds arrangements

Under our percent-of-proceeds arrangements, we generally receive natural gas from producers at or near the wellhead, move it through our gathering system, process it to separate the gas and liquid products and sell the resulting gas and NGLs to third parties. We then remit to the producers an agreed-upon percentage of the actual proceeds received from sales. The margins we earn are directly related to the volumes that flow through our system and the price at which we are able to sell the products.

We evaluate our percent-of-proceeds arrangements with customers against the principal/agent provisions of the underlying contract. For those arrangements where we possess control of the commodity after processing and act as principal in the sale, we record sales revenue equal to the gross price received and we recognize the cost paid to the purchaser as cost of sales of

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gathered purchased production. For those percent-of-proceeds arrangements where we do not control the products after processing, because substantially all of the sales proceeds are paid to the producer, we act as an agent for the producer and only recognize the net margin that we earn within sales of gathered production.

In limited instances, we may also receive products as consideration under percent-of-proceeds agreements. We recognize revenue for the products received at their fair value in the month of service.

Sale of gathered production

We sell gas, NGLs and condensate purchased from our customers to third parties pursuant to short term arrangements at market-based prices adjusted for location and quality differentials. These sales are recognized at the point (i) when we satisfy our performance obligation by transferring control of the product to the purchaser at the specified delivery point, (ii) when amounts are determinable and (iii) when we determine that collectibility is probable. The determination of the point control is transferred relies upon a variety of facts and circumstances including: the purchaser’s ability to use the products, the transfer of significant risks and rewards, our right to payment and transfer of legal title. The cost to purchase the underlying products is recognized when we obtain control of the product, but is generally concurrent with their sale.

Also, we may sell products to other midstream companies pursuant to off-take agreements. Under these contracts, we evaluate whether we control the products during processing and whether the processor controls the products in their sale to the ultimate purchaser. For those contracts where we do not control the products during processing, we recognize revenue on their sale to the midstream company based on the price received net of processing fees earned by the midstream company. For those contracts where we control the products during processing and where we direct their sale, we recognize revenue on the gross price received within sales of gathered production and we recognize the fees paid to the midstream company as transportation, processing and marketing expense.

Equity-Based Compensation 

In 2018, we granted various types of stock-based awards, including stock options, restricted stock and performance-based restricted stock units to certain of our employees.

The fair value of stock option awards is determined using the Black-Scholes option pricing model, which includes various assumptions. Expected volatilities utilized in the option pricing model are based on the re-levered asset volatility implied by a set of comparable companies.  Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date.  Dividend yield is based on our expectations of dividend payments during the expected term of the options granted and risk-free interest rates are based on U.S. Treasury rates in effect at the grant date.

Service-based restricted stock awards are valued using the market price of our Class A Common Stock on the grant date. Performance-based restricted stock awards are valued using the market price of Class A Common Stock at the later of grant date and when all performance-based criteria are determined.

We recognize the estimated fair value of stock option and restricted stock awards as compensation expense on a straight-line basis over the applicable vesting period, which generally is 3.0 years, except in the case of awards made to our directors, which vest immediately upon issuance. Awards of performance-based restricted stock units that contain tranches with multi-year performance targets are recognized over the vesting period for which performance criteria for each tranche have been determined. All awards to employees typically require continued employment to vest. Forfeitures of unvested awards are recognized when they occur and result in the reversal of previously recognized expense.

Fair Value Hierarchy

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date within our principal market.

There are three levels of the fair value hierarchy:

• Level 1 — Fair value is based on quoted prices in active markets for identical assets or liabilities.

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• Level 2 — Fair value is determined using significant observable inputs, generally either quoted prices in active markets for similar assets or liabilities, or quoted prices in markets that are not active.

• Level 3 — Fair value is determined using one or more significant inputs that are unobservable in active markets at the measurement date. Such inputs are often used in pricing models, discounted cash flow calculations, or similar techniques.

We utilize fair value measurements to account for certain items, determine certain account balances and provide disclosures. Fair value measurements are also utilized in assessing the impairment of long-lived assets.

We consider the book values of our cash, accounts and notes receivable and current liabilities to approximate fair value due to their short-term nature. Our outstanding borrowings under the Alta Mesa RBL have been classified as liabilities subject to compromise at December 31, 2019 and the outstanding borrowings under the KFM Credit Facility will be classified similarly following the January 2020 bankruptcy filing by the Additional Debtors as full recovery by our lenders following the expected sale of substantially all of our assets is unlikely.

Earnings Per Share 

Basic earnings per share is calculated by dividing earnings available to Class A common stockholders by the weighted average number of shares outstanding during each period. In periods where we report negative earnings, basic and diluted earnings per share are identical.

The Company uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding SRII Opco Common Units and corresponding shares of its outstanding Class C Common Stock, as well as outstanding warrants and the treasury stock method to determine the potential dilutive effect of restricted stock, restricted stock units and stock options.

Recently Issued Accounting Standards Applicable to Us

Adopted

As described further in Note 5, we adopted Accounting Standards Update 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, effective January 1, 2019.

Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today and would have been effective for us beginning January 2023. We made no determination as to the impact of this new standard on our financial position or results of operations upon adoption.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard, on a prospective basis, beginning January 2020.

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

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NOTE 3 - CHAPTER 11 PROCEEDINGS

Voluntary Reorganization Under Chapter 11

On September 11, 2019, the Initial Debtors filed for reorganization under the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court granted a motion seeking joint administration of the Chapter 11 cases.

In January 2020, the Additional Debtors filed for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Chapter 11 cases. The Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court.

The filing of the Debtors’ bankruptcy petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors to recover, collect or secure a claim arising prior to the bankruptcy filings. Accordingly, although the bankruptcy filing triggered defaults of the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, the creditors are generally stayed from taking any actions as a result of such defaults. Absent an order of the Bankruptcy Court, substantially all of the Initial Debtors’ prepetition liabilities are subject to compromise under the Bankruptcy Code at December 31, 2019 and substantially all of the Additional Debtors’ prepetition liabilities became subject to compromise under the Bankruptcy Code beginning in January 2020.

In September 2019, an official committee of unsecured creditors was appointed. In October 2019, the Bankruptcy Court approved proposed bidding procedures and the dates for an auction and a hearing to approve the sale or sales of assets under Section 363 of the Bankruptcy Code. The auction was held on January 15, 2020, at which a winning bid was selected for substantially all of Alta Mesa and KFM’s assets totaling $320.0 million before certain direct sales costs. The Sale Transactions are expected to close no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

Initial Orders and Other Filings

In September 2019, the Bankruptcy Court approved measures that allow the Initial Debtors to stabilize their businesses and operations. Similar orders requested by the Additional Debtors were approved by the Bankruptcy Court in January 2020. The Debtors are authorized to use cash collateral of their lenders, but the Debtors must adhere to a budget and meet certain milestones.

Liabilities Subject to Compromise

Liabilities subject to compromise at December 31, 2019 represented the Initial Debtors’ remaining prepetition liabilities that have been allowed or that the Initial Debtors anticipate will be allowed as claims in its Chapter 11 cases. The amounts represent the estimated obligations to be resolved in connection with their Chapter 11 proceedings. The differences between the estimate and the claims filed will be evaluated and resolved in connection with the claims resolution process during the pendency of Chapter 11 proceedings.

Following are the components of liabilities subject to compromise:

(in thousands)	December 31, 2019
Alta Mesa RBL	$	355,943
2024 Notes	500,000
Accounts payable and accrued liabilities	20,315
Accrued interest payable on 2024 Notes	9,516
Operating lease liabilities	11,088
Liabilities subject to compromise	$	896,862

Reorganization Items

The Initial Debtors have incurred and, along with the Additional Debtors, are expected to continue to incur significant costs associated with the bankruptcy.

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Components of reorganization items, net included are:

(in thousands)	Year Ended December 31, 2019
Unamortized deferred financing fees and premiums	$	24,725
Terminated contracts	1,435
Legal and other professional advisory fees	(26,357		)
Reorganization items, net	$	(197	)

Interest Expense

The Company did not record interest expense on its 2024 Notes after the Initial Debtors’ filing for bankruptcy. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.

Executory Contracts

Under the Bankruptcy Code, the Debtors may reject certain executory contracts with the approval of the Bankruptcy Court. Generally, the rejection of an executory contract is treated as a prepetition breach of that contract, therefore the Debtors are relieved of performing their future obligations under such executory contract, but the contract counterparty is entitled to file a general unsecured claim for damages.

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Combined Financial Information of Initial Debtors

Combined Statement of Operations

(in thousands)	Year Ended December 31, 2019
Revenue
Oil	$	328,386
Natural gas	53,693
Natural gas liquids	40,026
Other	1,471
Operating revenue	423,576
Gain on sale of assets	1,488
Loss on derivatives	(11,744		)
Total revenue	413,320
Operating expenses
Lease operating	79,884
Transportation and marketing	70,324
Production taxes	19,455
Workovers	2,652
Exploration	52,354
Depreciation, depletion and amortization	120,617
Impairment of assets	556,427
General and administrative	71,823
Total operating expenses	973,536
Operating income	(560,216		)
Other income (expenses)
Interest expense	(49,823		)
Interest income	154
Reorganization items, net	(197		)
Total other income (expense), net	(49,866		)
Loss from continuing operations before income taxes	(610,082		)
Income tax provision (benefit)	—
Net loss	$	(610,082	)

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Combined Balance Sheet

(in thousands)	December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	81,669
Restricted cash	681
Accounts receivable, net	49,256
Other receivables	1,311
Related party receivables, net	17,586
Prepaid expenses and other current assets	6,340
Total current assets	156,843
Property and equipment, net
Oil and gas properties, successful efforts method	215,352
Other property and equipment	23,210
Total property and equipment, net	238,562
Other assets
Investment in subsidiary	1,505,533
Operating lease right-of-use assets, net	—
Deferred financing costs, net	—
Deposits and other long-term assets	6,116
Total other assets	1,511,649
Total assets	$	1,907,054
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	58,858
Accounts payable - related parties	19,425
Advances from non-operators	811
Advances from related party	3,175
Asset retirement obligations, current portion	34
Total current liabilities	82,303
Long-term liabilities
Asset retirement obligations, net of current portion	12,995
Total long-term liabilities	12,995
Liabilities subject to compromise	896,862
Total liabilities	992,160
Partners’ capital	914,894
Total liabilities and partners’ capital	$	1,907,054

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Combined Statement of Cash Flows

(in thousands)	Year Ended December 31, 2019
Cash flows from operating activities:
Net loss	$	(610,082	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	120,617
Non-cash lease expense	2,981
Provision for uncollectible receivables	1,218
Impairment of assets	556,427
Non-cash reorganization items, net	(26,160		)
Amortization of deferred financing costs	195
Amortization of debt premium	(3,432		)
Equity-based compensation expense	5,718
Non-cash exploration expense	43,412
(Gain) loss on derivatives	11,744
Cash settlements of derivatives	7,642
Cash paid for derivatives	(1,906		)
Impact on cash from changes in:
Accounts receivable	18,783
Other receivables	4,957
Related party receivables	3,651
Prepaid expenses and other assets	(25,716		)
Advances from related party	(6,647		)
Settlement of asset retirement obligations	(234		)
Accounts payable, accrued liabilities and other liabilities	22,373
Operating lease obligations	(2,636		)
Cash from operating activities	122,905
Cash flows from investing activities:
Capital expenditures	(249,955		)
Distribution received from subsidiary	691
Cash from investing activities	(249,264		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	199,362
Repayments of long-term debt	(4,496		)
Payment of taxes withheld on equity-based compensation awards	(142		)
Cash from financing activities	194,724
Net increase in cash, cash equivalents and restricted cash	68,365
Cash, cash equivalents and restricted cash, beginning of period	13,985
Cash, cash equivalents and restricted cash, end of period	$	82,350

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NOTE 4 — IMPAIRMENT OF ASSETS

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Upstream
Impairment of unproved properties	$	31,023	$	742,065	$	—
Impairment of proved properties	484,830		1,291,647		—
Impairment of operating lease right-of-use assets	13,245		—		—
Impairment of other long-term assets	27,329		—		—
Total Upstream impairment of assets	556,427		2,033,712		—
Midstream
Impairment of Cimarron investment	—		15,963		—
Impairment of property and equipment	348,597		68,407		—
Impairment of operating lease right-of-use assets	269		—		—
Impairment of intangible assets	—		394,999		—
Impairment of goodwill	—		691,970		—
Total Midstream impairment of assets	348,866		1,171,339		—
Total impairment of assets	$	905,293	$	3,205,051	$	—

Impairment of Proved and Unproved Properties

The Initial Debtors filed for bankruptcy protection in September 2019. The sales price per the AMH PSA is $232.0 million (with a January 1, 2020 effective date) for substantially all of our oil and gas properties and certain other upstream property and equipment, resulting in total impairment expense of $515.9 million for our proved and unproved oil and gas properties and $13.1 million for certain other upstream property and equipment during 2019.

During the late fourth quarter of 2018, we experienced a 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. We determined these factors indicated possible impairment of our assets. Following our analysis of impairment, we recognized impairment charges of $2.0 billion in 2018 to our proved and unproved oil and gas properties using an income approach supplemented by a market approach for our unproved properties.

Impairment of Operating Lease Right-of-Use Assets

During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We sought to sublease our unused office space resulting from the consolidation but have since suspended those efforts in connection with our bankruptcy filing. Additionally, as a result of the expected Sale Transactions, we concluded that all remaining operating lease right-of-use assets were also not recoverable based on expected rejection of those leases in bankruptcy. As a result, we recognized charges of $13.2 million and $0.3 million, respectively, to fully impair all remaining Upstream and Midstream operating lease right-of-use assets at December 31, 2019. This impairment had no impact on our lease liability.

Impairment of Other Long-Term Assets

In addition to the impairment of certain other upstream property and equipment described above, we also recognized impairment expense of $14.2 million associated with a long-term asset relating to a prepayment of certain transportation fees under a long-term customer contract. As part of our bankruptcy proceedings, we expect this contract will be rejected and have determined that recovery of this prepayment is unlikely.

Impairment of equity method investment

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As the late-2018 outlook for Alta Mesa volumes and third-party volume opportunities in the area were significantly lower than initially projected, we suspended future contributions to Cimarron and agreed with our partner to abandon the project. We conducted an impairment analysis resulting in recognition of an impairment charge of $16.0 million to reduce the carrying value of our investment in Cimarron to its estimated fair value at December 31, 2018. In November 2019, we acquired the remaining 50% interest in Cimarron and consolidated this entity thereafter.

Impairment of property and equipment and intangible assets

The sales price per the KFM PSA is $88.0 million (with a January 1, 2020 effective date) for substantially all of our midstream property and equipment, resulting in total impairment expense of $348.6 million during 2019.

In the fourth quarter of 2018, we performed a quantitative assessment of our Midstream property and equipment and intangible assets, which included the use of an income approach which determined that the future undiscounted cash flows associated with our Midstream long-lived assets and intangible assets were below the combined carrying value of those assets. The cash flows used in the income approach were largely determined based on expected future gathering volumes which are dedicated to our gathering and processing facilities and are considered Level 3 inputs. We also considered the overall utilization of the processing plant and applied downward adjustments to the cost approach to account for decreased plant utilization. Based on an estimate of fair value using a discounted cash flow income approach, we determined that the carrying value of our Midstream property and equipment was in excess of its fair value and that the intangible assets were fully impaired at December 31, 2018. Accordingly, we recognized impairment charges in 2018 of $68.4 million to reduce the carrying value of our Midstream property and equipment to fair value and $395.0 million to reduce the remaining carrying value of our intangible assets to zero.

Impairment of goodwill

We performed a quantitative assessment to determine if the goodwill attributable to the Midstream segment was impaired as of December 31, 2018. Our assessment included the use of (i) an income approach to calculate the present value of estimated future discounted cash flows and (ii) a market approach to assess the value of the Midstream segment based on market participant multiples applied to the segment’s 2019 estimated cash generation. The cash flows used in the income approach were largely determined based on expected future production volumes of our Upstream segment, much of which is dedicated to the Midstream segment’s gathering and processing facilities. The income approach also used a market participant-based discount rate. Each of our assumptions regarding earnings, cash flows and discount rates were based mainly on Level 3 unobservable inputs. The results from the income approach and the market approach were appropriately weighted to recognize an impairment charge to eliminate the remaining carrying value of our goodwill.

NOTE 5 — ADOPTION OF ASU NO. 2016-02, LEASES

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

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

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

Upon adoption, we selected the following practical expedients:

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

As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At December 31, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.0 years and the weighted-average discount rate applied was 14.5%.

Lease Costs

(in thousands)	Year Ended December 31, 2019
Operating lease cost	$	3,122
Variable lease cost	1,250
Short-term lease cost	4,410
Total lease cost	$	8,782
Reported in:
Lease operating expense	$	4,241
General and administrative expense	4,541
Total lease cost	$	8,782

Remaining Operating Lease Liability Payments as of December 31, 2019

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Fiscal year	(in thousands)
2020	$	2,256
2021	2,209
2022	2,329
2023	2,321
2024	2,367
Thereafter	8,219
Total lease payments	19,701
Less: imputed interest	(8,336		)
Less: reclassification to liabilities subject to compromise	(11,088		)
Present value of operating lease liabilities	$	277
Current portion of operating lease liabilities	$	88
Operating lease liabilities, net of current portion	189
Present value of operating lease liabilities	$	277

NOTE 6 — RECEIVABLES

Accounts Receivable

(in thousands)	December 31, 2019			December 31, 2018
Production and processing sales and fees	$	40,858		$	51,004
Joint interest billings	12,845			18,147
Pooling interest (1)	7,901			18,786
Allowance for doubtful accounts	(417		)	(95		)
Total accounts receivable, net	$	61,187		$	87,842

_________________

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

Related Party Receivables

(in thousands)	December 31, 2019			December 31, 2018
Related party receivables	$	12,144		$	12,376
Allowance for doubtful accounts	(12,144		)	(9,035		)
Related party receivables, net	—			3,341
Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Related party receivables, net	$	—		$	3,341

At December 31, 2019, we had receivables, including notes receivable from HMI totaling approximately $23.2 million. Because HMI disputes its obligations under the promissory notes with us and challenges other amounts due us, we had fully reserved the outstanding receivables at December 31, 2019 based upon our assessment regarding collectibility.

Additionally, at December 31, 2019, we had receivables of $2.3 million from KFM’s former owner, KFM Holdco, LLC (“KFM Holdco”), relating to transaction costs paid on KFM Holdco’s behalf before the Business Combination. During 2019, we fully

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reserved this receivable based upon our assessment regarding collectibility. We have filed suit against KFM Holdco to seek payment for this receivable.

Management Services Agreement with HMI

(in thousands)
HMI related party receivable at December 31, 2018	$	10,066
Additions	832
Payments	(1,073		)
HMI related party receivable at December 31, 2019	9,825
Allowance for doubtful accounts(1)	(9,825		)
Balance at December 31, 2019, net	$	—

_________________

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

Our management services agreement with HMI (the “HMI Agreement”) was terminated effective January 31, 2019. 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 HMI Agreement. As of December 31, 2019, and December 31, 2018, approximately $9.8 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes or amounts that may become due pursuant to indemnification obligations which became more uncertain when HMI filed for bankruptcy protection in January 2020. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.8 million and $9.0 million as of December 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 December 31, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.

Promissory notes receivable

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

In addition, we have a note receivable from HMS which matured on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount.  HMI disputes its obligations under the note. As of December 31, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods. We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes.

We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. 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 have responsibility to address any potential conflicts of interest with respect to this matter.

Activity in our allowances for doubtful accounts for trade and related party receivables was as follows:

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	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Trade receivables:
Balance at beginning of period	$	95		$	415		$	415
Charged to expense	332			25			—
Deductions	(10		)	(345		)	—
Balance at end of period	$	417		$	95		$	415
Related party receivables:
Balance at beginning of period	$	22,438		$	—		$	—
Charged to expense	3,196			22,438			—
Deductions	(87		)	—			—
Balance at end of period	$	25,547		$	22,438		$	—

NOTE 7 — EARNINGS PER SHARE

(in thousands, except shares and per share data)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018
Net loss attributable to AMR Class A common stockholders	$	(450,538	)	$	(1,524,699	)
Weighted average Class A common shares outstanding (Basic and Diluted)	181,636,795			175,151,969
Basic and diluted loss per common share attributable to AMR common stockholders	$	(2.48	)	$	(8.71	)

During 2019, approximately 201.0 million shares of Class C Common Stock, 63.0 million of warrants and 5.1 million of aggregate stock options, restricted stock and restricted stock units, were excluded from the calculation of diluted earnings per share as their effect would have been anti-dilutive.

During the 2018 Successor Period, approximately 99.9 million shares of Class C Common Stock, 63.0 million of warrants and 6.2 million of aggregate stock options, restricted stock and restricted stock units, were excluded from the calculation of diluted earnings per share as their effect would have been anti-dilutive.

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NOTE 8 — SUPPLEMENTAL CASH FLOW INFORMATION

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	56,683		$	52,017		$	1,145
Cash paid for income taxes	706			1,573			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	853			5,665			—
Increase (decrease) in accruals or payables for capital expenditures	(155,681		)	39,997			4,896
Increase in withholding tax accruals for share-based compensation	142			534			—
Distribution of non-STACK assets, net of liabilities	—			—			43,482
Equity issued in Business Combination	—			2,067,393			—
Release of common stock from possible redemption	—			996,384			—
Other	78			(6		)	—

NOTE 9 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES

We made no acquisitions or divestitures during 2019.

2018 Activity

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

Pursuant to the Contribution Agreements, SRII Opco acquired (a) (i) all of the limited partner interests in Alta Mesa and (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa GP, ((i) and (ii) collectively, the “AM Contribution”) and (b) 100% of the economic interests in KFM (the “KFM Contribution”). SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco, is a wholly owned subsidiary of AMR.  As a result of the Business Combination, our only significant asset was our ownership at that time of an approximate 44.2% partnership interest in SRII Opco. SRII Opco owns all of the economic interests in each of Alta Mesa and KFM. SRII Opco was deemed to be a variable interest entity (“VIE”) and we were deemed to be the primary beneficiary of SRII Opco and have control of SRII Opco through our voting control of SRII Opco GP. Accordingly, we consolidate both SRII Opco and SRII Opco GP, including their consolidated subsidiaries, in our financial results.

Immediately prior to the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa. 

At the closing of the Business Combination:

• we issued (i) 40,000,000 shares of our Class A Common Stock and (ii) warrants to purchase 13,333,333 shares of our Class A Common Stock to Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”) pursuant to the terms of that certain

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Forward Purchase Agreement, dated as of March 17, 2017 (the “Forward Purchase Agreement”) for cash proceeds of $400 million to us;

• we contributed $1,338 million in cash representing (i) the proceeds from the Forward Purchase Agreement and (ii) the net proceeds, after redemptions and payment of deferred underwriting compensation, of the Trust Account, less transaction fees, amounts due Silver Run Sponsor II, LLC. (our “Sponsor”) and reimbursement of seller transaction fees and costs to SRII Opco, in exchange for (i) 169,371,730 of the common units (approximately 44.2%) representing limited partner interests in SRII Opco (the “SRII Opco Common Units”) and (ii) 62,966,651 warrants to purchase SRII Opco Common Units (“SRII Opco Warrants”);

• we caused SRII Opco to issue 213,402,398 SRII Opco Common Units (approximately 55.8%) to the Contributors in exchange for the ownership interests in Alta Mesa, Alta Mesa GP and KFM;

• we agreed to cause SRII Opco to issue up to 59,871,031 SRII Opco Common Units to High Mesa and KFM Holdco if the earn-out conditions were met pursuant to the terms of the Contribution Agreements;

• the Company issued to each of the Contributors a number of shares of Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), equal to the number of the SRII Opco Common Units received by each such Contributor;

• SRII Opco distributed $814.8 million to KFM Holdco in partial payment for the ownership interests in KFM; and

• SRII Opco entered into an amended and restated voting agreement with the owners of the remaining 10% voting interests in Alta Mesa GP whereby such other owners agreed to vote their interests in Alta Mesa GP as directed by SRII Opco.

Holders of our Class C Common Stock, together with holders of Class A Common Stock, voting as a single class, have the right to vote on all matters properly submitted to a vote of the stockholders, but holders of Class C Common Stock are not entitled to any dividends or liquidating distributions from us. The Contributors generally have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. However, we may, at our option, effect a direct exchange of cash or Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption by SRII Opco. Upon the future redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be canceled.

During 2019 and 2018, the Contributors redeemed 2,181,600 and 12,341,076, respectively of SRII Opco Common Units for an equal number of shares of Class A Common Stock through a direct exchange, whereby the combined 14,522,676 SRII Opco Common Units are now owned by us, and we issued an equal number of shares of our Class A Common Stock to them and canceled the related shares of our Class C Common Stock. Additionally, during 2018 we sold 3,101,510 of our Common Units in SRII Opco to SRII Opco to fund purchases of an equivalent number of our Class A common shares. As a result of these and other transactions, at December 31, 2019, we own approximately 47.75% of the limited partner interests in SRII Opco.

Pursuant to the Contribution Agreements, until February 2025, the Contributors were entitled to receive additional SRII Opco Common Units as earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of our Class A Common Stock equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):

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

The Contributors were entitled to the earn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of our assets, if the consideration paid to holders of Class A Common Stock exceeds the above-specified 20-Day VWAP hurdles. The expected sale of substantially all of our assets by mid-April 2020 will not trigger any earn-out consideration.

We also contributed $560.0 million in cash to Alta Mesa at the closing of the Business Combination.  

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Purchase Price for Alta Mesa

(in thousands)	February 9, 2018
Purchase Consideration: (1)
SRII Opco Common Units issued (2)	$	1,261,249
Estimated fair value of contingent earn-out purchase consideration (3)	284,109
Settlement of preexisting working capital	5,476
Total purchase price consideration	$	1,550,834

_________________

(1) The purchase price consideration was for 100% of the limited partner interests in Alta Mesa and 100% of the economic interests and 90% of the voting interests in Alta Mesa GP.  

(2) At closing, the Riverstone Contributor received 20,000,000 SRII Opco Common Units and High Mesa received 138,402,398 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, High Mesa received an additional 1,197,934 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity.

(3) For a period of seven years following Closing, High Mesa was to be entitled to receive earn-out consideration in the form of SRII Opco Common Units. We determined that the fair value of the earn-out consideration was approximately $284.1 million, which was classified as equity. The fair value of the contingent earn-out was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to the Company (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining term of the earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.

Purchase Price for KFM

(in thousands)	February 9, 2018
Purchase Consideration:
Cash (1)	$	809,812
SRII Opco Common Units issued (2)	433,931
Estimated fair value of contingent earn-out purchase consideration (3)	88,105
Settlement of preexisting working capital	(5,476		)
Total purchase price consideration	$	1,326,372

_________________

(1) The cash consideration paid at February 9, 2018 was net of estimated net working capital adjustments, transaction expenses, capital expenditures and banking fees. Pursuant to a final closing statement during the second quarter of 2018, KFM Holdco remitted back to the Company $5.0 million in cash.

(2) At closing, KFM Holdco, LLC received 55,000,000 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, KFM Holdco remitted back 89,680 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock. The SRII Common Units were valued at approximately $7.90 per unit, reflecting discounts for holding requirements and liquidity.

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

Acquisition of acreage

In October 2018, we completed a transaction to acquire certain unproved oil and gas properties for $22.3 million, net of customary post-closing purchase price adjustments.  The acquisition was funded utilizing borrowings under the Alta Mesa

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RBL.  

NOTE 10 — PROPERTY AND EQUIPMENT

(in thousands)	December 31, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	813,310		$	816,282
Accumulated impairment of unproved properties	(813,310		)	(742,065		)
Unproved properties, net	—			74,217
Proved oil and gas properties	2,239,444			2,110,346
Accumulated depreciation, depletion, amortization and impairment	(2,024,092		)	(1,421,226		)
Proved oil and gas properties, net	215,352			689,120
Total oil and gas properties, net	215,352			763,337
Other property and equipment
Land	5,690			5,600
Fresh water wells	27,373			27,366
Produced water disposal system	108,966			104,498
Gas processing plant and gathering lines	414,615			380,470
Office furniture, equipment and vehicles	3,397			3,703
Accumulated depreciation and impairment	(453,013		)	(77,368		)
Other property and equipment, net	107,028			444,269
Total property and equipment, net	$	322,380		$	1,207,606

Depreciation and Depletion

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	118,003	$	129,579	$	11,021
Midstream tangible asset depreciation	11,663		8,235		—
Other property and equipment depreciation	1,646		3,236		609
Total depletion and depreciation	$	131,312	$	141,050	$	11,630

Sale of Produced Water Assets

In November 2018, Alta Mesa sold its produced water assets, consisting of over 200 miles of produced water gathering pipelines and 20 disposal wells, surface leases, easements and other agreements, to a subsidiary of KFM for approximately $99 million, including approximately $90 million in cash at closing and $9 million of purchase price adjustments which, in total, approximated the net book value of the produced water assets.  This transaction was accounted for as a transfer of assets among entities under common control and recorded at carrying value. Accordingly, no gain or loss was recognized. In conjunction with the sale, Alta Mesa entered into a new fifteen-year produced water disposal agreement with KFM.

NOTE 11 — DISCONTINUED OPERATIONS (Predecessor)

Alta Mesa distributed its remaining non-STACK oil and gas assets and liabilities to High Mesa just prior to the closing of the Business Combination. We have determined that these non-STACK oil and gas assets and liabilities are discontinued operations during the Predecessor Periods and we have segregated their financial information in the financial statements.

Prior to the Business Combination, Alta Mesa had notes payable to its founder (“Founder Notes”) that bore simple interest at 10%. The Founder Notes were part of the non-STACK distribution.  The balance of the Founder Notes at the time of conversion

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was approximately $28.3 million, including accrued interest.  Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period.

(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 income (expense)
Interest expense	(103		)
Total other expense	(103		)
Loss from discontinued operations, net of state income taxes	$	(7,746	)

(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 12 — FAIR VALUE MEASUREMENTS

Recurring measurements

We historically utilized the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and gas derivatives. Inputs to these models included observable inputs from the NYMEX for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and gas prices. We have classified the inputs used to determine fair values of all our oil, gas and natural gas liquids derivative contracts as Level 2. See Note 13 - Derivatives for further information.

Non-recurring measurements

We estimated the fair value of Alta Mesa’s 2024 Notes to be $45.3 million at December 31, 2019 ($312.5 million at December 31, 2018), based on their most recent trading values at or near each reporting date, which is a Level 1 determination.

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At December 31, 2019, our oil, gas and midstream properties were evaluated for impairment based on the winning bid prices in a January 2020 auction of our assets conducted as part of a Bankruptcy Court approved sales process. These bid prices are considered a Level 1 input. Prior to December 31, 2019, our oil, gas, and midstream properties, as well as our goodwill and intangible assets in our Midstream segment were subject to impairment testing and potential impairment based largely on future estimated cash flows determined using Level 3 inputs.

	December 31, 2019						December 31, 2018
(in thousands)	Carrying Value Before Assessment		Estimated Fair Value		Impairment		Carrying Value Before Assessment		Estimated Fair Value		Impairment
Unproved oil and gas properties	$	31,023	$	—	$	31,023	$	816,282	$	74,217	$	742,065
Proved oil and gas properties	700,182		215,352		484,830		1,895,670		604,023		1,291,647
Operating lease right-of-use assets	13,514		—		13,514		—		—		—
Other long-term assets(1)	51,518		24,189		27,329		—		—		—
Equity method investment	—		—		—		17,063		1,100		15,963
Midstream property and equipment(1)	432,415		83,818		348,597		474,529		406,122		68,407
Intangible assets	—		—		—		394,999		—		394,999
Goodwill	—		—		—		691,970		—		691,970
Total	$	1,228,652	$	323,359	$	905,293	$	4,290,513	$	1,085,462	$	3,205,051

_________________

(1) Amounts reflect only those assets that were impaired.

We estimate the fair value of additions to asset retirement obligations associated with new or acquired properties. Such estimations of fair value are based on present value techniques that utilize company-specific information for inputs such as the cost and timing of plugging and abandonment of wells and facilities. These inputs are classified as Level 3.

NOTE 13 — DERIVATIVES

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

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

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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

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

	Successor						Predecessor
				February 9, 2018			January 1, 2018
Derivatives not	Year Ended			Through			Through
designated as hedges	December 31, 2019			December 31, 2018			February 8, 2018
Gain (loss) on derivatives -
Oil commodity contracts	$	(16,013	)	$	(3,559	)	$	4,796
Natural gas commodity contracts	4,269			(6,688		)	1,867
Total gain (loss) on derivatives	$	(11,744	)	$	(10,247	)	$	6,663

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

NOTE 14 — INTANGIBLE ASSETS

Our intangible assets represented customer relationships within the Midstream segment acquired in the Business Combination.

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(in thousands)	December 31, 2018
Customer contracts and relationships acquired	$	414,150
Accumulated amortization and impairment	(414,150		)
Intangibles, net	$	—

Amortization expense was $19.2 million during the 2018 Successor Period.  

NOTE 15 — EQUITY METHOD INVESTMENT

In May 2018, a subsidiary of KFM entered into agreements with a third party to jointly construct and operate a new crude oil pipeline via creation of Cimarron that we accounted for under the equity method. Cimarron’s proposed pipeline was to extend from our processing plant to Cushing, Oklahoma and was to be constructed and operated by Cimarron, which we determined was controlled by the third-party. During 2018, we invested $17.1 million in Cimarron, but at December 31, 2018, based on our decision to ultimately abandon the project, we reduced our investment to fair value, which we determined was our portion of the estimated cash remaining at Cimarron after satisfaction of liabilities.

In November 2019, Cimarron redeemed its 50% membership interest from the third party for one-half of the remaining cash in Cimarron plus an immaterial amount of other equipment. As a result, we adjusted our preacquisition equity method investment to the fair value of the residual assets remaining in Cimarron, consisting primarily of cash. This resulted in our recognition of a gain of $5.5 million, which is included in “Equity in earnings of unconsolidated subsidiaries” in our consolidated statements of operations. Following this transaction, Cimarron became our wholly owned subsidiary.

Activity in our equity method investment was as follows:

(in thousands)
Balance, as of February 9, 2018	$	—
Capital contributions	17,063
Impairment	(15,963		)
Balance, as of December 31, 2018	1,100
Equity in earnings through November 13, 2019	713
Adjustment of investment in Cimarron to fair value based on assets received	5,503
Ending balance before obtaining control	$	7,316

We obtained control of the following remaining assets and assumed the following liabilities of Cimarron as a result of execution of an agreement between Cimarron and our partner in November 2019:

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(in thousands)
Cash	$	7,238
Land and rights-of-way	90
Accrued liabilities	(12		)
Net assets received upon consolidation of Cimarron	$	7,316

NOTE 16 — ASSET RETIREMENT OBLIGATIONS

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Balance, beginning of period	$	11,552		$	—		$	10,469
Liabilities assumed in Business Combination(1)	—			5,998			—
Liabilities incurred	859			2,676			—
Liabilities settled	(234		)	(1,610		)	(63		)
Liabilities transferred in sale of properties	—			(19		)	—
Revisions to estimates	26			3,766			63
Accretion expense	980			741			40
Balance, end of period	13,183			11,552			10,509
Less: current portion	34			2,079			33
Long-term portion	$	13,149		$	9,473		$	10,476

_________________

(1) Represents the same wells as under the Predecessor Period but valued at a higher interest rate of 10.2% compared to Predecessor interest rates ranging between 4.4% and 8.8%.

NOTE 17 — LONG-TERM DEBT, NET

(in thousands)	December 31, 2019			December 31, 2018
Alta Mesa RBL	$	355,943		$	161,000
KFM Credit Facility	224,000			174,000
2024 Notes	500,000			500,000
Unamortized premium on 2024 notes	—			29,123
Total debt, net	1,079,943			864,123
Less: Liabilities subject to compromise	(855,943		)	—
Less: Current portion	(224,000		)	(690,123		)
Long-term debt, net	$	—		$	174,000

Alta Mesa RBL

In connection with the Business Combination, we entered into the Alta Mesa RBL which has a face amount of $1.0 billion and had an initial $350.0 million borrowing base, which was subsequently increased to $400.0 million in April 2018. The facility matures in February 2023 and was subject to semiannual redeterminations, as well as an additional optional redetermination between semiannual redeterminations either by us or the lender group. As of December 31, 2019, we had $355.9 million in outstanding borrowings under the Alta Mesa RBL, plus $1.9 million in outstanding letters of credit.

Amounts outstanding under the Alta Mesa RBL are secured by first priority liens on substantially all of our upstream oil and gas properties and all of our equity of our wholly owned guarantor subsidiaries. Upon closing of the expected AMH Sale Transaction, these outstanding amounts will be secured by the proceeds from such sale and all of the equity of our wholly

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owned guarantor subsidiaries. Additionally, SRII Opco and Alta Mesa GP, both of which are under bankruptcy protection at the time of this filing, had pledged their respective partner interests as security.

In August 2019, the lenders exercised their option to conduct an optional redetermination, pursuant to which they established a revised borrowing base of $200.0 million, a reduction from the prior $370.0 million established in April 2019. As a condition to the borrowing base reduction, we were required to make monthly installments of $32.5 million for five months, beginning in September 2019, to reduce our outstanding borrowings to the revised borrowing base. AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments.

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

Prior to default, we had the ability to designate borrowings in either Eurodollars or at a reference rate. Subsequent to our default, all Eurodollar loans were converted into reference rate loans at maturity, which bear interest at a rate per annum equal to the greater of (i) the agent bank’s prime rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus a margin ranging from 1.00% to 2.00%. At December 31, 2019, outstanding borrowings bore interest at a rate of 10.75%, which consisted of the Prime Rate plus additional penalty margins of 2.00% due to our borrowing base deficiency and 2.00% due to our default.

Prior to our default, restrictive covenants generally limited our ability to incur additional indebtedness, sell assets, guarantee or make loans to others, make investments, enter into mergers, make certain payments and distributions in excess of specific amounts, enter into or be party to hedge agreements outside of hedge requirements, amend organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. Subsequent to the AMH Debtors’ bankruptcy filing, we currently operate under cash collateral orders issued by the Bankruptcy Court that allow us to use our cash collateral, with restrictions on our ability to dispose of assets or settle liabilities. The terms and conditions of the cash collateral orders include, without limitation, adherence to a budget with an agreed upon variance and provide for certain monthly reporting obligations.

The Alta Mesa RBL had two covenants that no longer require quarterly testing as a result of our bankruptcy filing.

KFM Credit Facility  

Effective May 30, 2018, KFM entered into the KFM Credit Facility with an aggregate committed amount of $300.0 million. The KFM Credit Facility matures in May 2023. As of December 31, 2019, outstanding borrowings totaled $224.0 million and there were no outstanding letters of credit.

Amounts outstanding under the KFM Credit Facility are secured by first priority liens on substantially all of KFM’s assets and are guaranteed by KFM’s wholly owned subsidiaries. Upon closing of the expected KFM Sale Transaction these outstanding amounts will be secured by the proceeds from such sale and all of the equity of our wholly owned guarantor subsidiaries. Additionally, SRII Opco, LP had pledged its membership interests in KFM as collateral.

In September 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility alleged a potential event of default in respect of liens placed on KFM’s assets. As a result, KFM was unable to borrow additional funds under the KFM Credit Facility after September 2019.

On January 12, 2020, the KFM Debtors filed for protection under the Bankruptcy Code. This filing constituted an event of default under the KFM Credit Facility that accelerated KFM’s obligations thereunder.

Prior to the alleged default, we had the ability to designate borrowings under the KFM Credit Facility in either Eurodollars or at a reference rate. Subsequent to the alleged default, all Eurodollar loans were converted into reference rate loans at maturity, which bear interest at a rate per annum equal to the greater of (i) the agent bank’s prime rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus an applicable margin ranging from 1.00% to 2.25%. At December 31, 2019, outstanding borrowings bore interest at a rate of 6.5%.

Prior to our default, restrictive covenants limited our ability to incur additional indebtedness, dispose of assets, make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge

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agreements, amend organizational documents, incur liens, hold cash in excess of $15.0 million and engage in certain other transactions. Subsequent to the KFM Debtors bankruptcy filing in January 2020, we currently operate under cash collateral orders issued by the Bankruptcy Court that allow us to use our cash collateral, with restrictions on our ability to dispose of assets or settle liabilities. The terms and conditions of the cash collateral orders include, without limitation, adherence to a budget with an agreed upon variance and provide for certain monthly reporting obligations.

The KFM Credit Facility also had two maintenance covenants that no longer require quarterly testing as a result of the cash collateral orders issued in January 2020.

2024 Notes

Our 2024 Notes have a face value of $500 million and bear interest at 7.875% per annum, payable semi-annually each June 15 and December 15. The 2024 Notes mature in December 2024.

Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default including acceleration. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.

The 2024 Notes are guaranteed by each of Alta Mesa’s subsidiaries and rank equal in right of payment to all of Alta Mesa’s existing senior indebtedness; senior in right of payment to all of Alta Mesa’s existing and future subordinated indebtedness; effectively subordinated to all of Alta Mesa’s existing secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Alta Mesa RBL; and structurally subordinated to all existing and future indebtedness and obligations of any of Alta Mesa’s subsidiaries that do not guarantee the 2024 Notes.

The terms of the 2024 Notes originally provided for early redemption over certain periods at their principal amount plus an applicable make-whole premium and contained covenants restricting our ability to enter into certain transactions or to sell or otherwise dispose of assets, among other things.

Bond Premium  

The fair value of the 2024 Notes as of the Business Combination was $533.6 million, yielding a bond premium of $33.6 million. Amortization of the premium reduced our interest expense by $3.4 million and $4.5 million during the year ended December 31, 2019 and the 2018 Successor Period, respectively. Upon filing for bankruptcy protection, the remaining unamortized premium was written off as part of reorganization items, net.

Scheduled Maturities of Debt

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Fiscal Year	(in thousands)
2023	$	579,943
2024	500,000
	$	1,079,943

Based on the defaults associated with Alta Mesa’s and KFM’s bankruptcy filings and the reporting requirements for entities under bankruptcy protection, we have classified all of the indebtedness under the Alta Mesa RBL as liabilities subject to compromise and all of the indebtedness under the KFM Credit Facility as current liabilities at December 31, 2019 despite the scheduled maturities shown above. At December 31, 2018, all of the indebtedness under the Alta Mesa RBL and the related bond premium were classified as current liabilities due to our expectations at that time the indebtedness would become accelerated during 2019.

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NOTE 18 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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	Successor
(in thousands)	December 31, 2019			December 31, 2018
Accounts payable	$	27,349		$	20,422
Accruals for capital expenditures	1,244			139,904
Revenue and royalties payable	27,355			50,241
Accruals for operating expenses	25,131			21,830
Accrued interest	9,663			2,477
Derivative settlements	511			109
Other	1,716			12,456
Total accrued liabilities	65,620			227,017
Less: liabilities subject to compromise	(28,832		)	—
Accounts payable and accrued liabilities	$	64,137		$	247,439

NOTE 19 — COMMITMENTS AND CONTINGENCIES

Commitments

Firm Natural Gas Transportation Commitments  

We have entered into certain firm commitments intended to secure capacity on third party pipelines for transportation of natural gas that extend through 2036 with the following remaining minimum commitments at December 31, 2019:

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(in thousands)	Upstream		Midstream(1)		Total
2020	$	12,236	$	6,116	$	18,352
2021	12,236		6,116		18,352
2022	12,236		5,859		18,095
2023	12,236		5,676		17,912
2024	5,666		5,676		11,342
Thereafter	19,358		64,328		83,686
	$	73,968	$	93,771	$	167,739

_________________

(1) Total cash payments required for committed capacity in MMBtus of 45,750,000 in 2020, 45,625,000 in 2021, 40,275,000 in 2022, 36,500,000 in 2023, 36,600,000 in 2024 and 413,850,000 thereafter. KFM does not currently utilize the full amount of contracted capacity but strives to release capacity to third parties to attempt to minimize the under-utilization.

Other Commitments

KFM has entered into 2 commitments with other midstream providers with the following significant terms:

• An annual commitment for 3,650,000 mcf of processing volumes that runs through December 31, 2021. KFM is required to pay $0.85 per mcf for any shortfall volumes. Volumes processed under this contract are sold to the processor at market value after processing. KFM has entered into an agreement with Alta Mesa whereby Alta Mesa will reimburse KFM for half of the expenses associated with any shortfall.

• A commitment for approximately $128,000 per month of processing services that runs through December 31, 2021. Although there are no associated volumetric minimums, KFM is required to pay for the value of any shortfall from the approximately $128,000 monthly fee. Any volumes processed under this contract are sold to the processor at prevailing market prices after processing.

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Pursuant to the expected Sale Transactions, we anticipate certain of these firm and other commitments will be assumed by the Buyer. As part of the Chapter 11 proceedings any remaining commitments will be rejected by the Bankruptcy Court.

Contingencies

Environmental claims

Various landowners have sued Alta Mesa in lawsuits concerning several fields in which Alta Mesa’s subsidiaries have, or historically had, operations.  The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from its oil and gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims as of December 31, 2019.

Litigation

On January 30, 2019, the Company, James T. Hackett, our then interim Chief Executive Officer and Chairman of the Board, certain of our former and current directors, Thomas J. Walker, our former Chief Financial Officer, and Riverstone Investment Group LLC were named as defendants in a putative securities class action filed in the United States District Court for the Southern District of New York (“SDNY Complaint”). The plaintiff, Plumbers and Pipefitters National Pension Fund, alleges that the defendants disseminated a false and misleading proxy statement in connection with the Business Combination and, therefore, violated Section 14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 14-9 promulgated thereunder. In addition, the plaintiff alleges that Riverstone and the individual defendants violated Section 20(a) of the Exchange Act. The plaintiff is seeking compensatory and/or rescissory damages against the defendants. The District Court transferred this action to the U.S. District Court for the Southern District of Texas.

On March 14 and 19, 2019, two additional putative securities class action complaints were filed in the U.S. District Court for the Southern District of Texas (“SDTX Complaints”) against the same defendants named in the SDNY Complaint, and Harlan H. Chappelle, our former President and Chief Executive Officer, and Michael A. McCabe, our former Chief Financial Officer. These complaints include the same claims asserted in the initial complaint, but also add claims under Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder against us and certain of our current and former officers and directors on behalf of all persons or entities who purchased or otherwise acquired Silver Run or AMR securities between March 24, 2017, and February 25, 2019. The new claims are based upon alleged misstatements contained in our proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants.

On December 19, 2019, the U.S. District Court for the Southern District of Texas consolidated the three putative securities class action lawsuits into a single action. On January 16, 2020, the Court entered a stipulated order appointing Plumbers and Pipefitters National Pension Fund and the First New York Group (consisting of FNY Partners Fund LP, FNY Managed Accounts LLC, and Paul J. Burbach) as co-lead plaintiffs and appointing Camelot Event Driven Fund as an additional consolidated class representative. The amended Consolidated Putative Securities Class Action complaint is due March 16, 2020. The commencement of the Chapter 11 proceedings automatically stayed these actions against the Company.

The outcome of the above consolidated class actions is uncertain, and while we believe that we have valid defenses to the plaintiff’s claims and intend to defend the lawsuits vigorously, no assurance can be given as to the outcome of the lawsuits.

On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to KFM in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants.  We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves. The Mustang litigation was automatically stayed on the commencement of the Chapter 11 proceedings.

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Mustang filed an adversary proceeding (Mustang Gas Products LLC v. Oklahoma Energy Acquisitions, LP et al., Adversary Proceeding No. 20-03015 (Bankr. S.D. Tex.)) against Oklahoma Energy Acquisitions, LP (“OEA”) and other defendants on January 20, 2020, alleging that gas dedication covenants running with the land have a value of not less than $37 million, and entitle Mustang to a corresponding portion of the proceeds of the forthcoming sale of all or substantially all of OEA’s assets. OEA denies these allegations and intends to defend the case vigorously. OEA’s time to respond to Mustang’s complaint has been extended until 15 days after the bankruptcy court enters an order on the pending motion to dismiss filed by the Administrative Agent to the Alta Mesa RBL. It is not possible at this stage of the case to estimate the likelihood of an unfavorable outcome or the range of damages that may be awarded.

In August 2017, Biloxi Marsh Lands (“Biloxi”) filed suit in the 34th District Court for the Parish of St. Bernard, Louisiana, against Meridian Resource & Exploration LLC (“Meridian”, a subsidiary of HMI), Alta Mesa, and other defendants.  Biloxi alleges negligent construction, installation, maintenance, use and operation of a pipeline. In lieu of litigating corporate structure allegations and to reduce potential litigation expenses, Alta Mesa stipulated with respect to Biloxi that it would be bound by and assume liability and responsibility for any unpaid debts, obligations or final judgments that may be entered against Meridian in favor of Biloxi in this matter. However, these allegations relate to non-STACK oil and gas assets that Alta Mesa distributed to a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Consequently, we believe that any potential damages incurred by Alta Mesa or Meridian as a result of these allegations are the responsibility of HMI. There is no guarantee that HMI will pay any settlement amounts or judgments rendered against Alta Mesa or Meridian. In addition, Alta Mesa’s ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI, which recently filed for relief under Chapter 7 of the Bankruptcy Code in the Bankruptcy Court. The commencement of the Chapter 11 proceedings automatically stayed these against the Company. 

SEC Investigation

The SEC is conducting a formal investigation into, among other things, the facts involved in the fair value measurements used in accounting for the Business Combination and the impairment charge recognized during 2018. We are cooperating with this investigation. At this point we are unable to predict the timing or outcome of this investigation. If the SEC determines that violations of the federal securities laws have occurred, the agency has a broad range of civil penalties and other remedies available, some of which, if imposed on us, could be material to our business, financial condition or results of operations.

Other contingencies

We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business, the outcomes of which 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, the Company 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.

Performance appreciation rights.

Our Predecessor had a plan that was intended to provide incentive compensation to key employees and consultants. We canceled all amounts due under the plan at the time of the Business Combination, but recognized and paid $10.9 million as strategic costs in G&A during the 2018 Successor Period.

NOTE 20 — EMPLOYEE BENEFIT PLANS 

We sponsor a 401(k) savings plan, whereby the employees can elect to make contributions. We make matching contributions equal to 100% of the first 5% of an employee’s contributions. Employee contributions are immediately vested whereas company matching contributions typically vested 50% after two years and become fully vested after three years. Company matching contributions were approximately $1.2 million, $1.1 million, and $0.3 million for 2019, the 2018 Successor Period, and the 2018 Predecessor Period, respectively.

Due to the extent of our employee reductions and the expected Sale Transactions, we expect that all employees will receive accelerated vesting of company matching contributions as a result of a partial plan termination.

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NOTE 21 — SIGNIFICANT CONCENTRATIONS

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

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	123,000	$	336,248	$	28,757
Marketing and management fees paid to ARM	$	1,715	$	—	$	—
Fees paid to ARM for services relating to our derivatives	496		784		66
Total fees paid to ARM	$	2,211	$	784	$	66

Receivables from ARM for sales on our behalf were $6.8 million and $43.8 million as of December 31, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

For the year ended December 31, 2019, one customer accounted for 40.5% of our total operating revenue for the period.

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 22 — STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL

Class A Common Stock

Holders of our Class A Common Stock are entitled to one vote for each share held on all matters to be voted on by our stockholders. Holders of the Class A Common Stock and holders of the Class C Common Stock constitute a single class for all stockholder votes. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50% of the shares voted for the election of directors can elect all of the directors (subject to the right of the holders of our Series A Preferred Stock and Series B Preferred Stock to nominate and elect up to five directors in total).

In the event of our liquidation or dissolution, the holders of the Class A Common Stock are entitled to share ratably in all assets remaining after payment of liabilities and after provision is made for each class of stock, if any, having preference over the Class A Common Stock. Our stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the Class A Common Stock.

In August 2018, the Board of Directors authorized up to $50.0 million for the repurchase of our outstanding Class A Common Stock, exclusive of any fees, commissions or other expenses related to such repurchases. Repurchases could be made at the Company’s discretion in open market or private transactions. During 2018, we repurchased and retired 3,101,510 shares of Class A Common Stock, which remain authorized and are available for reissuance at a future date. The price paid for the shares repurchased, including commissions, that was in excess of par value has been recorded as a reduction of approximately $14.8 million in additional paid in capital. To fund the repurchase of our Class A shares of Common Stock, the Company sold 3,101,510 of its SRII Opco Common Units to SRII Opco for the same price paid to the market for the Class A shares repurchased. This resulted in an increase during the 2018 Successor Period in the ownership position of the noncontrolling interest holders in SRII Opco, and an offsetting reduction in the Company’s additional paid in capital, totaling approximately $10.8 million.

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In February 2020, we filed a Form 15 with the Securities and Exchange Commission to deregister our Class A Common Stock under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.

Class C Common Stock

In connection with the Business Combination, we issued 213,402,398 shares of Class C Common Stock to the Contributors, 199,987,976 of which remain outstanding at December 31, 2019 (202,169,576 at December 31, 2018).

Holders of Class C Common Stock, voting as a separate class, are entitled to approve any amendment of our certificate of incorporation that would alter or change the rights and powers of the Class C Common Stock. Holders of Class C Common Stock are not entitled to any dividends and are not entitled to receive any of our assets in the event of our liquidation or dissolution.

Shares of Class C Common Stock may be issued only to the Contributors, their respective successors and assigns, as well as any permitted transferees of the Contributors. A holder of Class C Common Stock may transfer shares of Class C Common Stock to any transferee (other than the Company) only if such holder also simultaneously transfers an equal number of such holder’s SRII Opco Common Units to such transferee in compliance with the amended and restated limited partnership agreement of SRII Opco. The Contributors generally have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. The Company may, however, at its option, effect a direct exchange of cash or Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption by SRII Opco. Upon the future redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be canceled. During 2019, we issued 2,181,600 shares of our Class A Common Stock to an owner of SRII Opco Common Units in exchange for those units, and canceled 2,181,600 of our Class C Common Stock. During the 2018 Successor Period, we issued 2,752,312 and 9,588,764 shares of our Class A Common Stock to equity owners of High Mesa and KFM Holdco, LLC, respectively, and canceled 12,341,076 shares of our Class C Common Stock as a result of the direct exchange of SRII Opco Common Units redemption.

Redeemable Series A Preferred Stock 

As of December 31, 2019, Bayou City Energy Management LLC (“Bayou City”) and HPS Investment Partners, LLC (“HPS”) each own one of the two outstanding shares of our Series A Preferred Stock, and may not transfer the Series A Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate. AM Equity Holding, LP elected to redeem their one share for par value in December 2018. The holders of the Series A Preferred Stock are not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holders are not entitled to dividends. The Series A Preferred Stock is not convertible into any other of our securities, but will be redeemable by us for par value upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series A Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. If the Series A Preferred Stock remains outstanding, its holders are entitled to nominate and elect up to two directors to our board of directors for a period of up to five years following the closing of the Business Combination based on their and their affiliates’ beneficial ownership of common stock. 

Redeemable Series B Preferred Stock 

As of December 31, 2019, the Riverstone Contributor owns the only outstanding share of our Series B Preferred Stock, and may not transfer the Series B Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate (as defined in the limited partnership agreement of SRII Opco). The holder of the Series B Preferred Stock is not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holder is not entitled to dividends. The Series B Preferred Stock is not convertible into any other security of the Company, but will be redeemable by us for par value upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series B Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. If the Series B Preferred Stock remains outstanding, its holder is entitled to nominate and elect up to three directors to our board of directors for a period of up to five years following the closing of the Business Combination based on its and its affiliates’ beneficial ownership of common stock.

Warrants

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As of December 31, 2019, we had 62,966,651 warrants outstanding, consisting of 34,499,985 public warrants originally sold in our IPO (“Public Warrants”), 15,133,333 Private Placement Warrants sold to our Sponsor and 13,333,333 Forward Purchase Warrants issued to Riverstone VI SR II Holdings, LP.

Each Public Warrant entitles the holder to purchase one share of our Class A Common Stock for $11.50 and expire in February 2023. 

The Private Placement Warrants are identical to the Public Warrants, except the Private Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees.

The Forward Purchase Warrants have terms and provisions that are identical to those of the Private Placement Warrants, except the Forward Purchase Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees. The Forward Purchase Warrants were sold in a private placement pursuant to a purchase agreement between us and our Sponsor.

In February 2020, we filed a Form 15 with the Securities and Exchange Commission to deregister our warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.

Noncontrolling Interest (“NCI”)

NCI relates to SRII Opco Common Units that were originally issued to the Contributors, in connection with the Business Combination and continue to be held by holders other than the Company. At the date of the Business Combination, the noncontrolling interest owners held 55.8% of the limited partner interests in SRII Opco. The non-controlling interest percentage is affected by Class C Common Stock conversions and the Class A Common Stock activities after which, the noncontrolling interest owners held 52.25% at December 31, 2019 (53.0% at December 31, 2018).

Partnership Management and Control

Alta Mesa’s amended and restated partnership agreement provides for interests to be divided into economic units held by the partners referred to as “LP Units” and non-economic general partner interests owned by Alta Mesa GP referred to as “GP Units”.  Alta Mesa GP owns all the GP Units and SRII Opco owns all the LP Units. 

Since Alta Mesa is a limited partnership, its operations and activities are managed by the board of directors of its general partner, Alta Mesa GP.  The limited liability company agreement of Alta Mesa GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic rights in Alta Mesa GP and (ii) Class B Units, which hold 100% of the voting interests in Alta Mesa GP. 

SRII Opco is the sole owner of Alta Mesa GP’s Class A Units and owns 90% of the Class B Units.  Our former President and Chief Executive Officer and our former Chief Operating Officer—Upstream, along with certain affiliates of Bayou City and HPS, own an aggregate 10% of the Class B Units.  Alta Mesa GP’s board of directors are selected by the Class B members.  Notwithstanding the foregoing, voting control of Alta Mesa GP is vested in SRII Opco pursuant to a voting agreement.

Cancellation

We expect that our reorganization pursuant to the bankruptcy proceedings will result in the cancellation of all equity that existed at December 31, 2019.

NOTE 23 — EQUITY-BASED COMPENSATION (Successor)

We have adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”).  A total of 50,000,000 shares of Class A Common Stock were initially reserved for issuance under the LTIP.  The LTIP provided for the grant of stock awards, including incentive stock options (“ISOs”), nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units and other awards in our Class A Common Stock. Prior to the Business Combination, we had no equity-based compensation programs. During 2019 and the 2018 Successor Period, we recognized stock-based compensation expense of $6.4 million and $22.0 million, respectively, in general and administrative expense including accelerated vesting in 2018 for separated executives related to the LTIP.  

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On February 11, 2020, we filed a post-effective amendment to our registration statement on Form S-8 (Registration No. 333-224248) to deregister unissued and unsold shares of Class A Common Stock issuable to participants under the LTIP. Accordingly, we are no longer able to grant restricted stock or shares of our Class A Common Stock in satisfaction of our outstanding unexercised stock options, unvested restricted stock and unvested performance-based restricted stock units (“PSUs”) and we anticipate those outstanding stock awards will be canceled as a result of our bankruptcy filing.

Stock options 

Stock options previously granted were set to expire seven years from the grant date and generally were to vest in one-third increments each year, based on continued employment. Employees had 90 days after termination to exercise vested stock options, unless extended by an employment agreement.

	Stock Options		Weighted Average Exercise Price		Weighted Average Grant-Date Fair Value		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of February 9, 2018	—		$	—	$	—	—	$	—
Granted	5,283,224		8.80		4.33		—	—
Exercised	—		—		—		—	—
Forfeited or expired	(139,319	)	9.38		4.55		—	—
Outstanding as of December 31, 2018	5,143,905		$	8.79	$	4.33	5.3	$	—
Granted	157,710		$	1.07	$	0.61	—	$	—
Exercised	—		—		—		—	—
Forfeited or expired	(1,498,328	)	8.44		4.20		—	—
Outstanding as of December 31, 2019	3,803,287		$	4.80	$	4.22	3.19	$	—
Exercisable as of December 31, 2019	2,260,388		$	9.21	$	4.49	5.15	—

The following assumptions were used to determine the fair value of our 2019 and 2018 option grants:

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	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Expected term (in years)	4.5		4.5
Expected stock volatility	69.8	%	64.6	%
Dividend yield	—		—
Risk-free interest rate	2.4	%	2.5	%

Unrecognized compensation cost related to non-vested stock options at December 31, 2019 was $3.5 million, with a remaining weighted average vesting period of 0.8 years.

Restricted stock 

Restricted stock granted to employees generally vested in one-third increments each year based on continued employment. Prior to vesting, unvested restricted stock may not be traded but was entitled to accumulate any dividend value. During the 2018 Successor Period, we granted 98,199 shares to certain of our directors, all which vested immediately, and granted 2,140,160 restricted stock awards to employees. All 2019 grants were to employees.

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The following table provides information about activity in our restricted stock awards during the 2018 Successor Period and year ended December 31, 2019:

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	Restricted Stock Awards		Weighted Average Grant Date Fair Value per share
Outstanding as of February 9, 2018	—		$	—
Granted	2,238,359		7.54
Vested(1)	(384,413	)	8.40
Forfeited or expired	(61,935	)	8.80
Outstanding as of December 31, 2018	1,792,011		7.32
Granted	70,093		0.96
Vested(1)	(619,061	)	7.04
Forfeited or expired	(719,766	)	7.36
Outstanding as of December 31, 2019	523,277		$	6.74

_________________

(1) To satisfy minimum tax withholding, 130,432 and 94,576 shares were withheld in 2019 and during the 2018 Successor Period.

Unrecognized compensation cost related to unvested restricted shares at December 31, 2019 was $2.1 million, with a remaining weighted average vesting period of 1.4 years.

Restricted stock units

Our PSUs granted in 2018 generally vested over three years at 20% during the first year, 30% during the second year and 50% was schedule to vest during the third year. The number of PSUs vesting each year were based on the achievement of annual performance goals and objectives applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that vest could range from 0% to 200% of the target grant applicable to each vesting period. We only recognize expense for PSUs when the specified performance thresholds for future periods have been established. For PSUs granted during the 2018 Successor Period only the performance goals and objectives for 2018 had been established as of December 31, 2018. Those 2018 performance goals were not attained, and the 2018 award tranche was forfeited, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted. The targets for 2019 were established in March 2019. The 2019 award tranche vested at 199% of target. Due to our bankruptcy and the expected sale of substantially all of our assets, no performance targets will be established for the 2020 award tranche and we expect that tranche will be forfeited as part of our bankruptcy proceedings.

The following table provides information about activity in our PSUs granted during the 2018 Successor Period and year ended December 31, 2019:

	PSUs		Weighted Average Grant Date Fair Value per unit
Outstanding as of February 9, 2018	—		$	—
Granted	2,093,453		4.07
Vested (1)	(1,559,749	)	2.53
Forfeited or expired	(533,704	)	8.54
Outstanding as of December 31, 2018	—		—
Granted	1,220,490		0.32
Vested	(100,870	)	0.96
Forfeited or expired	(54,112	)	0.27
Outstanding as of December 31, 2019	1,065,508		$	0.27

_________________

(1) To satisfy minimum tax withholding, 32,481 and 388,655 shares were withheld in 2019 and during the 2018 Successor Period.

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As of December 31, 2019, there was no unrecognized compensation cost related to unvested PSUs.

NOTE 24 — INCOME TAXES

As a result of the Business Combination, our wholly owned subsidiary, SRII Opco GP, is the general partner of SRII Opco, which became the sole managing member of Alta Mesa GP and KFM, and as a result, we began consolidating the financial results of Alta Mesa and KFM. SRII Opco is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, SRII Opco is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by SRII Opco is passed through to and included in the taxable income or loss of its limited partners, including the Company, on a pro rata basis. The Company is subject to U.S. federal income taxes, in addition to state and local income taxes, with respect to its allocable share of any taxable income or loss of SRII Opco, as well as any stand-alone income or loss generated by the Company.

Income tax expense (benefit) included in the statements of operations is detailed below:

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(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Current taxes:
Federal	$	—	$	(69	)
State	—		—
	—		(69		)
Deferred taxes:
Federal	—		—
State	—		—
	—		—
Income tax expense (benefit)	$	—	$	(69	)

A reconciliation of the statutory federal income tax expense to the income tax expense from continuing operations is as follows:

(Amounts in thousands)	Year Ended December 31, 2019					February 9, 2018 Through December 31, 2018
Federal income tax expense (benefit) - at statutory rate	$	(195,221	)	21.00	%	$	(682,378	)	21.00%
State income taxes - net of federal income tax benefit	(44,064		)	4.74		(154,022		)	4.74
Non-controlling interest	123,316			(13.27	)	833,239			(25.64	)
Return to provision	(1,690		)	0.18		(71		)	—
Change in valuation allowance	136,568			(14.69	)	3,135			(0.1	)
Permanent items	—			—		25			—
Other	(18,909		)	2.04		3			—
Income tax expense (benefit)	$	—		—	%	$	(69	)	—	%

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The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities are presented below:

(in thousands)	December 31, 2019			December 31, 2018
Deferred tax asset:
Investment in SRII Opco, LP	$	424,086		$	269,846
59(e) capitalized IDC	53,814			—
NOL carryforward	29,866			101,337
Organizational/startup costs	144			154
Other	7			11
Total deferred tax assets	507,917			371,348
Less: valuation allowance	(507,917		)	(371,348		)
Net deferred tax assets	—			—
Deferred tax liability	—			—
Total net deferred tax assets/(liabilities)	$	—		$	—

The change in our valuation allowance during the year ended December 31, 2019 was $136.6 million.

In connection with the Business Combination, we entered into the Tax Receivable Agreement with SRII Opco, High Mesa, and the Riverstone Contributor. This agreement generally provides for the payment by us of 85% of the amount of net cash savings, if any, in income tax that we actually realize (or are deemed to realize in certain circumstances) in periods after the Business Combination as a result of (i) tax basis increases resulting from the exchange of SRII Opco Common Units for AMR Class A Common Stock and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings.

The payment obligations under the Tax Receivable Agreement are obligations of the Company and not obligations of SRII Opco, and the payments required could have been substantial. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been entitled to any of the tax benefits subject to the Tax Receivable Agreement. In other words, we would calculate our federal, state and local income tax liabilities as if no tax attributes arising from a redemption or direct exchange of SRII Opco Common Units had been transferred to us. The term of the Tax Receivable Agreement continues until all such tax benefits have been utilized or have expired, unless we exercise our right to terminate the Tax Receivable Agreement or the Tax Receivable Agreement is otherwise terminated.

As of December 31, 2019, there has been one exchange of SRII Common Units which would trigger a payment under the TRA. This exchange occurred in November 2018 when 2,752,312 SRII Opco Common Units were converted into the same number of shares of AMR Class A Common Stock. We have calculated the tax basis increase resulting from this exchange, and the resulting potential future net cash income tax savings multiplied by 85% to arrive at a potential Tax Receivable Agreement liability. This amount would be due and payable by us if we actually realized these future cash tax savings. However, as of December 31, 2019 we have recorded a full valuation allowance on our other deferred tax assets determined in accordance with GAAP, and therefore we have not realized any savings and have recorded no liability for such at this time. We believe there is a very low likelihood that we will utilize these attributes in 2020 or future years, due to the expected outcome of our bankruptcy filing.

NOTE 25 — RELATED PARTY TRANSACTIONS

Gathering Agreements

On August 31, 2015, Alta Mesa’s wholly owned subsidiary Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM. The Gas Gathering and Processing Agreement was subsequently amended in February 2017, effective December 2016, and again in June 2018, effective April 2018. The more recent amendment to the Gas Gathering and

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Processing Agreement impacts our ability to make elections with respect to the NGL portion of our production volumes but has no other effect on our consolidated financial statements.

Employees

David McClure, our former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of approximately $769,000, $1,158,000, and $29,000 for the year ended December 31, 2019, the 2018 Successor Period, and the 2018 Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019.

Bayou City Joint Development Agreement

In January 2016, 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 Alta Mesa’s drilling operations and to allow Alta Mesa to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provided opportunities for the parties to potentially agree to an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of Alta Mesa’s working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. In exchange for funding the drilling and completion costs, BCE received 80% of our working interest in each wellbore, which BCE interest would be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, Alta Mesa and BCE would each bear its respective proportionate working interest share of all subsequent operating costs related to such joint well.  Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depended on a number of factors outside his control and is not known at this time.  During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA, a portion of which was refunded during the 2018 Successor Period. As of December 31, 2019, 61 joint wells have been drilled or spudded. As of December 31, 2019 and December 31, 2018, $3.2 million and $9.8 million, respectively of revenue payable liabilities 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 consolidated balance sheets. No new wells were drilled in 2019 under the JDA and as of December 31, 2019, there were no funded horizontal wells in progress, and none were developed in 2020. 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. The JDA expired in January 2020 pursuant to its terms.

BCE-Mach III LLC

BCE-Mach III LLC, a Delaware limited liability company formed by Bayou City Energy Management, LLC, a related party, and Mach Resources LLC, is the buyer of our assets pursuant to the Sale Transactions, which we expect to close no later than mid-April 2020.

High Mesa - Promissory Notes

In September 2017, Alta Mesa entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC, which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured in February 2019. At December 31, 2019 and 2018, amounts due under the promissory note totaled $1.7 million. HMS defaulted under the terms of that promissory note when it was not paid when due on February 28, 2019, and HMS has failed to cure such default. Alta Mesa subsequently declared all amounts owing under the note immediately due and payable. Alta Mesa also has an $8.5 million promissory 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. As of December 31, 2019 and 2018, the note receivable amounted to $11.7 million. HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to Alta Mesa. We oppose HMI’s claims and believe HMI’s obligation under the notes to be valid assets of Alta Mesa and that the full amount is payable to Alta Mesa. We are pursuing remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. As a result of the potential conflict of interest of certain of our directors who are also controlling holders and directors of HMI, our disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2019, we have an allowance for doubtful accounts for the promissory notes totaling $13.4 million, the expense for which is included in general and administrative expense in 2018.

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Interest income on the promissory notes amounted to approximately $0.9 million and $0.1 million for the 2018 Successor Period and the 2018 Predecessor Period, respectively, all recorded as paid-in-kind and added to the balance due thereunder. Due to our assessment of collectability, we did not recognize interest income related to this receivable in 2019.

High Mesa - Management Services Agreement

In connection with the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Under the HMI 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 HMI Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the HMI 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 Alta Mesa 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 HMI Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the HMI Agreement, and pursuant to the HMI Agreement have reflected these costs as “Related party receivables” in the balance sheets. As of December 31, 2019 and December 31, 2018, we had receivables of approximately $9.8 million and $10.1 million, respectively, for costs and expenses incurred on HMI’s behalf. During 2019, we billed HMI $0.8 million for incremental costs incurred and have received approximately $1.1 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. We are pursuing remedies under applicable law in connection with repayment of this receivable.

We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. As a result, at December 31, 2019 and December 31, 2018, we had allowances for uncollectible accounts of $9.8 million and $9.0 million, respectively, to fully provide for the unremitted balance. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities and expect such liabilities, if any, to be addressed in connection with our pending bankruptcy proceedings.

NOTE 26 — BUSINESS SEGMENT INFORMATION

Following the Business Combination, we have two reportable segments: (i) Upstream and (ii) Midstream.  Each segment is ultimately led by our Chief Executive Officer, who is also the Chief Operating Decision Maker (“CODM”).  The CODM evaluates segment performance using Adjusted EBITDAX and Adjusted EBITDA. 

We believe Adjusted EBITDAX and Adjusted EBITDA are 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 and Adjusted EBITDA should not be considered as an alternative to net income (loss), operating income (loss) or any other performance measure derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports.

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	Year Ended December 31, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations				Total
Revenue
Oil	$	328,386		$	—		$	—			$	328,386
Natural gas	53,693			—			—				53,693
Natural gas liquids	40,026			—			—				40,026
Sales of gathered production	—			37,195			—				37,195
Midstream revenue	—			84,763			(54,173		)		30,590
Segment sales revenue	422,105			121,958			(54,173		)		489,890
Other revenue	1,471			24,988			(16,129		)		10,330
Operating revenue	423,576			146,946			(70,302		)		500,220
Gain (loss) on sale of assets	1,488			(106		)	—				1,382
Gain (loss) on derivatives	(11,744		)	—			—				(11,744		)
Total revenue	413,320			146,840			(70,302		)		489,858
Operating expenses
Lease operating	79,884			—			(16,129		)		63,755
Transportation, processing and marketing	70,324			9,659			(58,941		)		21,042
Midstream operating	—			24,719			—				24,719
Cost of sales for purchased gathered production	—			34,529			—				34,529
Production taxes	19,455			—			—				19,455
Workovers	2,652			537			—				3,189
Exploration	52,354			—			—				52,354
Depreciation, depletion, and amortization	120,617			11,675			—				132,292
Impairment of assets	556,427			348,866			—				905,293
General and administrative	59,897			35,427			12,331				107,655
Total operating expenses	961,610			465,412			(62,739		)		1,364,283
Operating income	(548,290		)	(318,572		)	(7,563		)		(874,425		)
Other income (expense)
Interest expense	(49,823		)	(11,636		)	—				(61,459		)
Interest income and other	154			17			72				243
Equity in earnings of unconsolidated subsidiaries	—			6,216			—				6,216
Reorganization items, net	449			—			(646		)		(197		)
Total other income (expense)	(49,220		)	(5,403		)	(574		)		(55,197		)
Income (loss) from continuing operations before income taxes	(597,510		)	(323,975		)	(8,137		)	—	(929,622		)
Interest expense	49,823			11,636			—				61,459
Depreciation, depletion and amortization	120,617			11,675			—				132,292
Loss on unrealized hedges	19,386			—			—				19,386
Loss on sale of property and equipment	—			106			—				106
Impairment assets	556,427			348,866			—				905,293
Provision for uncollectible related party receivables	886			2,310			—				3,196
Equity-based compensation	5,718			694			—				6,412
Exploration	52,354			—			—				52,354
Severance costs	4,865			2,162			—				7,027
Strategic costs	8,116			11,479			2,025				21,620
Non-cash lease operating expense	3,835			—			—				3,835
Gain on equity method investment	—			(5,503		)	—				(5,503		)
Reorganization items, net	(449		)	—			646				197
Adjusted EBITDAX	$	224,068		$	59,450		$	(5,466	)		$	278,052
Equity method investment	$	—		$	—		$	—			$	—
Capital expenditures	249,955			77,612			—				327,567
Total assets at period end	396,041			112,825			(10,286		)		498,580

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	February 9, 2018 Through December 31, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations				Total
Revenue
Oil	$	323,299		$	—		$	—			$	323,299
Natural gas	43,407			—			—				43,407
Natural gas liquids	43,039			—			—				43,039
Sales of gathered production	—			31,506			—				31,506
Midstream revenue	—			68,519			(41,059		)		27,460
Segment sales revenue	409,745			100,025			(41,059		)		468,711
Other revenue	4,762			—			—				4,762
Operating revenue	414,507			100,025			(41,059		)		473,473
Gain on sale of assets	4,751			—			—				4,751
Gain (loss) on derivatives	(10,247		)	—			—				(10,247		)
Total revenue	409,011			100,025			(41,059		)		467,977
Operating expenses
Lease operating	60,547			—			(3,720		)		56,827
Transportation, processing and marketing	50,038			9,911			(40,656		)		19,293
Midstream operating	—			15,221			—				15,221
Cost of sales for purchased gathered production	—			31,247			—				31,247
Production taxes	16,865			—			—				16,865
Workovers	5,563			—			—				5,563
Exploration	34,085			—			—				34,085
Depreciation, depletion, and amortization	133,554			27,388			—				160,942
Impairment of assets	2,033,712			1,171,339			—				3,205,051
General and administrative	114,735			14,025			2,292				131,052
Total operating expenses	2,449,099			1,269,131			(42,084		)		3,676,146
Operating income	(2,040,088		)	(1,169,106		)	1,025				(3,208,169		)
Other income (expense)
Interest expense	(38,265		)	(5,031		)	—				(43,296		)
Interest income and other	1,983			6			60				2,049
Total other income (expense)	(36,282		)	(5,025		)	60				(41,247		)
Income (loss) from continuing operations before income taxes	(2,076,370		)	(1,174,131		)	1,085			(1)	(3,249,416		)
Interest expense	38,265			5,031			—				43,296
Depreciation, depletion and amortization	133,554			27,388			—				160,942
Gain on unrealized hedges	(28,714		)	—			—				(28,714		)
Loss on sale of fixed assets	388			—			—				388
Impairment of assets	2,033,712			1,171,339			—				3,205,051
Provision for uncollectible related party receivables	22,438			—			—				22,438
Equity-based compensation	20,000			1,190			835				22,025
Exploration	34,085			—			—				34,085
Business Combination	23,717			—			—				23,717
Adjusted EBITDAX	$	201,075		$	30,817		$	1,920			$	233,812
Equity method investment	$	—		$	1,100		$	—			$	1,100
Capital expenditures	700,953			61,807			—				762,760
Total assets at period end	935,719			437,721			(15,610		)		1,357,830

_________________

(1) Includes $3,316 for elimination of intercompany deferred revenue resulting from the adoption of ASC 606.

NOTE 27 — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

We determined for 2018 reporting that it was not probable that we would have the necessary capital to develop our PUD reserves. Thus, we have concluded that we do not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our available drilling locations.

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The unaudited reserve and other information presented below is provided as supplemental information.  The information presented during the 2018 Predecessor Period includes amounts related to discontinued operations.

Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Reserve estimates incorporate assumptions regarding future prices and costs at the date estimates are made. Actual future prices and costs may be materially higher or lower. Actual future net revenue will also be affected by factors such as actual production, supply and demand for oil and gas, curtailments or increases in consumption by gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.

Oil and gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

Estimated Quantities of Proved Reserves

The following table sets forth our net proved reserves as of December 31, 2019 and 2018 and February 8, 2018, and the changes therein during the periods then ended.

	Oil (Mbbls)		Gas (MMcf)		NGL’s (Mbbls)		Boe (Mbbls)
Total Proved Reserves:
Balance at December 31, 2017 (Predecessor)	73,518		433,519		36,887		182,658
Production	(521	)	(1,984	)	(161	)	(1,012	)
Sales of reserves in place (1)	(1,667	)	(24,239	)	(771	)	(6,478	)
Revisions of previous quantity estimates and other	375		3,506		289		1,248
Balance at February 8, 2018 (Predecessor)	71,705		410,802		36,244		176,416
Production(2)	(5,053	)	(16,913	)	(2,268	)	(10,140	)
Purchases in place(2)	2,658		13,331		1,751		6,631
Discoveries and extensions(2)	30,026		155,306		19,646		75,557
Revisions of previous quantity estimates and other(2)	(74,064	)	(418,378	)	(35,581	)	(179,375	)
Balance at December 31, 2018 (Successor)	25,272		144,148		19,792		69,089
Production	(5,885	)	(24,802	)	(2,760	)	(12,779	)
Discoveries and extensions	4,265		24,351		2,835		11,159
Revisions of previous quantity estimates and other(3)	(6,736	)	(29,254	)	(9,352	)	(20,964	)
Balance at December 31, 2019 (Successor)	16,916		114,443		10,515		46,505
Proved Developed Reserves:
Balance at December 31, 2017	20,347		150,183		12,180		57,557
Balance at February 8, 2018	19,345		126,231		11,348		51,731
Balance at December 31, 2018	25,272		144,148		19,792		69,089
Balance at December 31, 2019	16,916		114,443		10,515		46,505
Proved Undeveloped Reserves:
Balance at December 31, 2017	53,171		283,336		24,707		125,101
Balance at February 8, 2018	52,360		284,571		24,896		124,685
Balance at December 31, 2018	—		—		—		—
Balance at December 31, 2019	—		—		—		—

_________________

(1) Sales of reserves in place during the 2018 Predecessor Period represent amounts related to our non-STACK properties that were distributed to High Mesa and are classified as discontinued operations in our financial statements.

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(2) An analysis of changes in our reserves from February 8, 2018 to December 31, 2018 follows:

	MBoe
Description	Proved Developed Reserves		Proved Undeveloped Reserves		Total
Balance at February 8, 2018	51,731		124,685		176,416
Production	(10,140	)	—		(10,140	)
Purchases in place, discoveries and extensions	35,096		47,092		82,188
Revisions of previous quantity estimates and other:
Lower estimated recoveries identified as a result of 2018 drilling program	(31,964	)	(69,534	)	(101,498	)
Higher average commodity prices in Successor Period compared to 2017	5,367		5,829		11,196
Transfers of PUDs to proved developed reserves	18,999		(18,999	)	—
Derecognition of PUDs due to significant concerns about ability to fund development of those reserves	—		(89,073	)	(89,073	)
Balance at December 31, 2018	69,089		—		69,089

(3) Revisions decreased our estimated recovery of proved reserves and is ratably due to lower average commodity prices in 2019 as compared to 2018, the decision to report ethane rejection rather than ethane recovery, and decreases in volume estimates based on the overall performance of our wells.

Results of Operations for Oil and Gas Producing Activities - Upstream Segment

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Operating revenue	$	423,576		$	414,507		$	40,136
Production expense (1)	232,212			247,748			30,743
Depreciation, depletion and amortization	120,617			133,554			11,670
Exploration expense	52,354			34,085			7,003
Impairment expense	556,427			2,033,712			—
Income tax expense (benefit)	—			4			—
Results of operations	$	(538,034	)	$	(2,034,596	)	$	(9,280	)

_________________

(1) Production expense consists of direct lease operating expense, transportation and marketing expense, production taxes, workover expense and allocated general and administrative expense.

Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
(in thousands)	2019			2018
Capitalized costs:
Proved properties	$	2,239,444		$	2,110,346
Unproved properties	813,310			816,282
Total	3,052,754			2,926,628
Accumulated depreciation, depletion, amortization and impairment	(2,837,402		)	(2,163,291		)
Net capitalized costs	$	215,352		$	763,337

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Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities

Acquisition costs in the table below include costs incurred to purchase, lease or otherwise acquire property. Exploration expenses include additions to exploratory wells and other exploration expenses, such as geological and geophysical costs. Development costs include drilling and completion costs plus additions to production facilities and equipment.

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Costs incurred during the period: (1)
Property acquisition
Unproved (2)	$	—	$	54,587	$	4,240
Proved	—		16,300		327
Exploration	7,305		32,130		3,678
Development (3)	134,908		664,138		37,672
	$	142,213	$	767,155	$	45,917

_________________

(1) Costs incurred in the 2018 Predecessor Period include amounts related to non-STACK oil and gas assets, which were distributed in connection with the Business Combination.

(2) Property acquisition costs for unproved properties include the acquisition of unevaluated leasehold portion from an unaffiliated third party of approximately $22.3 million for the 2018 Successor Period.

(3) Includes asset retirement additions (revisions) of $0.9 million and $5.6 million for the 2019 and the 2018 Successor Period, respectively. For the 2018 Predecessor Period, there were no material asset retirement additions (revisions).

Standardized Measure of Discounted Future Net Cash Flows

The following information utilizes reserve and production data prepared by us. Future cash inflows were calculated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month, for the year ended December 31, 2019, the 2018 Successor Period, and for the 2018 Predecessor Period. Well costs, operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. 

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The following table sets forth the components of the standardized measure of discounted future net cash flows:

	Successor						Predecessor
(in thousands, except per unit data)	December 31, 2019			December 31, 2018			February 8, 2018
Future cash inflows	$	1,326,490		$	2,446,888		$	5,798,886
Future production costs	(825,300		)	(1,214,479		)	(2,556,361		)
Future development costs	(25,251		)	(23,183		)	(965,780		)
Future income taxes	(26,707		)	(146,632		)	—
Future net cash flows(1)	449,232			1,062,594			2,276,745
Discount to present value at 10 percent per annum	(122,321		)	(348,311		)	(1,096,859		)
Standardized measure of discounted future net cash flows	$	326,911		$	714,283		$	1,179,886
Base price for crude oil, per barrel, in the above computation	$	55.69		$	65.56		$	52.89
Base price for gas, per Mcf, in the above computation	$	2.58		$	3.10		$	2.99
Realized price for NGLs, per barrel, in the above computation	$	14.60		$	22.44		$	27.48

Changes in Standardized Measure of Discounted Future Net Cash Flows

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Balance at beginning of period	$	714,283		$	1,179,886		$	1,105,922
Sales and transfers of oil and gas produced, net of production costs	(253,582		)	(278,091		)	(30,391		)
Net changes in prices and production costs	(270,712		)	38,963			71,334
Revisions of previous quantity estimates	(129,305		)	(1,120,097		)	10,887
Purchases of reserves in-place	—			24,376			—
Sales of reserves in-place(1)	—			—			(4,807		)
Current year discoveries and extensions, less related costs	134,451			684,700			—
Changes in estimated future development costs	473			(39,069		)	491
Development costs incurred during the period	84			160,583			—
Accretion of discount	81,285			117,989			110,592
Net change in income taxes	79,134			(98,568		)	—
Change in production rate (timing) and other	(29,200		)	43,611			(84,142		)
Net change	(387,372		)	(465,603		)	73,964
Balance at end of period	$	326,911		$	714,283		$	1,179,886

_________________

(1) The sale of reserves in-place during the 2018 Predecessor Period includes the sale of non-STACK properties.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. 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.

We have concluded that our disclosure controls and procedures were effective as of December 31, 2019.

Management’s Annual Report on Internal Control Over Financial Reporting

Under the Exchange Act, our management is responsible for establishing and maintaining adequate internal control over financial reporting (“ICFR”). Our ICFR should be designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP and includes those policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company’s transactions and dispositions of its assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures are being made only in accordance with authorizations of management and directors; and

• provide reasonable assurance to prevent or timely detect unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.

As of December 31, 2019, management, including our principal executive officer and principal financial officer, and under the oversight of the Board of Directors, conducted an assessment of the effectiveness of our ICFR based upon the framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013) (COSO 2013).

Company Changes in ICFR in Response to Deficiencies Reported as of December 31, 2018

As disclosed in Part II Item 9A. Controls and Procedures in our Annual Report on Form 10-K for the year ended December 31, 2018, we concluded that our disclosure controls and procedures were not effective due to the existence of material weaknesses in our ICFR. Material weakness describes a deficiency, or a combination of deficiencies, in ICFR, such that there is a reasonable possibility that a material misstatement of the financial statements will not be prevented or detected on a timely basis.

During 2019, we implemented our remediations to address these material weaknesses, including by:

• Adding to our senior management team with seasoned experience in performing risk assessments of ICFR in complex accounting and operating environments and implementing internal control in response to identified risks, which includes our chief financial officer and chief accounting officer. Each has a strong background in oil and gas accounting and managing sophisticated internal control assessments, including oversight of outside advisors.

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• Improving the cross-functional nature of our internal control environment by embedding ICFR at all levels and across finance and other departments which allowed us to better distribute accountability for ICFR. We provided GAAP and internal controls training to our employees with responsibilities for ICFR to improve internal control. As described above, we hired key finance and accounting positions during 2019 and we retained outside resources to supplement our employees with respect to complex accounting and financial reporting areas and improved our supervision of outside resources. We enhanced our documentation of procedures which resulted in a better understanding of roles and responsibilities for ICFR.

• Engaging outside resources to assist with the design and implementation of a risk-based internal controls plan that aligns to and is measured against the COSO 2013 Framework. We used outside resources to assist our employees in business process documentation and ICFR design. Additionally, outside resources provided broad training and assisted with management's self-assessment and testing of internal controls. Due to the timing of the completion of our Annual Report for 2018, the addition of senior financial and accounting personnel and the improvements in our ICFR design, we were not able to perform rigorous interim testing of our 2019 control environment until the third quarter; therefore, our testing was performed primarily in the third and fourth quarters.

• Performing a cross-functional enterprise risk assessment involving the executive management and all departments to adequately identify, analyze and determine how we will respond to our business operations, changes to them and the impact on financial reporting, including on ICFR. Our filing for bankruptcy protection in the third quarter restricted our ability to respond to a portion of our identified risks. Accordingly, we became subject to new risks associated with our bankruptcy filing, and we added employees and advisors knowledgeable in the bankruptcy process and communicated timely to those responsible for financial reporting, ICFR and those charged with governance regarding those risks.

• Revising our processes, such as operating and capital accruals, or improving our controls over the use of spreadsheets used for impairment expense, depreciation, depletion and amortization expense, and determination of non-controlling interest among other accounts, such that access is restricted to appropriate personnel, that changes to data or formulas are authorized and appropriate, and that the spreadsheets are adequately reviewed by someone other than the preparer. As reported in the third quarter 2019 Form 10-Q, we satisfactorily completed testing of changes to access controls for payroll, production accounting and reserves systems to remediate material weaknesses identified during 2018 in those areas.

• Addressing deficiencies in our financial reporting close process activities and related controls by proactively planning our response to accounting and disclosure requirements which allowed us to more fully develop disclosures and vet issues, implementing more robust review procedures of complex accounting and disclosure requirements, timely communicating requirements for financial disclosure as a result of the bankruptcy, and implementing reconciliation procedures and checklists to monitor completion of key processes and controls.

• Deploying enhanced management review controls, performed by experienced employees, over complex accounting estimates at an appropriate level of precision to reduce the risk of an undetected material misstatement. We improved the controls over the completeness and accuracy of data and assumptions used in these accounting estimates, and where outside resources were used, improved our supervision of those resources.

Except for the remediation of the material weaknesses in internal control identified during the year ended December 31, 2018, there were no other changes in our ICFR during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information required as to Item 10 will be set forth in the 2020 Proxy Statement for the Annual Meeting and is incorporated herein by reference. Except as otherwise specifically incorporated by reference, our 2020 Proxy Statement is not deemed to be filed as part of this Annual Report.

Item 11. Executive Compensation

Information required as to Item 11 will be set forth in the 2020 Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required as to Item 12 will be set forth in the 2020 Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required as to Item 13 will be set forth in the 2020 Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 14.  Principal Accountant Fees and Services

KPMG LLP served as the Company’s independent auditor during 2019 and 2018.

Aggregate fees for professional services rendered to the Company by KPMG LLP were:

	Year Ended December 31, 2019		Year Ended December 31, 2018
Audit fees	$	1,900,000	$	2,966,500
Audit-related fees	—		359,000
Tax fees	—		—
All other fees	—		—
Total	$	1,900,000	$	3,325,500

Audit Fees. Audit fees are primarily for the audit of the Company’s consolidated financial statements included in the Annual Report on Form 10-K and reviews of the Company’s consolidated financial statements included in the Quarterly Reports on Form 10-Q. For the year ended December 31, 2018, KPMG also conducted an audit of the effectiveness of the Company’s internal control over financial reporting.

Audit-Related Fees. Audit-related fees were incurred for accounting consultation regarding certain transactions that occurred during the year ended December 31, 2018.

Tax Fees. KPMG did not provide income tax compliance, planning and advisory services to us during the years ended December 31, 2019 and 2018.

All Other Fees. KPMG did not provide any “other services” as the Company’s independent auditor during the years ended December 31, 2019 and 2018. Alta Mesa did pay KPMG LLP $162,670 for services on a state escheatment project covering the period from January 2017 through May 2018, but that contract was cancelled prior to engaging KPMG LLP as our independent auditor.

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Pre-Approval Policy

Since the Business Combination, the Audit Committee of the Board of Directors approved all services to be provided by KPMG LLP.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are filed as part of this Annual Report or incorporated by reference:

1. The Consolidated Financial Statements of Alta Mesa Resources, Inc. are listed on the Index to Financial Statements in Item 8.

2. Financial Statement Schedules:

(i) All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto.

3. Exhibits:

2.1	Contribution Agreement, dated as of August 16, 2017, among High Mesa Holdings, LP, High Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, the Registrant and the Contributor Owners party thereto (incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K filed with the SEC on August 17, 2017).
2.2	Contribution Agreement, dated as of August 16, 2017, among KFM Holdco, LLC, Kingfisher Midstream, LLC, the Registrant and the Contributor Members party thereto (incorporated by reference to Exhibit 2.2 of the Registrant’s Form 8-K filed with the SEC on August 17, 2017).
2.3	Contribution Agreement, dated as of August 16, 2017, between Riverstone VI Alta Mesa Holdings, L.P. and the Registrant (incorporated by reference to Exhibit 2.3 of the Registrant’s Current Report on Form 8-K filed with the SEC on August 17, 2017).
3.1	Second Amended and Restated Certificate of Incorporation of Alta Mesa Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
3.2	Certificate of Designations of Series A Preferred Stock of Alta Mesa Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
3.3	Certificate of Designation of Series B Preferred Stock of Alta Mesa Resources, Inc. (incorporated by reference to Exhibit 3.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
3.4	Bylaws of Alta Mesa Resources, Inc. (incorporated by reference to the Registrant’s Registration Statement on Form S-1 filed with the SEC on (Registration No. 333-216409) filed with the SEC on March 2, 2017).
3.5	Amended and Restated Agreement of Limited Partnership of SRII Opco, LP, dated February 9, 2018 (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
4.1	Specimen Class A Common Stock Certificate (incorporated by reference to Exhibit 4.2 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-216409) filed with the SEC on March 2, 2017).
4.2	Specimen Warrant Certificate (incorporated by reference to Exhibit 4.3 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-216409) filed with the SEC on March 2, 2017).
4.3	Warrant Agreement between the Registrant and Continental Stock Transfer & Trust Company, as warrant agent (incorporated by reference to Exhibit 4.4 of the Registrant’s Current Report on Form 8-K filed with the SEC on March 29, 2017).
4.4	Registration Rights Agreement, dated March 23, 2017, among the Registrant, Silver Run Sponsor II, LLC and certain other security holders named therein (incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed with the SEC on March 29, 2017).
4.5	Registration Rights Agreement, dated as of February 9, 2018, by and among Alta Mesa Resources, Inc., High Mesa Holdings, L.P., KFM Holdco, LLC and Riverstone VI Alta Mesa Holdings, L.P. (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
4.6	Amendment No. 1 to Registration Rights Agreement, dated as of February 9, 2018, by and among Alta Mesa Resources, Inc., Silver Run Sponsor II, L.L.C., and the other holders party thereto (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).

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4.7	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 to 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).
4.8	Description of Alta Mesa Resources, Inc’s Securities (incorporated by reference to exhibit 4.8 to the Registrant’s Annual Report on Form 10-K filed with the SEC on August 2, 2019).
4.9*	Amended and Restated Purchase and Sale Agreement by and among Kingfisher Midstream, LLC, Oklahoma Produced Water Solutions, LLC, Kingfisher STACK Oil Pipeline, LLC and Cimarron Express Pipeline, LLC and BCE-Mach III LLC, dated January 17, 2020.
4.10*	Amended and Restated Purchase and Sale Agreement by and among Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp., Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP and BCE-Mach III LLC and, with respect to certain provisions, Alta Mesa Resources, Inc., dated as of January 17, 2020.
10.1	Eighth Amended and Restated Credit Agreement dated as of February 9, 2018 among Alta Mesa Holdings, LP, the lenders party hereto from time to time, and Wells Fargo Bank, National Association, as administrative agent for such Lenders (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.2	Master Assignment, Increase Agreement and Amendment No. 1 to Credit Agreement dated as of May 14, 2018 to the Eighth Amended and Restated Credit Agreement dated as of February 9, 2018, among Alta Mesa Holdings, LP, as borrower, Wells Fargo Bank, National Association, as administrative agent for the Lenders and as issuing lender, the Lenders listed therein and Barclays Bank PLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on November 14, 2018).
10.3	Amendment No. 2 to Credit Agreement dated as of August 13, 2018 to the Eighth Amended and Restated Credit Agreement dated as of February 9, 2018, among Alta Mesa Holdings, LP, as borrower, Wells Fargo Bank, National Association, as administrative agent for the Lenders and as issuing lender and the Lenders listed therein (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on November 14, 2018).
10.4	Amendment No. 3 to Credit Agreement dated as of December 5, 2018 but effective as of February 9, 2018, to the Eighth Amended and Restated Credit Agreement dated as of February 9, 2018, among Alta Mesa Holdings, LP, as borrower, Wells Fargo Bank, National Association, as administrative agent for the Lenders and as issuing lender and the Lenders listed therein (incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K filed with the SEC on August 27, 2019).
10.5	Amended and Restated Credit Agreement, dated May 30, 2018, by and among Kingfisher Midstream, LLC, as borrower, Wells Fargo Bank, N.A., as successor administrative agent and LC issuer, and ABN AMRO Capital USA LLC, as resigning administrative agent, the LC issuers listed therein, the Lenders listed therein and the Exiting lenders listed therein (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 31, 2018).
10.6	First Amendment and Limited Waiver to Amended and Restated Credit Agreement dated as of April 29, 2019, among Kingfisher Midstream, LLC, each of the lenders that is a signatory thereto, and Wells Fargo Bank, N.A., as administrative agent and an issuer of letters of credit, to that certain Amended and Restated Credit Agreement dated as of May 30, 2018 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 1, 2019).
10.7	Letter Agreement, dated as of February 9, 2018, by and between the Registrant and James T. Hackett (incorporated by reference to Exhibit 10.12 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.8	Amended and Restated Consulting Agreement, dated September 10, 2019, by and among Alta Mesa Services, LP, Meridian Energy LLC, Randy Limbacher, John H. Campbell and Mark P. Castiglione (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on September 12, 2019).
10.9	Employment Agreement, dated as of January 7, 2019, by and between Alta Mesa Services, LP and John C. Regan (incorporated by reference to Exhibit 10.8 to the Registrant’s Annual Report on Form 10-K filed with the SEC on August 27, 2019).
10.10	Employment Agreement, dated as of April 9, 2018, by and between Alta Mesa Services LP and Kimberly O. Warnica (incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K filed with the SEC on August 27, 2019).
10.11	Separation Agreement by and between Alta Mesa Services, LP and Craig W. Collins, dated March 26, 2019 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 28, 2019).

100

10.12	Separation Agreement, by and between Alta Mesa Services, LP and Ronald J. Smith, dated July 2, 2019 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on July 8, 2019).
10.13	Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (incorporated by reference to Exhibit 10.19 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.14	Form of Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on August 15, 2018).
10.15	Form 2019 Incentive Program Letter Agreement (incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed with the SEC on March 28, 2019).
10.16	Form of Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan Officer Stock Option Award Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on August 15, 2018).
10.17	Form of Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan Performance-Based Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on August 15, 2018).
10.18	Tax Receivable Agreement, dated as of February 9, 2018, by and among the Registrant, SRII Opco, LP, Riverstone VI Alta Mesa, L.P., and High Mesa Holdings LP (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.19	Restrictive Covenant Agreement, dated February 9, 2018, by and between the Registrant and Asset Risk Management, LLC (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.20	Form of Indemnity Agreement (incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.21	Form of Amendment No. 1 to the Indemnity Agreement (incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.22	Management Services Agreement, dated February 9, 2018, by and between Alta Mesa Holdings, LP and High Mesa, Inc. (incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.23	Amended and Restated Voting Agreement, by and among Alta Mesa Holdings GP, LLC, BCE-AMH Holdings, LLC, BCE-MESA Holdings, LLC, Mezzanine Partners II Delaware Subsidiary, LLC, Offshore Mezzanine Partners Master Fund II, L.P., Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., The Northwestern Mutual Life Insurance Company, The Northwestern Mutual Life Insurance Company For its Group Annuity Separate Account, Northwestern Mutual Capital Strategic Equity Fund III, LP, KCK-AMIH, Ltd., United Insurance Company of America, Jade Real Assets Fund, Michael E. Ellis, Harlan H. Chappelle and SRII Opco, LP, dated as of February 9, 2018 (incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.24*	Summary of Alta Mesa Resources, Inc. Director Compensation Program
10.25	Private Placement Warrants Purchase Agreement, dated March 23, 2017, between the Registrant and Silver Run Sponsor II, LLC (incorporated by reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K filed with the SEC on March 29, 2017).
10.26	Forward Purchase Agreement, dated as of March 17, 2017, between the Registrant and Riverstone VI SR II Holdings, L.P. (incorporated by reference to Exhibit 10.9 of the Registrant’s Registration Statement on Form S-1/A (Registration No. 333-216409) filed with the SEC on March 17, 2017).
21.1*	Subsidiaries of the Registrant.

101

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).
99.1*	Audit Letter by Ryder Scott Company, L. P. Oklahoma Properties (SEC parameters), dated February 4, 2020
101*	Inline Interactive data files.
104*	Cover page Inline interactive data file
* filed herewith.

Item 16. Form 10-K Summary

None.

102

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		ALTA MESA RESOURCES, INC.
		(Registrant)
By:	/s/ Curtis M. Emerson
	Curtis M. Emerson
	Vice President and Chief Accounting Officer (Principal Accounting Officer)
Dated:	March 5, 2020

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 5, 2020 by the following persons on behalf of the registrant and in the capacities indicated.

	Signature	Title
By:	/s/ Mark P. Castiglione	Chief Executive Officer (Principal Executive Officer)
	Mark P. Castiglione
By:	/s/ John C. Regan	Executive Vice President, Chief Financial Officer and Assistant Secretary (Principal Financial Officer)
	John C. Regan
By:	/s/ James T. Hackett	Chairman of the Board and Director
	James T. Hackett
By:	/s/ Donald R. Dimitrievich	Director
	Donald R. Dimitrievich
By:	/s/ William W. McMullen	Director
	William W. McMullen
By:	/s/ Pierre F. Lapeyre, Jr.	Director
	Pierre F. Lapeyre, Jr.
By:	/s/ Jeffrey H. Tepper	Director
	Jeffrey H. Tepper
By:	/s/ Diana J. Walters	Director
	Diana J. Walters
By:	/s/ Sylvia J. Kerrigan	Director
	Sylvia J. Kerrigan
By:	/s/ David M. Leuschen	Director
	David M. Leuschen
By:	/s/ Donald R. Sinclair	Director
	Donald R. Sinclair

103

EX-4.9

Exhibit 4.9

Execution Version

AMENDED AND RESTATED

PURCHASE AND SALE AGREEMENT

by and among

Kingfisher Midstream, LLC, Oklahoma Produced Water Solutions, LLC, Kingfisher STACK Oil Pipeline, LLC and Cimarron Express Pipeline, LLC

as Seller

and

BCE-Mach III LLC

as Buyer

dated January 17, 2020

TABLE OF CONTENTS

Page

ARTICLE I DEFINITIONS AND INTERPRETATION1

1.1 Defined Terms    1

1.2 References and Rules of Construction    17

ARTICLE II ASSET ACQUISITION18

2.1 Asset Acquisition    18

2.2 Excluded Assets    20

2.3 Revenues and Expenses    22

2.4 365 Contracts; Cure Costs    22

2.5 Consents for 365 Contracts and Purchased Rights of Way    24

ARTICLE III PURCHASE PRICE; DEPOSIT25

3.1 Purchase Price    25

3.2 Deposit    25

3.3 Adjustments to Purchase Price    25

3.4 Closing Settlement Statement; Final Settlement Statement    26

3.5 Disputes    28

3.6 Allocated Values    28

3.7 Withholding    28

ARTICLE IV ACCESS/DISCLAIMERS29

4.1 Access    29

i

4.2 Confidentiality    31

4.3 Disclaimers    31

ARTICLE V CASUALTIES; TRANSFER RESTRICTIONS32

5.1 Casualty or Condemnation Loss    32

5.2 Consents to Assign    33

ARTICLE VI [RESERVED]35

ARTICLE VII REPRESENTATIONS AND WARRANTIES OF SELLER35

7.1 Organization, Existence    35

7.2 Authorization    35

7.3 No Conflicts    35

7.4 Consents    36

7.5 Foreign Person    36

7.6 Claims and Litigation    36

7.7 Material Contracts    36

7.8 No Violation of Laws    37

7.9 Preferential Purchase Rights    37

7.10 Current Commitments    37

7.11 Asset Taxes    37

7.12 Brokers’ Fees    38

7.13 Bonds and Credit Support    38

7.14 Pipeline Imbalances    38

7.15 Owned Real Property; Rights of Way    38

7.16 Insurance    39

7.17 Personal Property    39

7.18 Permits    39

7.19 Environmental Matters    40

7.20 FCC Matters    40

7.21 Labor and Employment    41

7.22 Benefit Plans    41

ARTICLE VIII BUYER REPRESENTATIONS AND WARRANTIES41

8.1 Organization; Existence    41

8.2 Authorization    41

8.3 No Conflicts    42

8.4 Consents    42

8.5 Bankruptcy    42

8.6 Claims and Litigation    42

8.7 Regulatory    42

8.8 Financing    43

8.9 Independent Evaluation    43

8.10 Brokers’ Fees    43

8.11 Accredited Investor    43

ARTICLE IX CERTAIN AGREEMENTS44

9.1 Conduct of Business    44

9.2 Bonds    45

9.3 Notifications    46

9.4 RESERVED    46

9.5 Equitable and Other Remedies    46

9.6 Record Retention    46

9.7 Permits; Operatorship    46

9.8 HSR Act    47

9.9 Bankruptcy Court Approval; Bidding Procedures    47

9.10 Bankruptcy Proceedings    48

9.11 Certain Litigation Matters    49

9.12 RESERVED    49

9.13 Financing    49

9.14 Material Contracts    52

ARTICLE X BUYER’S CONDITIONS TO CLOSING52

10.1 Representations    52

10.2 Performance    53

10.3 No Legal Proceedings    53

10.4 Casualty Losses; Consents    53

10.5 Certificate    53

10.6 HSR Act    53

10.7 Closing Deliverables    53

10.8 Sale Order    53

10.9 Closing of Transactions under AMH Agreement    53

ARTICLE XI SELLER’S CONDITIONS TO CLOSING53

11.1 Representations    53

11.2 Performance    54

11.3 No Legal Proceedings    54

11.4 Casualty Losses; Consents    54

11.5 Certificate    54

11.6 Sale Order    54

11.7 HSR Act    54

11.8 Closing Deliverables    54

11.9 Closing of Transactions under AMH Agreement    54

ARTICLE XII CLOSING54

12.1 Date of Closing    54

12.2 Place of Closing    55

12.3 Closing Obligations    55

12.4 Records    55

12.5 FCC Filings    56

ARTICLE XIII ASSUMPTION; INDEMNIFICATION; SURVIVAL56

13.1 Assumed Obligations; Excluded Obligations    56

13.2 Indemnities of Buyer    58

13.3 Express Negligence    59

13.4 Exclusive Remedy    59

13.5 Indemnification Procedures    59

13.6 Survival    61

13.7 Non-Compensatory Damages    61

13.8 Waiver or Right to Rescission    62

13.9 Insurance    62

13.10 Waiver of Consumer Rights    62

ARTICLE XIV TERMINATION, DEFAULT AND REMEDIES63

14.1 Right of Termination    63

14.2 Effect of Termination    65

14.3 Return of Documentation and Confidentiality    66

ARTICLE XV EMPLOYEES67

15.1 Business Employees    67

15.2 Employee Matters    67

ARTICLE XVI MISCELLANEOUS68

16.1 Exhibits and Schedules    68

16.2 Expenses and Taxes    68

16.3 Value Allocations for Tax Purposes    69

16.4 Assignment; Liquidating Trust    70

16.5 Preparation of Agreement    70

16.6 Publicity; Disclosure of Agreement and Transaction    70

16.7 Notices    71

16.8 Further Cooperation    72

16.9 Filings, Notices and Certain Governmental Approvals    72

16.10 Entire Agreement; Conflicts    73

16.11 Successors and Permitted Assigns    73

16.12 Parties in Interest    73

16.13 Amendment    74

16.14 Waiver; Rights Cumulative    74

16.15 Governing Law; Jurisdiction; Venue; Jury Waiver    74

16.16 Severability    76

16.17 Removal of Name    76

16.18 Counterparts    76

16.19 Time is of the Essence    76

16.20 No Recourse    77

16.21 No Recourse to Financing Sources    77

LIST OF EXHIBITS

EXHIBITS:
Exhibit A	Form of Assignment and Bill of Sale
Exhibit B	Form of Deed
Exhibit C	Form of ROW Assignment Agreement
Exhibit D	Sale Area
Exhibit E	Gathering Systems
Exhibit F	Purchased Rights of Way
Exhibit G	Personal Property
Exhibit H	Disposal Wells
Exhibit I	Vehicles
Exhibit J	FCC Licenses
Exhibit K	Excluded Assets
Exhibit L	RESERVED
Exhibit M	Form of Sale Order
Exhibit N	Form of Release and Exculpation
Exhibit O	Form of Escrow Agreement

LIST OF SCHEDULES

SCHEDULES:
Schedule 1.1	Gathering Agreements
Schedule 1.1(a)	RESERVED
Schedule 1.1(b)	Permitted Encumbrances
Schedule 2.4(b)	365 Schedule
Schedule 3.6	Allocated Values
Schedule 7.3	No Conflicts
Schedule 7.4	Seller Consents
Schedule 7.6	Litigation
Schedule 7.7(a)	Material Contracts
Schedule 7.7(b)	Material Defaults
Schedule 7.8	Violation of Laws
Schedule 7.9	Preferential Purchase Rights
Schedule 7.10	Current Commitments
Schedule 7.11	Asset Taxes
Schedule 7.13	Bonds and Credit Support
Schedule 7.14	Pipeline Imbalances
Schedule 7.15(a)	Owned Real Property
Schedule 7.15(c)	ROW Interests
Schedule 7.15(e)	Scheduled ROW Interests – Gaps
Schedule 7.16	Insurance
Schedule 7.19(a)	Environmental Matters
Schedule 7.20	Applicable FCC Licenses
Schedule 8.4	Buyer Consents
Schedule 9.1	Conduct of Business
Schedule 15.1	Business Employees

AMENDED AND RESTATED PURCHASE AND SALE AGREEMENT

This AMENDED AND RESTATED PURCHASE AND SALE AGREEMENT (as the same may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is entered into this 17th day of January, 2020 (the “A&R Execution Date”), by and among Kingfisher Midstream, LLC, a Delaware limited liability company (“KFM”), Oklahoma Produced Water Solutions, LLC, a Delaware limited liability company (“OPWS”), Kingfisher STACK Oil Pipeline, LLC, a Delaware limited liability company (“KSOP”), and Cimarron Express Pipeline, LLC, a Delaware limited liability company (“CEP” and, together with KFM, OPWS and KSOP, collectively “Seller”), and BCE-Mach III LLC, a Delaware limited liability company (“Buyer”). Buyer and Seller may be referred to collectively as the “Parties” or individually as a “Party.”

Recitals

WHEREAS, the Parties entered into a purchase and sale agreement on December 31, 2019 (the “Execution Date”) for the sale of the Assets pursuant to section 363 of the Bankruptcy Code (the “Original Agreement”) upon the terms and conditions set forth therein, pursuant to which the Parties intended to effectuate the transactions contemplated by the Original Agreement;

WHEREAS, on January 12, 2020, Seller filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Chapter 11 Cases”);

WHEREAS, Seller conducted the Auction on January 15, 2020, and Buyer was designated the Successful Bidder for the Assets at the conclusion of the Auction;

WHEREAS, pursuant to Section 16.13 of the Original Agreement, the Parties desire to amend and restate the Original Agreement to, among other things, successfully incorporate certain amendments to the Original Agreement required by the activities and actions that took place at the Auction, and the Parties intend to effectuate the transactions contemplated by this Agreement pursuant to section 363 of the Bankruptcy Code; and

WHEREAS, effective as of the Effective Time, Seller desires to sell and convey, and Buyer desires to purchase and pay for, the Assets (as defined below) in accordance with the terms and conditions of this Agreement.

NOW, THEREFORE, for and in consideration of the mutual agreements herein contained, the benefits to be derived by each Party, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

ARTICLE IDEFINITIONS AND INTERPRETATION

1.1Defined Terms. Capitalized terms used herein and not otherwise defined shall have the meanings given such terms as set forth below in this Section 1.1:

“365 Contract” means all Applicable Contracts and other executory contracts and unexpired leases to which a Seller is a party that relate to the Assets, in each case that may be assumed by Seller pursuant to Section 365 of the Bankruptcy Code.

2“365 Schedule” has the meaning set forth in Section 2.4(b).

3“AAA” means the American Arbitration Association.

4“AAA Rules” means the Commercial Arbitration Rules of the AAA.

5“A&R Execution Date” has the meaning set forth in in the first paragraph herein.

6“Accounting Arbitrator” has the meaning set forth in Section 3.5.

7“Adjusted Purchase Price” has the meaning set forth in Section 3.3.

8“AFEs” has the meaning set forth in Section 7.10.

9“Affiliate” means, with respect to any Person, any other Person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, such Person. The concept of control, controlling or controlled as used in the aforesaid context means the possession, directly or indirectly, of the power to direct or cause the direction of the management, policies or action of another, whether through the ownership of voting securities, voting trust, by contract, or membership in management or in the group appointing or electing management or otherwise through formal or informal arrangements or business relationships.

10“Agreement” has the meaning set forth in the first paragraph herein.

11“Allocable Amount” has the meaning set forth in Section 16.3.

12“Allocated Value” has the meaning set forth in Section 3.6.

13“Allocation Schedule” has the meaning set forth in Section 16.3.

“AMH Agreement” means the Amended & Restated Purchase and Sale Agreement dated as of January 17, 2020, by and among Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp., Alta Mesa Services, LP Oklahoma Energy Acquisitions, LP and, for the limited purposes set forth therein, Alta Mesa Resources, Inc., on the one hand and Buyer, on the other hand.

“AMH Change” means an amendment of the AMH Agreement that has the effect of adversely and materially affecting the certainty or timing of closing of the AMH Agreement.

14“Applicable Contracts” means all Contracts, if any, to which a Seller is a party that relate to the Assets, including Contracts to the extent they are used by a Seller in the operation or development of the Assets, or any other Contracts by which the Assets are bound and that, subject to the other provisions of this Agreement, will be binding on Buyer after the Closing, including purchase and sale agreements; crude oil, condensate, and natural gas purchase and sale, gathering, transportation and marketing agreements; Hydrocarbon storage agreements; acreage dedication agreements; area of mutual interest agreements; operating agreements and balancing agreements; unitization agreements; processing agreements; surface use agreements; crossing agreements; water supply agreements; saltwater disposal agreements or other waste disposal agreements; facilities or equipment leases; letters of objection; letter agreements; and other similar contracts and agreements held by Seller, in each case, to the extent related to Seller’s right, title and interest in the Assets.

15“Applicable FCC Licenses” has the meaning set forth in Section 7.20.

16“Applicable Policies” has the meaning set forth in Section 7.16.

“Asset Credit Support” means any bonds, letters of credit, guarantees or other forms of credit support, if any, posted by Seller or its Affiliates with Governmental Authorities or other Third Parties and relating to the Assets.

17“Asset Taxes” has the meaning set forth in Section 16.2(c).

18“Assets” has the meaning set forth in Section 2.1.

19“Assigned Contracts” means the 365 Contracts assumed by a Seller and assigned to Buyer pursuant to Section 2.4 and all other Applicable Contracts that are not 365 Contracts (other than Excluded Contracts).

20“Assigned FCC Licenses” has the meaning set forth in Section 2.1(m).

21“Assignment” means the Assignment and Bill of Sale from Seller to Buyer, pertaining to the Assets (other than the Assets covered by Deeds and the ROW Assignment Agreements), substantially in the form attached to this Agreement as Exhibit A.

22“Assumed Obligations” has the meaning set forth in Section 13.1(a).

23“Auction” has the meaning set forth in the Bidding Procedures.

“Avoidance Action” means any claim, right or cause of action of any Seller arising under chapter 5 of the Bankruptcy Code and any analogous state or federal statutes and common law relating to the Assets, Assigned Contracts, and Assumed Obligations.

24“Backup Bidder” means the bidder for the Assets with the next-highest or otherwise second-best bid for the Assets as determined in accordance with the Bidding Procedures.

25“Back-up Termination Date” means the first to occur of (a) forty-five (45) days after the entry of the Sale Order and (b) consummation of the transaction with the Successful Bidder at the Auction.

26“Bankruptcy Code” means title 11 of the United States Code.

27“Bankruptcy Court” means the United States Bankruptcy Court for the Southern District of Texas.

“Benefit Plans” means (a) any bonus, incentive compensation, deferred compensation, pension, profit sharing, retirement, stock purchase, stock option, stock ownership, stock appreciation rights, restricted stock, phantom stock or stock-based, stock or cash award, deferred compensation, leave of absence, layoff, stay, vacation, day or dependent care, legal services, cafeteria, life, health, welfare, post-retirement, accident, disability or other insurance, severance, separation, retention, change of control, employment or other benefit or compensation plan, practice, policy, agreement or arrangement of any kind, whether written or oral, whether for the benefit of a single individual or more than one individual, and whether or not legally enforceable, and (b) any other “employee benefit plan” within the meaning of Section 3(3) of ERISA or any comparable provision of any other applicable Law existing on the Closing Date or prior thereto, in each case, that is established, sponsored, maintained, contributed to or required to be contributed to by Seller or any of its Affiliates, or any predecessor of any of the foregoing, or for which Seller or any of its Affiliates is a party, is subject or may have Liabilities, including with respect to any Business Employee.

28“Bidding Procedures” means the Bidding Procedures attached to the Supplemental Bidding Procedures Order as Exhibit 1.

29“Board of Directors” means, as to each Seller, the board of directors or board of managers of such Seller or such other governing body of such Seller performing similar functions as a board of directors or board of managers,

“Business Day” means any day other than Saturday or Sunday or a day on which banking institutions in Houston, Texas are authorized by Law to close.

30“Business Employee” means each employee of Seller or any of its Affiliates whose primary duties and responsibilities are associated with the operation of the Assets, each of whom is set forth on Schedule 15.1.

31“Buyer” has the meaning set forth in the first paragraph herein.

32“Buyer Non-Recourse Party” has the meaning set forth in Section 16.20(b).

33“Buyer Parties” means (a) Bayou City Energy Management LLC; (b) BCE-AMH Holdings, LLC; (c) BCE-AMR Holdings LLC; (d) BCE-MESA Holdings, LLC; (e) William W. McMullen; (f) Mark Stoner; (g) Andrew Koehler; (h) Mach Resources LLC; (i) BCE-Mach LLC; (j) BCE-Mach II LLC; and (k) with respect to each of the foregoing Persons or entities, such Person or Entities’ respective current and former equity holders, controlled subsidiaries, officers, directors, managers, principals, members, employees, agents, advisory board members, financial advisors, partners, attorneys, accountants, investment bankers, consultants, representatives, and other professionals, each in their capacity as such; provided that under no circumstances shall the Buyer Parties include any Excluded Persons and Entities.

34“Buyer Representatives” has the meaning set forth in Section 4.1(a).

35“Cash Collateral Order” means the order of the Bankruptcy Court (a) authorizing Seller to use the cash collateral of the prepetition lenders and (b) providing the prepetition lenders with adequate protection.

36“Casualty or Condemnation Loss” has the meaning set forth in Section 5.1(b).

37“CBA” has the meaning set forth in Section 7.7(a)(x).

38“CEP” has the meaning set forth in the first paragraph herein.

39“Chapter 11 Cases” has the meaning set forth in the Recitals.

40“Claim Notice” has the meaning set forth in Section 13.5(b).

41“Closing” has the meaning set forth in Section 12.1.

42“Closing Date” has the meaning set forth in Section 12.1.

43“Closing Settlement Statement” has the meaning set forth in Section 3.4(a).

44“COBRA” means the Consolidated Omnibus Budget Reconciliation Act of 1985, Part 6 of Subtitle B of Title I of ERISA, Section 4980B of the Code and any similar state Law.

“Code” means the Internal Revenue Code of 1986, as amended.

45“Commitment” means the commitment of the Commitment Parties pursuant to the Commitment Documentation.

46“Commitment Documentation” means (i) that certain commitment letter dated January 15, 2020 (as amended pursuant to amendments permitted pursuant to the terms thereof), from Bayou City Energy III, L.P. and BCE-Mach Holdings II, LLC to Buyer with respect to the AMH Agreement, (ii) that certain commitment letter dated January 15, 2020 (as amended pursuant to amendments permitted pursuant to the terms thereof), from Bayou City Energy III, L.P. and BCE-Mach Holdings II, LLC to Buyer with respect to this Agreement and (iii) that certain commitment letter from UBS AG, Stamford Branch and UBS Securities LLC to Buyer with respect to both the AMH Agreement and this Agreement, to provide at least the Required Amounts in debt and/or equity financing to Buyer in order to consummate the transactions contemplated by both the AMH Agreement and this Agreement.

47“Commitment Parties” means, collectively, Bayou City Energy III, L.P., BCE-Mach Holdings II, LLC, UBS AG, Stamford Branch and UBS Securities LLC.

“Confidentiality Agreement” means that certain Confidentiality Agreement dated October 1, 2019 by and between the Company (as defined therein) and BCE-Mach LLC.

48“Confirmation Order” means the order of the Bankruptcy Court confirming the Plan.

49“Consent” has the meaning set forth in Section 7.4.

50“Continuing Employee” has the meaning set forth in Section 15.1.

51“Continuing Employee Records” shall mean the following current employment and current personnel information with respect to each Continuing Employee, in each case, to the extent permitted by applicable Law: salary, wage grade, job function, variable compensation targets, performance documentation, and business and personal mailing addresses and telephone numbers, including as applicable, any applicable employment-related agreements, Family and Medical Leave Act (or similar) records and Forms I-9 (Employment Eligibility Verification) related to such Continuing Employee; provided that Continuing Employee Records shall not include any medical records.

52“Contract” means any contract or agreement, including all Hydrocarbon purchase and sale contracts, Hydrocarbon gathering or transportation contracts, processing agreements, marketing agreements, production handling agreements, compression agreements, equipment leases, and surface use agreements, but excluding, however, any easement, surface lease, right-of-way, Permit or other instrument, in each case, creating or evidencing any real property interests.

53“Cure Costs” has the meaning set forth in Section 2.4(a).

54“Customary Post Closing Consents” means the consents and approvals from Governmental Authorities for the assignment of the Assets to Buyer that are customarily and reasonably obtained after the assignment of properties similar to the Assets.

55“Debt Financing Related Parties” means the Debt Financing Sources and other lenders from time to time party to agreements related to the Commitment, their Affiliates and their and their Affiliates’ respective Representatives and their respective successors and permitted assigns.

56“Debt Financing Sources” means the lenders, arrangers and bookrunners (including the lenders) (or any of their Affiliates) party from time to time to the Commitment Documentation.

57“Debt Instrument” has the meaning set forth in Section 7.7(a)(iii).

58“Deed” means, collectively, one or more deeds without warranty (statutory, express or implied) substantially in the form attached hereto as Exhibit B, adapted as necessary to conform to local requirements to render such deeds effective and recordable, pertaining to any surface fee interests included in the Assets.

59“Deloitte” has the meaning set forth in Section 3.5.

60“Deposit” has the meaning set forth in Section 3.2(a).

61“Designation Deadline” means 5:00 p.m. (Central Time) on the date that is five (5) Business Days prior to the Target Closing Date, or such later date as Buyer and Seller shall mutually agree and, if applicable, as the Bankruptcy Court may authorize.

62“Disposal Wells” has the meaning set forth in Section 2.1(h).

“Dispute Notice” has the meaning set forth in Section 3.4(a).

63“DOJ” means the United States Department of Justice.

64“Effective Time” means 12:01 a.m. (Central Prevailing Time) on January 1, 2020.

65“Election Form” has the meaning set forth in Section 2.4(c).

66“Encumbrance” means all liens, whether consensual or statutory (including mechanic’s, materialman’s, carrier’s, repairer’s, contractor’s and other similar liens arising under applicable Laws), replacement liens, adequate protection liens or other liens granted under Sections 361, 363 or 364 of the Bankruptcy Code, mortgages, deeds of trust, hypothecations, pledges, security interests, charges, options and transfer restrictions, including without limitation, rights of first refusal or first offer, defect or objection liens, easements, encroachments or servitudes, in each case, that constitutes an “interest” for purposes of Bankruptcy Code § 363(f), including without limitation those charges or interests in property within the meaning of “lien” under Bankruptcy Code § 101(37) or any other limitation, restriction or interest that constitutes an “interest” for the purposes of Bankruptcy Code § 363(f).

67“Environmental Condition” means a condition that causes an Asset (or Seller with respect to an Asset) not to be in compliance with or subject to Liability under an Environmental Law. For the avoidance of doubt, (a) the fact that a pipe is temporarily not in use shall not form the basis of an Environmental Condition, and (b) except with respect to Personal Property (i) that causes or has caused contamination of soil, surface water or groundwater or (ii) the use or condition of which is a violation of Environmental Law, the physical condition of any surface or subsurface Personal Property, including water or oil tanks, separators or other ancillary equipment, shall not form the basis of an Environmental Condition.

68“Environmental Defect” means an Environmental Condition existing on the Execution Date or the Closing Date with respect to any Asset.

69“Environmental Laws” means any applicable Law relating to public or worker health or safety (regarding Hazardous Materials), pollution or the protection of the environment, including air, water, or land. The term “Environmental Laws” does not include good or desirable operating practices or standards that may be voluntarily employed or adopted by other oil and gas well operators or recommended, but not required, by a Governmental Authority.

70“Environmental Liability” means any Liability (a) resulting from or attributable to the actual or threatened Release of Hazardous Materials into the environment or resulting from or attributable to exposure to Hazardous Materials; (b) resulting from or attributable to the generation, manufacture, processing, distribution, use, treatment, storage, Release or threatened Release, transport, disposal or handling of Hazardous Materials; or (c) otherwise arising under or related to Environmental Laws or the violation thereof; provided that Environmental Liabilities shall not include Liabilities relating to or at any time arising out of the off-site transportation, disposal or arrangement therefor of any Hazardous Materials off the premises of the Assets prior to the Closing, or civil or criminal fines or penalties relating to violations occurring prior to the Closing Date of any Environmental Law with respect to the Assets or the operation thereof.

71“Environmental Permits” means all permits under any Environmental Law; provided, however, that Real Property Permits are expressly excluded from the term Environmental Permits.

72“ERISA” means the Employee Retirement Income Security Act of 1974.

73“ERISA Affiliate” means any Person that, together with Seller or any of its Affiliates, is (or at any relevant time has been or would be) treated as a single employer under Section 414 of the Code.

74“Escrow Account” means the account maintained by Escrow Agent in connection with the Escrow Agreement.

75“Escrow Agent” means Prime Clerk LLC.

76“Escrow Agreement” means that certain Escrow Agreement to be entered into by and among Buyer, Seller and Escrow Agent at Closing in substantially the form attached hereto as Exhibit O.

77“Excess Cure Costs” has the meaning set forth in Section 2.4(a).

78“Excluded Assets” has the meaning set forth in Section 2.2.

79“Excluded Contracts” means all 365 Contracts other than Assigned Contracts.

80“Excluded Liabilities” has the meaning set forth in Section 13.1(b).

“Excluded Persons and Entities” means each of (a) KFM Holdco, LLC, (b) High Mesa Inc. and all of its subsidiaries, (c) Alta Mesa Resources, Inc., and its subsidiaries, (d) Riverstone VI Alta Mesa Holdings, L.P. and any of its related Persons or Entities that would otherwise be included in the definition of Representatives (as defined in the Sale Order) of Buyer or the Buyer Parties, in their respective capacities as equity holders or Affiliates of Buyer or any of the Buyer Parties, or (e) HPS Investment Partners, LLC and any of its related Persons or Entities that would otherwise be included in the definition of Representatives (as defined in the Sale Order) of Buyer or the Buyer Parties, in their respective capacities as equity holders or Affiliates of Buyer or any of the Buyer Parties.

81“Execution Date” has the meaning set forth in the Recitals.

82“FCC” means the Federal Communications Commission.

83“FCC Licenses” means any licenses, permits, certificates, approvals, franchises, consents, waivers, registrations or other authorizations issued by the FCC.

84“Final Order” means any award, decision, decree, settlement, order, injunction, ruling, judgment, or consent of or entered, issued, made or rendered by any Governmental Authority as to which the time to file an appeal, a motion for rehearing or reconsideration or a petition for writ of certiorari has expired and no such appeal, motion or petition is pending.

85“Final Settlement Date” has the meaning set forth in Section 3.4(b).

86“Final Settlement Statement” has the meaning set forth in Section 3.4(b).

“Free and Clear” means free and clear of all claims, Encumbrances or Liabilities other than the Assumed Obligations and Permitted Encumbrances, in each case to the maximum extent permitted by Section 363(f) of the Bankruptcy Code.

“FTC” means the Federal Trade Commission.

87“GAAP” means generally accepted accounting principles as used in the United States of America.

88“Gathering Agreements” means those Hydrocarbon gathering, transportation and processing agreements and water and disposal agreements set forth on Schedule 1.1.

89“Gathering Systems” has the meaning set forth in Section 2.1(a).

90“Good and Defensible Title” means, as to each Gathering System and Owned Real Property, good and defensible title to such property by which Seller would be reasonably likely to successfully defend against any adverse claim made by a Third Party, and which, as of Closing, is free and clear of all Encumbrances other than Permitted Encumbrances.

“Governmental Authority” means any federal, state, county, city, local, municipal, tribal, foreign or other government; any governmental, quasi-governmental, regulatory or administrative agency, commission, department, board, bureau, body, official or other authority or instrumentality exercising or entitled to exercise any administrative, executive, judicial, legislative, regulatory or taxing authority or power; and any court, arbitral body (public or private) or other tribunal, including any tribal authority having or asserting jurisdiction with respect to the Assets.

91“Hazardous Materials” means any: (a) pollutants, contaminants, toxic or hazardous or extremely hazardous substances, materials, wastes, constituents, compounds, products or chemicals that are regulated by or included in the definition of “hazardous substance,” “hazardous material,” “hazardous waste,” “restricted hazardous waste,” “extremely hazardous waste,” “solid waste,” “toxic waste,” “extremely hazardous substance,” “chemical substance,” “toxic pollutant,” “contaminant” or “pollutant”, or may form the basis of liability under, any Environmental Laws; (b) Hydrocarbons, petroleum, petrochemical or petroleum products, petroleum substances, natural gas liquid, condensate, natural gas, crude oil or any components, fractionations or derivatives thereof or any mixtures containing any of the foregoing; (c) oil and gas exploration and production wastes, including produced and flow back waters; and (d) asbestos containing materials, mercury, polychlorinated biphenyls, mold, radioactive materials, urea formaldehyde foam insulation, or radon gas.

92“Highest or Best Proposal” shall mean any bona fide proposal or offer to or from a Person other than Buyer or its representatives with respect to (a) any plan of reorganization or liquidation, proposal, offer, dissolution, winding up, liquidation, reorganization, merger, consolidation, business combination, joint venture, partnership, sale of assets or equity interests or restructuring involving all or part of the Assets, or (b) any other direct or indirect acquisition or series of acquisitions involving all or part of the Assets, that, in each case, the independent manager of KFM has determined in good faith, after consultation with its outside financial advisors and outside legal counsel, would, if consummated, result in the highest or otherwise best transaction for Seller, taking into account all terms thereof, including (x) the likelihood and timing of consummation, and (y) all material legal, financial (including the financing terms of any such proposal), conditionality, regulatory and other aspects of such proposal.

93“HSR Act” means the Hart Scott Rodino Antitrust Improvements Act of 1976, as amended and the rules and regulations thereunder.

“Hydrocarbons” means oil, gas and other hydrocarbons (including casinghead gas and condensate) produced or processed in association therewith (whether or not such item is in liquid or gaseous form), including all crude oils, condensates and natural gas liquids at atmospheric pressure and all gaseous hydrocarbons (including wet gas, dry gas and residue gas) or any combination thereof, and sulphur, carbon dioxide and any other minerals extracted from, attributable to or produced in association therewith.

94“Indemnified Party” has the meaning set forth in Section 13.5(a).

95“Indemnifying Party” has the meaning set forth in Section 13.5(a).

96“Instruments of Conveyance” means, collectively, the Assignment, the Deed(s) and the ROW Assignment Agreements.

“Interim Period” means the period of time commencing with the Effective Time and ending immediately prior to Closing.

“KFM” has the meaning set forth in the first paragraph herein.

97“Knowledge” means, (a) with respect to Seller, the actual knowledge (without due investigation or inquiry) of the following Persons: John Regan, John Campbell, and Mark Castiglione, and (b) with respect to Buyer, the actual knowledge (without due investigation or inquiry) of the following Persons: Daniel T. Reineke, Jr. and Kevin White.

98“KSOP” has the meaning set forth in the first paragraph herein.

99“Law” means any applicable statute, law (including any obligation arising under the common law), rule, regulation, ordinance, order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Authority.

100“Liabilities” means any and all claims, causes of actions, payments, charges, judgments, assessments, losses, monetary damages, penalties, fines, fees, interest obligations, deficiencies, debts, obligations, costs and expenses and other liabilities (whether absolute, accrued, contingent, fixed or otherwise, or whether known or unknown, or due or to become due or otherwise), including any amounts paid in settlement, interest, court costs, costs of investigators, attorneys’ fees, legal or other expenses incurred in connection therewith.

101“Liquidating Trust” means a liquidating or similar trust as may be established with respect to Seller’s estate in conjunction with the Chapter 11 Cases.

102“Liquidating Trustee” means the trustees or other representative of the Liquidating Trust.

103“Material Adverse Effect” means, with respect to Seller, any change, inaccuracy, effect, event, result, occurrence, condition or fact (for the purposes of this definition, each, an event) (whether foreseeable or not and whether covered by insurance or not) that, individually or in the aggregate, has resulted or would reasonably be expected to result in, (1) a material adverse effect upon the ability of Seller to consummate the transactions contemplated by this Agreement, or to perform its obligations hereunder, or (2) a material adverse effect on the ownership, operation, financial condition or value of the Assets, taken as a whole, as currently owned and operated as of the Execution Date; provided, however, that Material Adverse Effect shall not include such material adverse effects resulting from: (a) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (b) changes in general market, economic, financial or political conditions (including changes in commodity prices, fuel supply or transportation markets, interest or rates, or general market prices in the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally) in the area in which the Assets are located, the United States or worldwide; (c) changes in conditions or developments generally applicable to the oil and gas industry in the area where the Assets are located; (d) acts of God, including hurricanes, storms or other naturally occurring events; (e) acts or failures to act of Governmental Authorities, except as a result of the action or inaction of Seller or its Affiliates; (f) civil unrest, any outbreak of disease or hostilities, terrorist activities or war or any similar disorder; (g) any actions taken or omitted to be taken by or at the written request or with the prior written consent of Buyer or required by the terms of this Agreement; (h) matters that are cured or no longer exist by the earlier of Closing and the termination of this Agreement, including matters to the extent a downward Purchase Price adjustment is provided for under this Agreement; (i) any change in Laws or in GAAP and any interpretations thereof from and after the Execution Date; (j) Casualty or Condemnation Losses; (k) the commencement or pendency of the Chapter 11 Case; (l) any objections in the Bankruptcy Court to (i) this Agreement and the other Transaction Documents and the transactions contemplated hereby and thereby, (ii) the reorganization of Seller and any related plan of reorganization or disclosure statement, (iii) the Bidding Procedures or the sale motion, or (iv) the assumption or rejection of a 365 Contract; (m) any order of the Bankruptcy Court (except any such order that would preclude or prohibit Seller from consummating the transactions contemplated by this Agreement) or any actions or omissions of Seller in compliance therewith; and (n) any of the matters disclosed on any Exhibit or Schedule to this Agreement.

104“Material Contracts” has the meaning set forth in Section 7.7.

105“New Commitment” has the meaning set forth in Section 9.13(a)(iv).

106“NORM” means naturally occurring radioactive material.

107“Offered Employees” has the meaning set forth in Section 15.1.

108“Operating Expenses” means all (a) operating expenses (including costs of insurance) and capital expenditures paid or payable to Third Parties incurred in the ownership and operation of the Assets in the ordinary course of business and, where applicable, under and pursuant to the relevant transportation, gathering, treating, or processing agreement, if any (in each case, to the extent the same is an Assigned Contract) and (b) all Third Party overhead; but excluding (in all cases) Liabilities attributable to (i) personal injury or death, property damage, torts, breach of contract or violation of any Law, (ii) obligations relating to the dismantling or decommissioning facilities and restoring the surface around such facilities, (iii) Environmental Liabilities (other than monitoring or other costs incurred in the ordinary course of business to maintain compliance with Environmental Laws or prevent an Environmental Condition or Environmental Liabilities), (iv) obligations with respect to Pipeline Imbalances, (v) obligations with respect to Taxes, (vi) amounts (if any) incurred to obtain any Required Consent, (vii) any amounts incurred to cure or attempt to cure any breaches of this Agreement or any Casualty or Condemnation Loss, (viii) any Cure Costs, and (ix) claims for indemnification or reimbursement from any Third Party with respect to costs of the types described in the preceding clauses (i) through (ix), whether such claims are made pursuant to contract or otherwise.

109“OPWS” has the meaning set forth in the first paragraph herein.

110“Original Agreement” has the meaning set forth in the Recitals.

111“Original Deposit” has the meaning set forth in Section 3.2(a).

112“Outside Termination Date” means April 15, 2020.

113“Owned Real Property” has the meaning set forth in Section 7.15(a).

114“Party” and “Parties” have the meanings set forth in the first paragraph herein.

115“PEPL” means Panhandle Eastern Pipe Line Company, LP.

“PEPL Contracts” means, collectively, the Applicable Contracts between Seller and PEPL or any Affiliate of PEPL.

116“Permits” means any permit, license, registration, consent, order, approval, variance, exemption, waiver, franchise, right or other authorization (in each case) of any Governmental Authority, excluding FCC Licenses.

117“Permitted Encumbrances” means:

(a)the terms and conditions of all Applicable Contracts that individually or in the aggregate do not prevent or materially impair the operation or use of the Assets as currently operated and used;

(b)Preferential Purchase Rights;

(c)liens for Taxes or assessments (i) (A) not yet due or delinquent, (B) the nonpayment of which is permitted or required by the Bankruptcy Code or (C) that if delinquent, are being contested in good faith by appropriate proceedings by or on behalf of Seller, (ii) are set forth on Schedule 1.1(b), or (iii) from which the Assets will be permanently and fully released pursuant to the Sale Order;

(d)any Consents (including Customary Post Closing Consents), and any required notices to, or filings with, Governmental Authorities in connection with the consummation of the transactions contemplated by this Agreement;

(e)all applicable Laws and all rights reserved to or vested in any Governmental Authority: (i) to control or regulate any Asset in any manner; (ii) by the terms of any right, power, franchise, grant, license or permit, or by any provision of Law, to terminate such right, power, franchise grant, license or permit or to purchase, condemn, expropriate or recapture or to designate a purchaser of any Asset; (iii) to use such property in a manner which does not materially impair the use of such property for the purposes for which it is currently owned and operated; or (iv) to enforce any obligations or duties affecting the Asset to any Governmental Authority with respect to any franchise, grant, license or permit;

(f)rights of a common owner of any interest in rights-of-way, permits or easements held by Seller and such common owner as tenants in common or through common ownership, in each case, to the extent the same does not prevent or materially impair the operation or use of the Assets subject thereto as currently operated and used;

(g)easements, conditions, covenants, restrictions, servitudes, permits, rights-of-way, surface leases and other similar rights for the purpose of surface or other operations, facilities, pipelines, transmission lines, transportation lines, distribution lines, power lines, telephone lines and other like purposes, or for the joint or common use of the lands, rights-of-way, facilities and equipment, in each case, to the extent the same does not prevent or materially impair the operation or use of the Assets as currently operated and used;

(h)vendor’s, carrier’s, warehousemen’s, repairmen’s, mechanic’s, workmen’s, materialmen’s, construction or other like liens arising by operation of Law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations (i) which are not yet due or (ii) if delinquent, that are being contested in good faith by appropriate proceedings by or on behalf of Seller and are set forth on Schedule 1.1(b) and, in each case of (i) and (ii), from which the Assets will be permanently and fully released pursuant to the Sale Order or that are discharged pursuant to the Bankruptcy Code;

(i)liens created under Permits, easements, rights-of-way or Applicable Contracts, or by operation of Law in respect of obligations which (i) are not yet due or (ii), if delinquent, which are being contested in good faith by appropriate proceedings by or on behalf of Seller and are set forth on Schedule 1.1(b) and, in each case of (i) and (ii), from which the Assets will be permanently and fully released pursuant to the Sale Order or that are discharged pursuant to the Bankruptcy Code;

(j)any Encumbrance affecting the Assets that is permanently and fully released at or prior to Closing or that are discharged pursuant to the Bankruptcy Code;

(k)all litigation and claims set forth on Schedule 7.6 and all Pipeline Imbalances set forth on Schedule 7.14;

(l)limitations (including operating limitations) imposed on the Assets by reason of the rights of subsurface owners or operators in a common property (including the rights of coal, utility and timber owners), in each case, to the extent the same does not prevent or materially impair the operation or use of the Assets subject thereto as currently operated and used;

(m)all restrictions or limitations applicable to any ROW Interest set forth in any Hydrocarbon lease from which such ROW Interest is derived, in each case, to the extent the same does not prevent or materially impair the operation or use of such ROW Interest as currently operated and used;

(n)zoning and planning ordinances and municipal regulations;

(o)all other Encumbrances, instruments, obligations, defects and irregularities affecting the Assets that individually or in the aggregate do not materially interfere with the ownership, operation or use of the Assets as currently operated and used; and

(p)the express terms and conditions of any conveyance or granting document creating or evidencing any Owned Real Property or ROW Interestand all restrictions on the exercise of the rights under a conveyance or granting instrument that are set forth therein or in another executed agreement between the parties thereto that individually or in the aggregate do not prevent or materially impair the operation or use of the Assets as currently operated and used.

118“Person” means any individual, firm, corporation, company, partnership, joint venture, limited partnership, limited liability company, association, trust, estate, labor union, organization, Governmental Authority or any other entity.

119“Personal Property” has the meaning set forth in Section 2.1(d).

120“Pipeline Imbalance” means any marketing imbalance between the quantity of Hydrocarbons attributable to the Assets required to be delivered by Seller under any Contract relating to the gathering, transportation, marketing, storage or processing (including any production handling and processing at a separation facility) and the quantity of Hydrocarbons attributable to the Assets actually delivered by Seller pursuant to the relevant Contract, together with any appurtenant rights and obligations concerning production balancing at the delivery point into the relevant sale, gathering, transportation, storage or processing facility, including corresponding cash settlement obligations.

“Plan” means, if applicable, the joint plan of reorganization of Seller under Chapter 11 of the Bankruptcy Code with respect to the Chapter 11 Cases.

“Plant” means the Lincoln Gas Plant located in Section 35, Township 18 North, Range 6 West, Kingfisher County, OK, consisting of two trains totaling 260 MMcfd of processing capacity.

“Post-Closing Consent Period” has the meaning set forth in Section 5.2(a)(iii).

“Preferential Purchase Right” has the meaning set forth in Section 7.9.

121“Purchase Price” has the meaning set forth in Section 3.1.

122“PurchasedRights of Way” has the meaning set forth in Section 2.1(c).

123“Real Property Permits” means those Permits used in connection with the ownership, operation, maintenance, repair or replacement of the Gathering Systems, the Plant or the Disposal Wells that are set forth in Schedule 7.15(c) or that otherwise grant Seller the right to locate Assets in, over or across real property; provided, however, that Environmental Permits are expressly excluded from the definition of Real Property Permits.

124“Records” has the meaning set forth in Section 2.1(i).

125“Release” or “Released” means any presence, releasing, depositing, spilling, leaking, pumping, pouring, placing, emitting, discarding, abandoning, emptying, discharging, migrating, injecting, escaping, leaching, dumping, or disposing into the environment.

126“Remediation” means, with respect to any Environmental Condition, the implementation and completion of any remedial, removal, response, construction, closure, disposal or other corrective actions required or necessary under Environmental Laws to fully correct or remove such Environmental Condition.

127“Remediation Amount” means, with respect to any Environmental Condition, the cost of the lowest cost Remediation of such Environmental Condition that is effective and reasonably available and in full compliance with Environmental Laws; provided, however, that “Remediation Amount” shall not include (a) the costs of Buyer’s or its Affiliates’ employees, or, if Seller is conducting the Remediation, Buyer’s project manager(s) or attorneys, (b) expenses for matters that are ordinary costs of doing business regardless of the presence of an Environmental Condition (e.g., those costs that would ordinarily be incurred in the day-to-day operations of the Assets or in connection with Permit renewal/amendment activities), (c) overhead costs of Buyer or its Affiliates, or (d) any costs or expenses relating to the assessment, remediation, removal, abatement, transportation and disposal of any asbestos, asbestos-containing materials or NORM unless resulting in a violation of Environmental Laws. The lowest cost Remediation may include taking no action, leaving the condition unaddressed, periodic monitoring or the recording of notices in lieu of Remediation, to the extent such responses are permitted and allowed under Environmental Laws.

128“Required Amounts” has the meaning set forth in Section 8.8(b).

129“Required Consent” has the meaning set forth in Section 5.2(a)(i).

“ROW Assignment Agreements” means, collectively, one or more assignment agreements without warranty (statutory, express or implied) and without recourse, substantially in the form attached hereto as Exhibit C, adapted as necessary to conform to local requirements to render such assignment agreements effective and recordable, conveying the Purchased Rights of Way from Seller to Buyer.

130“ROW Interests” has the meaning set forth in Section 7.15(c).

131“Sale Area” means that area set forth on Exhibit D.

132“Sale Order” means an order of the Bankruptcy Court substantially in the form attached hereto as Exhibit M, authorizing and approving, inter alia, the sale of the Assets to Buyer on the terms and conditions set forth herein, Free and Clear, the releases set forth therein, and authorizing and approving the assumption and/or assignment of the Assigned Contracts, including the 365 Contracts, to Buyer, which such order may be the Confirmation Order.

133“Seller” has the meaning set forth in the first paragraph herein.

134“Seller Indemnified Parties” has the meaning set forth in Section 13.2.

135“Seller Non-Recourse Party” has the meaning set forth in Section 16.20(a).

136“Seller Party” means each of KFM, OPWS, KSOP and CEP, individually.

137“Seller Representatives” means each Seller Party and its respective members, partners or shareholders, as the case may be, and its Affiliates and its and their respective successors and assigns, and the officers, board of directors or managers, employees, agents, advisors and representatives of all of the foregoing Persons.

138“Seller Taxes” means any (a) income, capital gains, franchise or similar Taxes of Seller or its Affiliates, (b) Asset Taxes allocated to Seller pursuant to Section 16.2 taking into account, and without duplication of, such Asset Taxes effectively borne by Seller as a result of the adjustments to the Purchase Price made pursuant to Section 3.3 or Section 3.4, as applicable, (c) Taxes attributable to the Excluded Assets and (d) Taxes (other than Taxes described in clause (a), (b) or (c)) attributable to the Assets for periods (or portions thereof) before the Effective Time.

139“Successful Bidder” means the bidder for the Assets with the highest or otherwise best bid for the Assets as determined in accordance with the Bidding Procedures.

140“Supplemental Bidding Procedures Order” means the Order Establishing Bidding Procedures Relating to the Sales of All or a Portion of the Debtors’ Assets (as may be amended, supplemented or modified from time to time).

141“Supplemental Deposit” has the meaning set forth in Section 3.2(a).

142“Target Closing Date” has the meaning set forth in Section 12.1.

143“Tax” or “Taxes” means all (a) taxes, assessments, duties, levies, imposts, unclaimed property and escheat obligations or other similar charges imposed by a Governmental Authority, including all income, franchise, profits, capital gains, capital stock, transfer, gross receipts, sales, use, transfer, service, occupation, ad valorem, property, excise, severance, windfall profit, premium, stamp, license, payroll, employment, social security, unemployment, disability, environmental, add-on, value-added, withholding (including backup withholding) and other taxes, assessments, duties, levies, imposts or other similar charges of any kind (whether payable directly or by withholding and whether or not requiring the filing of a Tax Return), and all estimated taxes, deficiency assessments, additions to tax, additional amounts imposed by any Governmental Authority, penalties and interest and (b) any liability in respect of any items described in clause (a) above that arises by reason of a Contract, assumption, transferee or successor liability or operation of Law (including by reason of participation in a consolidated, combined or unitary Tax Return).

144“Tax Return” means any return, declaration, report or information return (including any related or supporting estimates, elections, schedules, statements, or information) filed or required to be filed in connection with the determination, assessment, or collection of any Tax.

145“Third Party” means any Person other than a Party to this Agreement or an Affiliate of a Party to this Agreement.

146“Third Party Claim” has the meaning set forth in Section 13.5(b).

147“Transaction Documents” means this Agreement and those other documents executed and/or delivered pursuant to or in connection with this Agreement on the Closing Date.

148“Transfer Taxes” means any sales, use, excise, real property transfer, registration, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees incurred and imposed upon, or with respect to, the property transfers to Buyer contemplated by this Agreement as well as any interest, penalty or addition thereto whether disputed or not.

149“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of amended, succeeding, similar, substitute, proposed or final Treasury Regulations.

150“Willful Breach” means, with respect to any Party, that such Party knowingly does one or more of the following: (a) such Party willfully and intentionally breaches in any material respect (by refusing to perform or taking an action prohibited) any material pre-Closing covenant, obligation or agreement applicable to such Party, or (b) such Party willfully and intentionally causes any of its representations or warranties under this Agreement to not be true and correct in all material respects after the Execution Date and prior to the Closing Date. For clarity, if a Party is obligated hereunder to use its commercially reasonable efforts to perform an action or to achieve a result, the failure to use such commercially reasonable efforts would constitute a willful and intentional breach of this Agreement.

1.2References and Rules of Construction. All references in this Agreement to Exhibits, Schedules, Articles, Sections, subsections and other subdivisions refer to the corresponding Exhibits, Schedules, Articles, Sections, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Articles, Sections, subsections and other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language hereof. The words “this Agreement,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular Article, Section, subsection or other subdivision unless expressly so limited. The word “including” (in its various forms) means including without limitation. Unless expressly provided to the contrary, the word “or” is not exclusive. All references to “$” or “dollars” shall be deemed references to United States dollars. Each accounting term not defined herein, and each accounting term partly defined herein to the extent not defined, will have the meaning given to it under GAAP as in effect from time to time. Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Except as expressly provided otherwise in this Agreement, references to any Law or agreement means such Law or agreement as it may be amended from time to time. References to any date shall mean such date in Houston, Texas and for purposes of calculating the time period in which any notice or action is to be given or undertaken hereunder, such period shall be deemed to begin at 12:01 a.m. on the applicable date in Houston, Texas. The word “extent” in the phrase “to the extent” shall mean the degree or proportion to which a subject or other thing extends, and such phrase shall not mean simply “if.” If a date specified herein for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

ARTICLE IIASSET ACQUISITION

2.1Asset Acquisition. Upon the terms and subject to (x) the conditions of this Agreement, and for the consideration specified in Section 3.1 and (y) entry of the Sale Order pursuant to Sections 363 and 365 of the Bankruptcy Code (and, if applicable, Sections 1123(a)(5), 1123(b) and 1141(c) of the Bankruptcy Code), Seller agrees to sell, assign, transfer and convey to Buyer, and Buyer agrees to purchase, pay for and acquire from Seller all of Seller’s right, title and interest in and to the following assets (less and except for the Excluded Assets, such interest of Seller in such assets, collectively, the “Assets”):

(a)all gathering systems, pipelines, compressor stations and related facilities located in the Sale Area and generally described on Exhibit E (collectively, the “Gathering Systems”);

(b)all Owned Real Property, including the Plant;

(c)all of the easements, rights-of-way, surface leases, servitudes, licenses, surface use agreements, crossing rights and other surface or sub surface interests or rights held by Seller to the extent used or held for use in connection with the ownership or operation of the other Assets or which are required for access to the other Assets, including those set forth on Exhibit F, together with all rights, hereditaments, and appurtenances thereto, excluding the FCC Licenses (collectively, the “PurchasedRights of Way”);

(d)all equipment, machinery, fixtures, buildings, structures, improvements and other real, personal and mixed property, operational or nonoperational, whether owned or leased, that is used or held for use in connection with the other Assets or otherwise located in the Sale Area, including (without limitation) all tubing, pumps, pipes, pipelines, valves, meters, motors, compressors, compression equipment, line fill, scrubbers, spare parts, pipeline markers, vents, measurement telemetry, regulators, gathering lines, fittings, pig launching and receiving equipment, dehydration units, tanks, traps, cathodic protection units, processing and separation facilities, structures and materials (in each case) used or held for use in connection with the ownership or operation of the Gathering Systems, the Plant or the Disposal Wells and as may be constructed, expanded or extended prior to the Closing Date, including such items set forth on Exhibit G (Seller’s interest in such properties, collectively, the “Personal Property”);

(e)to the extent assignable (provided that Seller will use commercially reasonable efforts prior to Closing to obtain any necessary Consent to assignment, without any obligation to incur any out-of-pocket expense or provide any other consideration), all Permits, other than Real Property Permits (which are covered by Section 2.1(c)), used or held for use in connection with the ownership or operation of the other Assets;

(f)all Assigned Contracts;

(g)subject to the approval of the transfer of any applicable Assigned FCC Licenses (but without limiting Section 12.5), all radio and communication towers, all SCADA systems, all radio and telephone equipment and all licenses (to the extent assignable) relating thereto, in each case that are used or held for use in connection with the operation of the other Assets;

(h)the disposal wells described on Exhibit H;

(i)all books, records and files, reports, Asset Tax and accounting records, in each case to the extent relating to the Assets, including (without limitation): (i) land and title records (including surveys and maps); (ii) contract files; (iii) correspondence; (iv) facility and pipeline files (including construction records and imbalance account records); (v) the Continuing Employee Records; and (vi) environmental, regulatory, accounting and Asset Tax records; but excluding any of the foregoing items to the extent comprising or otherwise attributable to the Excluded Assets (the foregoing, subject to such exclusion, the “Records”);

(j)all personal computers, and to the extent assignable (provided that Seller will use commercially reasonable efforts prior to Closing to obtain any necessary Consent to assignment, without any obligation to incur any out-of-pocket expense or provide any other consideration), any central SCADA server and all software associated with any SCADA system included in the Assets, network equipment and associated peripherals;

(k)all trucks, cars and vehicles, including those listed on Exhibit I;

(l)all rights, claims and causes of action (including all audit rights, rights of indemnity, set-off or refunds and any and all rights and interests of Seller under any policy or agreement of insurance) of Seller to the extent (and only to the extent) such rights, claims or causes of action relate to any of the Assumed Obligations (other than (i) Avoidance Actions which shall be addressed solely by Section 2.1(n) and (ii) any rights, claims and causes of action against any Excluded Persons and Entities);

(m)those licenses granted by the FCC that are held by Seller or an Affiliate of Seller and described on ExhibitJ (the “Assigned FCC Licenses”);

(n)except (i) as otherwise released pursuant to the Sale Order, (ii) for any Avoidance Actions against any Excluded Persons and Entities, and (iii) for any Avoidance Actions specified in Section 2.2(s) and Section 2.2(v), all Avoidance Actions;

(o)[reserved]; and

(p)all trade credits and accounts receivable of Seller attributable to the Assets with respect to any period of time from and after the Effective Time or to any other Assumed Obligations.

2.2Excluded Assets. Notwithstanding anything contained in Section 2.1 to the contrary, Seller is not selling, assigning or conveying, and the term “Assets” shall expressly exclude the following assets of Seller, all of which shall be retained by Seller (collectively, the “Excluded Assets”):

(a)all of Seller’s corporate minute books and corporate Tax, or financial records that relate to Seller’s business generally (including the ownership and operation of the Assets);

(b)except to the extent related to any Assumed Obligations, all trade credits, all accounts receivable, if any, and all other proceeds, income or revenues attributable to the Assets with respect to any period of time prior to the Effective Time;

(c)except to the extent related to any Assumed Obligations, all claims, causes of action, manufacturers’ and contractors’ warranties and other rights of Seller arising under or with respect to (i) any Assets that are attributable to periods of time prior to the Effective Time including claims for adjustments or refunds, and (ii) any other Excluded Assets;

(d)subject to Section 5.1(b), all rights and interests of Seller (i) under any policy or agreement of insurance or (except to the extent related to any Assumed Obligations) indemnity, (ii) under any bond or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property, and in each of clauses (i) and (iii), except to the extent related to any Assumed Obligations;

(e)all claims of Seller for refunds of or loss carry forwards with respect to Seller Taxes;

(f)all of Seller’s proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property;

(g)all documents and instruments and other data or information of Seller that may be protected by an attorney-client privilege (other than environmental reports or evaluations);

(h)all documents and instruments and other data or information that cannot be disclosed to Buyer as a result of confidentiality arrangements under agreements with Third Parties (provided that Seller shall use commercially reasonable efforts to obtain waivers of any such confidentiality arrangements or permit Buyer to execute a joinder agreement with respect thereto);

(i)except to the extent related to any Assumed Obligations, all audit rights arising under any of the Applicable Contracts or otherwise with respect to (i) any period prior to the Effective Time, with respect to the Assets or (ii) any of the Excluded Assets;

(j)documents prepared or received by Seller or its Affiliates with respect to (i) lists of prospective purchasers for such transactions compiled by Seller or its Affiliates, (ii) bids submitted by other prospective purchasers of the Assets or any other interest in the Assets, (iii) analyses by Seller or its Affiliates of any bids submitted by any prospective purchaser, (iv) correspondence between or among Seller or its Affiliates or their respective representatives, and any prospective purchaser other than Buyer, and (v) correspondence between Seller or its Affiliates or any of their respective representatives with respect to any of the bids, the prospective purchasers or the transactions contemplated in this Agreement;

(k)Seller’s evaluations, estimates and valuations of assets or unliquidated liabilities, pilot studies, engineering, production, financial or economic studies, reports or forecasts, and any and all similar forward-looking economic, evaluative, or financial information relating to the Assets;

(l)any Assets described in Section 2.1(c), Section 2.1(e) or Section 2.1(f) that are not assignable (provided that Seller will use commercially reasonable efforts to obtain any necessary consents to assignment with respect thereto) after giving effect to the Sale Order;

(m)the sponsorship of, and all assets attributable to, the Benefit Plans and any other benefit or compensation plan, program, policy, or arrangement of any kind at any time sponsored, maintained, contributed to or required to be contributed to by Seller or any of its Affiliates or under or with respect to which Seller or any of its Affiliates has (or has had) any Liability;

(n)all other properties and assets specifically identified on Exhibit K;

(o)all Excluded Contracts;

(p)all engagements and similar letters and agreements with Seller’s legal advisors, it being agreed that Buyer shall have no right to claim, own or waive any attorney-client or similar privilege in favor of Seller or any of its Affiliates with respect to the ownership or operation of the Assets;

(q)all rights of Seller under this Agreement and the other Transaction Documents;

(r)any prepayments or good faith or other deposits submitted by any Third Party under the terms of the Supplemental Bidding Procedures Order;

(s)Seller’s rights, including any rights of set-off, claims, and causes of action, including any Avoidance Actions, arising from or relating to (i) Seller’s acquisition of produced water assets, including produced water gathering pipelines, facilities, disposal wells, surface leases, and easements, from Oklahoma Energy Acquisitions, LP or its Affiliates in November 2018, (ii) Cimarron Express Pipeline LP and (iii) Cause No. 2019-62128 in the 333rd Judicial District Court of Harris County, TX, styled KFM v. KFM Holdco, LLC;

(t)all rights, claims and causes of action related to any matter listed on Schedule 7.6;

(u)all cash and cash equivalents of Seller;

(v)all rights, claims and causes of action (including Avoidance Actions) against any Excluded Persons and Entities; and

(w)any assets or properties otherwise expressly identified as Excluded Assets under this Agreement.

2.3Revenues and Expenses. For purposes of determining the amount of the adjustment to the Purchase Price provided for in Section 3.3, the principles set forth in this Section 2.3 shall apply except as expressly provided otherwise in this Agreement. Subject to the preceding sentence: (i) Seller shall remain entitled to all of the rights of ownership (including the right to all gathering fees, transportation fees and other proceeds) and shall remain responsible for all Operating Expenses, in each case attributable to the Assets for the period of time prior to the Effective Time, (ii) and subject to the occurrence of the Closing, Buyer shall be entitled to all of the rights of ownership (including the right to all gathering fees, transportation fees and other proceeds) attributable to the Assets for the period of time from and after the Effective Time, and shall be responsible for all Operating Expenses attributable to the Assets for the period of time from and after the Effective Time. Such amounts that are received or paid prior to Closing shall be accounted for in the Closing Settlement Statement or Final Settlement Statement, as applicable. Such amounts that are received or paid after Closing but prior to the date of the Final Settlement Statement shall be accounted for in the Final Settlement Statement. If after Closing, if not otherwise accounted for in the Closing Settlement Statement or Final Settlement Statement, (w) Seller receives an invoice for any Operating Expense for which Buyer is responsible Seller shall promptly remit such invoice to Buyer for payment, (x) Seller receives any revenues to which Buyer is entitled Seller shall promptly remit such revenues to Buyer, (y) Buyer receives an invoice for any Operating Expense for which Seller is responsible Buyer shall promptly remit such invoice to Seller for payment and (z) Buyer receives any revenues to which Seller is entitled Buyer shall promptly remit such revenues to Seller. For the avoidance of doubt, the date an item or work is ordered is not the date of a transaction for settlement purposes in the Closing Settlement Statement or Final Settlement Statement, as applicable, but rather the date on which the item ordered is delivered to the job site, or the date on which the work ordered is performed, is the relevant date (i.e., on an accrual basis). “Earned” and “incurred”, as used in this Agreement, shall be interpreted in accordance with GAAP, as applied by Seller in the ordinary course of business consistent with past practice, subject to the other provisions of this Section 2.3. Seller shall utilize reasonable interpolative procedures to arrive at an allocation of production when exact meter readings (including gas production meters or sales meters) or gauging and strapping data is not available.

2.4365 Contracts; Cure Costs.

(a)At the Closing, Buyer shall pay, pursuant to Section 365 of the Bankruptcy Code, if applicable Section 1123(b)(2) of the Bankruptcy Code, and the Sale Order, any and all cure and reinstatement costs or expenses that are required to be paid under Sections 365(b)(1)(A), 365(b)(1)(B) and if applicable 1123(b)(2), or any other applicable provision of the Bankruptcy Code to effectuate the assumption and assignment of the Assigned Contracts (such costs or expenses required to be paid by Buyer, the “Cure Costs”); provided that, Buyer shall not be required to pay (and Seller shall retain and be responsible for) the amount of Cure Costs with respect to the Gathering Agreements to the extent the amount of Cure Costs for the Gathering Agreements, in the aggregate, exceeds Seller’s good faith estimate of the Cure Costs for all Gathering Agreements, in the aggregate, as set forth on Schedule 2.4(b) as of the Execution Date by more than $1,000,000.00 (the “Excess Cure Costs”). For the avoidance of doubt, (i) Buyer shall pay all Cure Costs (other than the Excess Cure Costs) in cash at such time as is provided in the preceding sentence and (ii) neither Buyer nor any Buyer Affiliates shall be required to make any payment of Cure Costs for, and neither Buyer nor any Buyer Affiliates shall assume or have any obligation for any Liabilities with respect to, any Excluded Contract.

(b)Schedule 2.4(b) (as may be amended from time to time or supplemented with written notice to Buyer) sets forth each 365 Contract and Seller’s good faith estimate of the amount of the Cure Costs payable in respect of each such 365 Contract (and if no Cure Cost is estimated to be payable in respect of any 365 Contract, the amount of such Cure Cost designated for such 365 Contract shall be “$0.00”) (as such schedules may from time to time be amended or supplemented with written notice to Buyer, the “365 Schedule”). Seller shall use its reasonable best efforts to provide, and to cause the Seller Representatives to provide, financial and other pertinent information regarding the 365 Contracts, as is reasonably requested by Buyer, including using Seller’s reasonable best efforts to furnish Buyer’s financing sources with such financial and other pertinent information regarding such 365 Contracts as may be reasonably requested; provided that Seller shall not be required to breach any confidentiality restriction contained in any 365 Contract.

(c)Within ten (10) Business Days after the Execution Date, and subject to Buyer’s rights under Section 2.4(e) below to subsequently amend such designations, Buyer will deliver to Seller schedules of the 365 Contracts to be assumed by Seller and assigned to Buyer (as Assigned Contracts) at the Closing (the “Election Form”). Seller shall commence any necessary proceedings before the Bankruptcy Court and otherwise take all reasonably necessary actions in order to determine Cure Costs with respect to any 365 Contracts including providing sufficient notice in accordance with the Supplemental Bidding Procedures Order to all counterparties to the 365 Contracts of their assumption or rejection and providing a schedule of Cure Costs. Any 365 Contracts that are not set forth on such list of 365 Contracts to be assumed shall be Excluded Contracts and deemed rejected, and shall be an Excluded Asset for all purposes hereof.

(d)Promptly following the Execution Date (and in any event within two (2) Business Days following commencement of the Chapter 11 Cases), Seller shall file the 365 Schedule with the Bankruptcy Court and deliver a written notice in a form reasonably acceptable to Buyer of the proposed assignments of the 365 Contracts that are Assigned Contracts and the proposed Cure Costs for each 365 Contract (consistent with Seller’s good faith estimates set forth on Schedule 2.4(b)) to all non-debtor parties of the 365 Contracts, which notice shall notify each non-debtor party to such 365 Contract of (i) the proposed Cure Cost for such 365 Contract and (ii) an objection deadline for such non-debtor party to object to the proposed Cure Cost. To the extent that any objections are received from such non-debtor parties in response to such notice, Seller shall take all reasonably necessary actions (excluding providing any payment of Cure Costs unless funded by Buyer, but without limiting Seller’s retention of and responsibility for any Excess Cure Costs) to resolve such disputes with the applicable non-debtor party, and all such resolutions with respect to any 365 Contract that is an Assigned Contract shall be acceptable to Buyer in its sole discretion.

(e)At any time prior to the Designation Deadline, Buyer shall have the right, which may be exercised in Buyer’s sole discretion, to provide written notice to Seller of Buyer’s election to designate any 365 Contract (including any Contract that is an Assigned Contract immediately before such designation) (i) as an Excluded Contract and upon such designation such Contract shall constitute an Excluded Contract and, if applicable, shall cease to constitute an Assigned Contract or (ii) to the extent not already rejected, as an Assigned Contract and upon such designation Seller shall use commercially reasonable efforts to effect the assumption of such 365 Contract by the applicable Seller in accordance with the Bankruptcy Code and, if Seller is successful in effecting such assumption, such 365 Contract shall constitute an Assigned Contract and shall cease to constitute an Excluded Contract. If a 365 Contract is subject to a cure dispute or other dispute as to the assumption or assignment of such 365 Contract that has not been resolved to the mutual satisfaction of Buyer and Seller prior to the Designation Deadline, then the Designation Deadline shall be extended (but only with respect to such 365 Contract) to no later than the earliest of (A) the date on which such dispute has been resolved to the mutual satisfaction of Buyer and Seller, (B) the date on which such 365 Contract is deemed rejected by operation of Sections 365(d)(4) or 1123(b)(2) of the Bankruptcy Code, as applicable, or (C) the date required by the Bankruptcy Court and set forth in the Sale Order. The Election Form shall be deemed automatically amended to reflect changes made pursuant to this Section 2.4(e).

(f)If Buyer exercises its rights in Section 2.4(e) above to designate a 365 Contract (including a 365 Contract that was an Assigned Contract immediately before such designation) as an Excluded Contract, there shall be no change in the Purchase Price as a result of such designation or change in designation.

(g)Notwithstanding anything in this Agreement to the contrary, Seller shall not reject any 365 Contracts without the prior written consent of Buyer in its sole discretion; provided that, after the Designation Deadline, Seller may reject Excluded Contracts without the consent of Buyer so long as such 365 Contracts were identified to Buyer in writing prior to the Designation Deadline. In the event that Seller identifies (whether before or after the Designation Deadline) any additional 365 Contracts capable of being assumed or rejected that were not previously identified as such, Seller shall promptly notify Buyer of (i) such 365 Contracts and (ii) Seller’s good faith estimate of the amount of the Cure Costs payable in respect of each such 365 Contract. For the avoidance of doubt, Buyer may designate each such additional 365 Contract described in the immediately preceding sentence as an Assigned Contract or Excluded Contract pursuant to this Section 2.4(e), notwithstanding the passage of the Designation Deadline. The Election Form shall be deemed automatically amended to reflect changes made pursuant to this Section 2.4(g).

(h)Notwithstanding anything in this Agreement to the contrary, including Section 2.4(e) above, the Gathering Agreements shall at all times constitute Assigned Contracts and shall be assigned to Buyer at the Closing.

2.5Consents for 365 Contracts and Purchased Rights of Way. For all purposes of this Agreement (including all representations and warranties of Seller contained herein), Seller shall be deemed to have obtained all required consents (including all Required Consents) in respect of the assumption and assignment of any 365 Contract or Purchased Right of Way if, and to the extent that, (i) Seller has properly served under the Bankruptcy Code notice of assumption and/or assignment on the counterparty to such 365 Contract or Purchased Right of Way, (ii) any objections to assumption and/or assignment filed by such counterparty have been withdrawn or overruled (including pursuant to the Sale Order or other order of the Bankruptcy Court), and (iii) pursuant to the Sale Order, Seller is authorized to assume and assign such 365 Contract or Purchased Right of Way to Buyer pursuant to section 365 of the Bankruptcy Code or otherwise and any applicable Cure Costs have been satisfied by Buyer as provided in this Agreement.

ARTICLE III
PURCHASE PRICE; DEPOSIT

3.1Purchase Price. The consideration for the transfer of the Assets and the transactions contemplated hereby shall be (a) the assumption of the Assumed Obligations and (b) an amount equal to $88,000,000.00to be paid in cash by Buyer to Seller, by wire transfer in same day funds at Closing as provided for in this Agreement (the “Purchase Price”).

3.2Deposit.

(a)On January 2, 2020, Buyer deposited into the Escrow Account, by wire transfer in same day funds, the sum of $8,525,000.00, which represented ten percent (10%) of the unadjusted Purchase Price under the Original Agreement (such amount, together with any interest earned thereon, the “Original Deposit”). On or before 5:00 p.m. (Central Prevailing Time) on January 17, 2020, Buyer shall deposit into the Escrow Account, by wire transfer in same day funds, an additional $275,000.00 (such amount, together with any interest earned thereon, the “Supplemental Deposit”, and the Supplemental Deposit together with the Original Deposit, the “Deposit”). If the Closing occurs, the Deposit shall be applied toward the Adjusted Purchase Price at Closing pursuant to Section 12.3.

(b)If this Agreement is terminated in accordance with Section 14.1, the provisions of Section 14.2 shall be applicable and the Deposit shall be handled in accordance therewith.

3.3Adjustments to Purchase Price. The Purchase Price shall be adjusted as follows, determined on an accrual basis in conjunction with Section 2.3 and otherwise in accordance with GAAP, as applicable (and the resulting amount shall be herein called the “Adjusted Purchase Price”):

(a)The Purchase Price shall be adjusted upward by the following amounts (without duplication):

(i)an amount equal to all non-reimbursed Operating Expenses paid (whether prepaid or otherwise) by Seller that are allocable to Buyer pursuant to Section 2.3;

(ii)the amount of all Asset Taxes prorated to Buyer in accordance with Section 16.2 but paid or payable by Seller;

(iii)to the extent that any Third Party owes a Pipeline Imbalance as of the Effective Time to any Seller, an amount equal to the product of (A) the underdelivered volumes times (B) $1.50/MMBtu for gaseous Hydrocarbons; and an amount equal to the product of (X) the underdelivered volumes times (Y) $16.50/Bbl for liquid Hydrocarbons

(iv)an amount equal to $825,000.00, to account for Seller’s general and administrative costs and expenses related to the ownership and management of the Assets during the period between the Effective Time and Closing; and

(v)any other amount provided for elsewhere in this Agreement or otherwise agreed in writing by Seller and Buyer.

(b)The Purchase Price shall be adjusted downward by the following amounts (without duplication):

(i)an amount equal to all revenues received by Seller attributable to the operation of the Assets during the Interim Period (for clarity, excluding, amounts received by Seller for the sale of Hydrocarbons marketed or otherwise sold for the account of Third Parties, net of any fees or other amounts retained by Seller for Seller’s account out of such amounts, the allocation of which fees and other amounts are addressed in Section 2.3);

(ii)the amount of all Asset Taxes prorated to Seller in accordance with Section 16.2 but paid or payable by Buyer;

(iii)to the extent that the Seller Parties owe a Pipeline Imbalance as of the Effective Time to any Third Party, an amount equal to the product of (A) the underdelivered volumes times (B) $1.50/MMBtu for gaseous Hydrocarbons; and an amount equal to the product of (X) the underdelivered volumes times (Y) $16.50/Bbl for liquid Hydrocarbons;

(iv)an amount equal to all non-reimbursed Operating Expenses paid (whether prepaid or otherwise) by Buyer that are allocable to Seller pursuant to Section 2.3; and

(v)any other amount provided for elsewhere in this Agreement or otherwise agreed in writing by Seller and Buyer.

3.4Closing Settlement Statement; Final Settlement Statement.

(a)Not less than five (5) Business Days prior to the Closing, Seller shall prepare and submit to Buyer for review a draft settlement statement (the “Closing Settlement Statement”) that shall set forth Seller’s good faith estimate of the Adjusted Purchase Price, reflecting each proposed adjustment to be made in accordance with this Agreement as of the date of preparation of such Closing Settlement Statement and the calculation of the adjustments used to determine such amount (provided that, to the extent actual amounts are not available for any particular adjustment as of the date of preparation, such adjustment shall reflect Seller’s good faith estimate based on all information reasonably available to Seller at the time, including estimated Operating Expenses for the period between the Effective Time and the month the Closing occurs), together with the designation of Seller’s accounts for the wire transfers of funds as set forth in Section 12.3(d). Within three (3) Business Days after receipt of the Closing Settlement Statement, Buyer will deliver to Seller a written report prepared in good faith containing all changes that Buyer proposes, in good faith, to be made to the Closing Settlement Statement, if any (including proposed changes to Seller’s good faith estimates, where applicable), together with a brief explanation of such changes (a “Dispute Notice”). The Closing Settlement Statement, as agreed upon by the Parties, will be used to adjust the Purchase Price at Closing; provided that, if the Parties cannot agree on any adjustment in the Closing Settlement Statement prior to the Closing (including with respect to any estimated adjustment), Buyer shall deposit into the Escrow Account a portion of the Purchase Price equal to the positive difference between Seller’s proposed adjustment and Buyer’s proposed adjustment (as set forth in the Dispute Notice) for such disputed adjustments (adjusted for any amounts therein actually agreed by the Parties prior to Closing), and such amounts shall be credited towards the Adjusted Purchase Price at Closing, subject to resolution as between the Parties prior to the Final Settlement Date or, if applicable, as provided in Section 3.5.

(b)On or before the date that is thirty (30) days following the Closing Date, a final settlement statement (the “Final Settlement Statement”) will be prepared by Seller, based on actual revenues and expenses and that takes into account all final adjustments made to the Purchase Price and shows the resulting final Adjusted Purchase Price. The Final Settlement Statement shall set forth the actual allocation of the amounts required by this Agreement. Seller shall supply reasonable documentation in the possession of Seller or any of its Affiliates to support the items for which adjustments are proposed or made in the Final Settlement Statement and a brief explanation of any such adjustments and the reasons therefor. As soon as practicable, and in any event within fifteen (15) daysafter receipt of the Final Settlement Statement, Buyer will deliver to Seller a Dispute Notice containing any proposed changes to the Final Settlement Statement and a brief explanation of such changes. Any changes not included in a Dispute Notice (including any Dispute Notice delivered pursuant to Section 3.4(a) above) shall be deemed waived, and Seller’s determinations with respect to all such elements of the Final Settlement Statement that are not addressed in the Dispute Notice (including any Dispute Notice delivered pursuant to Section 3.4(a) above) shall prevail. If the final Adjusted Purchase Price set forth in the Final Settlement Statement is mutually agreed upon by Seller and Buyer, the Final Settlement Statement and the final Adjusted Purchase Price, shall be final and binding on the Parties. If the final Adjusted Purchase Price is (a) more than the Adjusted Purchase Price used at Closing pursuant to Section 3.4(a), Seller shall be entitled to receive from Buyer the amount of such difference, or (b) less than the Adjusted Purchase Price used at Closing pursuant to Section 3.4(a), Buyer shall be entitled to receive from Seller the amount of such difference. To that end, within two (2) Business Days after the final resolution by the Parties of the final Adjusted Purchase Price, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to each Party the funds in the Escrow Account to which such Party is entitled in accordance with the terms hereof; provided that, if Seller is owed amounts in excess of the amounts in the Escrow Account, then Buyer shall promptly (and in any event within five (5) Business Days following the final resolution by the Parties of the final Adjusted Purchase Price) pay to Seller via wire transfer to the account designated by Seller, the amount of any such difference. Notwithstanding anything to the contrary herein, in no event shall Seller be liable to Buyer for any amounts pursuant to this Section 3.4(b) for amounts other than amounts in the Escrow Account. The Parties shall use commercially reasonable efforts to resolve any disputes related to the final Adjusted Purchase Price; provided that, if the Parties are unable to resolve any such disputes (to the extent set forth in a timely delivered Dispute Notice) within sixty (60) days after the Closing Date (the “Final Settlement Date”), then the final Adjusted Purchase Price shall be determined in accordance with Section 3.5.

3.5Disputes. If Seller and Buyer are unable to resolve the matters addressed in the Dispute Notice (if any) by the Final Settlement Date, each of Buyer and Seller shall within fourteen (14) Business Days thereafter, summarize its position with regard to such dispute in a written document of ten pages or less and submit such summaries to the Houston, Texas office of Deloitte Touche Tohmatsu Limited (“Deloitte”) (or if Deloitte is unable or unwilling to serve as arbitrator within twenty (20) days after receipt of a written request from the Parties to serve and absent agreement by the Parties as to a replacement for such arbitrator within ten (10) Business Days after notification that Deloitte is unable or unwilling to serve, the arbitrator shall be selected by the Houston, Texas office of the AAA) (the “Accounting Arbitrator”), together with the Dispute Notice and any other documentation such Party may desire to submit. The Accounting Arbitrator shall also be furnished with a copy of this Agreement. The Parties shall instruct the Accounting Arbitrator that, within twenty (20) Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision choosing either Seller’s position or Buyer’s position with respect to each matter addressed in any Dispute Notice, whichever complies more closely to the terms of the Agreement and the materials described above. The costs of such Accounting Arbitrator shall be borne one-half by Seller and one-half by Buyer. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Seller and Buyer and will be enforceable against each of the Parties in any court of competent jurisdiction. The final Adjusted Purchase Price determined by the Accounting Arbitrator pursuant to this Section 3.5 shall be final and binding on the Parties, without right of appeal and enforceable by either Party in any court of competent jurisdiction. The Accounting Arbitrator shall be authorized to resolve only the specific disputed aspects of the Final Settlement Statement submitted by the Parties as provided above and may not award damages, interest or penalties to any Party with respect to any matter, notwithstanding any AAA Rules to the contrary. Within two (2) Business Days after the final resolution by the Accounting Arbitrator of the matters addressed in the Dispute Notice, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to each Party the funds in the Escrow Account to which such Party is entitled in accordance with the terms of such final resolution; provided that, if Seller is owed amounts in excess of the amounts in the Escrow Account, then Buyer shall promptly (and in any event within five (5) Business Days following the final resolution by the Parties of the final Adjusted Purchase Price) pay to Seller via wire transfer to the account designated by Seller, the amount of any such difference; provided that, notwithstanding anything to the contrary herein, in no event shall Seller be liable to Buyer for any amounts pursuant to this Section 3.5 for amounts other than amounts in the Escrow Account.

3.6Allocated Values. The “Allocated Value” for each Asset shall equal the lesser of (i) the amount set forth for such Asset on Schedule 3.6 (and if there is no value allocated to an Asset on Schedule 3.6, the Allocated Value of such Asset shall be $0.00) or (ii) the actual cost to replace such Asset, provided Seller shall bear the burden of demonstrating such lower cost of replacement to Buyer’s reasonable satisfaction, and such Allocated Values shall be used in calculating adjustments to the Purchase Price as provided in Section 5.2(a)(i).

3.7Withholding. Notwithstanding anything in this Agreement to the contrary, to the extent that Buyer reasonably determines that it is required by applicable Law to deduct or withhold from any amounts otherwise payable to Seller pursuant to this Agreement, Buyer shall be entitled to deduct and withhold from any consideration otherwise payable or deliverable to Seller pursuant to this Agreement such amounts as may be required to be deducted or withheld therefrom under applicable Law; provided that, Buyer shall promptly notify Seller of any such determination and the Parties shall cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such deduction or withholding, including by providing any certificates or forms that are reasonably requested to establish an exemption from (or reduction in) any deduction or withholding. To the extent such amounts are so properly deducted or withheld, and remitted to the applicable Governmental Authority in accordance with applicable Law, such amounts shall be treated for all purposes of this Agreement as having been paid to the Person to whom such amounts would otherwise have been paid absent such deduction or withholding.

ARTICLE IVACCESS/DISCLAIMERS

4.1Access.

(a)From and after the Execution Date and up to and including the Closing Date (or earlier termination of this Agreement) but subject to (i) the other provisions of this Section 4.1, and (ii) obtaining any consents or waivers from Third Parties that are required pursuant to the terms of the easements and Applicable Contracts (including any restrictions therein related to access during hunting seasons), Seller shall afford to Buyer and its Affiliates and their respective officers, employees, agents, accountants, attorneys, investment bankers, consultants and other authorized representatives (the “Buyer Representatives”), upon prior reasonable notice, reasonable access, during normal business hours, to the Assets, reasonably appropriate Seller personnel and all Records and other documents in Seller’s or its Affiliates’ possession, in each case, to the extent relating to the Assets. Without limiting the forgoing, Seller shall use commercially reasonable efforts to make available to Buyer upon the execution of this Agreement (and shall in any event make available to Buyer within three (3) Business Days after the Execution Date), in electronic format, all title opinions, abstracts of title, elections, Third Party brokerage information, reports, records (including, but not limited to, contract files, records of easements and right-of-ways, and records relating to environmental and regulatory matters) and other similar data and information in Seller’s files as may be reasonably necessary in connection with Buyer’s and the Buyer Representatives’ title due diligence activities with respect to the Assets.

(b)From and after the Execution Date to the Closing Date (or earlier termination of this Agreement), subject to (i) the other provisions of this Section 4.1, and (ii) obtaining any consents or waivers from Third Parties that are required pursuant to the terms of the easements and Applicable Contracts (including any restrictions therein related to access during hunting seasons), Buyer and the Buyer Representatives shall have inspection rights with respect to the Environmental Condition of the Assets but such inspection rights shall be limited to conducting a Phase I Environmental Site Assessment (as defined in the applicable ASTM International Standards) and limited environmental compliance review of the Assets and Buyer and the Buyer Representatives shall not conduct any Phase II Environmental Site Assessment (as defined in the applicable ASTM International Standards) or operate any equipment or conduct any testing, boring, sampling, drilling or other invasive investigation activities (in each case) on or with respect to any of the Assets without the prior written consent of Seller, which consent may be withheld in Seller’s sole discretion. If Seller denies a reasonable request by Buyer to undertake any Phase II Environmental Site Assessment on any Asset, Buyer shall have the right to reduce the Purchase Price by an amount equal to Buyer’s good faith estimate of the Remediation Amounts of all Environmental Defects or potential Environmental Defects identified in Buyer’s Phase I Environmental Site Assessment or limited compliance review for the relevant Asset as disclosed in writing to Seller at the time of Buyer’s request to undertake any Phase II Environmental Site Assessment with respect to such Asset. Notwithstanding anything herein to the contrary, Buyer and/or any of the Buyer Representatives shall not have access to, and shall not be permitted to conduct, any environmental due diligence (including any Phase I Environmental Site Assessment, as defined in the applicable ASTM International Standards) with respect to any Assets where Seller does not have the authority to grant access for such due diligence.

(c)All investigations and due diligence conducted by Buyer or any Buyer Representative pursuant to Section 4.1(a) or 4.1(b), above, shall be conducted at Buyer’s sole cost, risk and expense, and any conclusions made from any examination done by Buyer or any Buyer Representative shall result from Buyer’s or Buyer Representatives’ own independent review and judgment. Buyer shall coordinate its access rights and physical inspections of the Assets with Seller so as not to unreasonably interfere with the conduct of business by Seller or its Affiliates, and Seller shall have the right to accompany Buyer and any Buyer Representative in connection with any physical inspection of the Assets at Seller’s sole cost and expense. Buyer shall, and shall cause all Buyer Representatives to, abide by all Laws and all of Seller’s safety rules, regulations, and operating policies while conducting Buyer’s due diligence evaluation of the Assets, including any environmental or other inspection or assessment of the Assets (provided that Buyer is provided an advance copy or otherwise informed of any such rules, regulations and policies), and to the extent required by any Third Party operator, execute and deliver any access agreement required by such Third Party operator.

(d)Buyer hereby releases, indemnifies, defends and holds harmless each Seller Indemnified Party from and against any and all Liabilities (including any personal injury, death or loss or damage of property) to the extent arising out of, resulting from or relating to any office visit, field visit, environmental property assessment or other due diligence activity conducted by Buyer or any Buyer Representative with respect to the Assets, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES, EXCEPTING ONLY LIABILITIES TO THE EXTENT ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY SELLER INDEMNIFIED PARTY, OR THE MERE DISCOVERY OF A PRE-EXISTING CONDITION BY BUYER OR BUYER’S REPRESENTATIVE SO LONG AS SUCH DISCOVERY DOES NOT IN AND OF ITSELF EXACERBATE OR ADVERSELY CONTRIBUTE TO ANY SUCH PRE-EXISTING CONDITION.

(e)Upon completion of Buyer’s due diligence, Buyer shall remove all equipment, tools or other property brought onto the Assets in connection with Buyer’s (or any Buyer Representative’s) due diligence investigation and to the extent there exists after such due diligence investigation any damage upon the Assets, Seller shall (i) repair all damage done to the Assets (including the real property and other assets associated therewith) in connection with Buyer’s (or any Buyer Representative’s) due diligence investigation, and (ii) restore the Assets (including the real property and other assets associated therewith) to the approximate same condition that they were prior to commencement of Buyer’s (or any Buyer Representative’s) due diligence investigation at Buyer’s sole cost and expense and without any Third Party cost or expense to Seller or its Affiliates. Seller shall provide an invoice to Buyer following any such work and Buyer shall remit payment to Seller for all reasonable and documented out-of-pocket costs and expenses paid or incurred by Seller in respect of such repair or restoration within ten (10) days after receipt of such invoice.

(f)During all periods that Buyer and/or any of the Buyer Representatives are on the Assets or any lands underlying such Assets, Buyer shall maintain, at its sole expense, policies of insurance of types and in amounts customary for such review of Buyer under Section 4.1(a) and Section 4.1(b). Upon request by Seller, Buyer shall provide evidence of such insurance to Seller prior to entering the Assets or any lands underlying such Assets.

4.2Confidentiality. Buyer acknowledges that, pursuant to its right of access to the Records and the Assets, Buyer will become privy to confidential and other information of Seller and its Affiliates and the Assets and that such confidential information shall be held confidential by Buyer and Buyer Representatives in accordance with the terms of the Confidentiality Agreement. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including the Confidentiality Agreement, shall terminate (except as to the Excluded Assets); provided, that such termination of the Confidentiality Agreement shall not relieve any party thereto from any liability thereunder for the breach of such agreement prior to the Execution Date.

4.3Disclaimers.

(a)EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII OR THE CERTIFICATE DELIVERED BY SELLER AT CLOSING, (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO BUYER OR ANY BUYER REPRESENTATIVE (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER BY A MEMBER OF THE SELLER INDEMNIFIED PARTIES), AND BUYER ACKNOWLEDGES THAT IT HAS NOT RELIED ON ANY SUCH REPRESENTATION OR WARRANTY.

(b)EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII OR THE CERTIFICATE DELIVERED BY SELLER AT CLOSING, SELLER EXPRESSLY DISCLAIMS, AND BUYER ACKNOWLEDGES THAT IT HAS NOT RELIED UPON, ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED BY ANY MEMBER OF SELLER INDEMNIFIED PARTIES, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (III) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (IV) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (V) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY OR ON BEHALF OF SELLER OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (VI) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ANY BUYER REPRESENTATIVE IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (VII) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII OR THE CERTIFICATE DELIVERED BY SELLER AT CLOSING, SELLER FURTHER DISCLAIMS, AND BUYER ACKNOWLEDGES THAT IT HAS NOT RELIED UPON, ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE OR CONSIDERATION, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT, BUYER SHALL BE DEEMED TO BE ACQUIRING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(c)EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF HAZARDOUS MATERIALS OR OTHER MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND BUYER ACKNOWLEDGES THAT IT HAS NOT RELIED UPON ANY SUCH REPRESENTATION OR WARRANTY, AND BUYER SHALL BE DEEMED TO BE ACQUIRING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(d)Seller and Buyer agree that, to the extent required by applicable Law to be effective, the disclaimers of certain representations and warranties contained in this Section 4.3 are conspicuous disclaimers for the purpose of any applicable Law.

ARTICLE V
CASUALTIES; TRANSFER RESTRICTIONS

5.1Casualty or Condemnation Loss.

(a)Notwithstanding anything herein to the contrary, from and after the Effective Time if Closing occurs, with respect to the Assets, Buyer shall assume all risk of loss, including with respect to the depreciation of any Asset due to ordinary wear and tear, and, in each case, Buyer shall not assert such matters as any Casualty or Condemnation Loss hereunder.

(b)If, after the Execution Date but prior to the Closing Date, any portion of the Assets is damaged or destroyed or otherwise impaired by fire, explosion, tornado, hurricane, earthquake, earth movement, flood, water damage or other similar casualty or is taken in condemnation or under right of eminent domain (in each case, a “Casualty or Condemnation Loss”), then Buyer shall nevertheless be required to close the transactions contemplated by the Agreement without any change to the Purchase Price, and Seller shall pay to Buyer all sums paid) to Seller by Third Parties by reason of such Casualty or Condemnation Loss insofar as with respect to the Assets (net of amounts spent or incurred by Seller prior to Closing with respect replacement or repair of any such Casualty or Condemnation Loss) and shall assign, transfer and set over to Buyer or subrogate Buyer to all of Seller’s and its Affiliates’ right, title and interest (if any) in insurance claims, unpaid awards and other rights against Third Parties (excluding any Liabilities, other than insurance claims, of or against any Seller Indemnified Parties) arising out of such Casualty or Condemnation Loss insofar as with respect to the Assets; provided, however, that Seller shall reserve and retain (and Buyer shall assign to Seller) all rights, title, interests and claims against Third Parties for the recovery of Seller’s costs and expenses incurred prior to the Closing in pursuing or asserting any such insurance claims or other rights against Third Parties with respect to any such Casualty or Condemnation Loss. Except as expressly set forth hereinabove, Seller shall retain all rights to insurance, condemnation awards and other claims against Third Parties with respect to the casualty or taking except to the extent the Parties otherwise agree in writing.

5.2Consents to Assign.

(a)With respect to each Consent set forth on Schedule 7.4 with respect to any Applicable Contract or Purchased Right of Way that is not a 365 Contract (which Consents for 365 Contracts are addressed in Section 2.4(d)), within five (5) Business Days after the Execution Date, Seller shall send to the holder of each such Consent a notice in compliance with the contractual provisions applicable to such Consent seeking such holder’s consent to the transactions contemplated hereby. With respect to each such Consent (with respect to any Applicable Contract or Purchased Right of Way that is not a 365 Contract) that is not set forth on Schedule 7.4 but is discovered by Buyer prior to Closing, Buyer shall notify Seller in writing of same within three (3) days of such discovery. With respect to each Consent (with respect to any Applicable Contract or Purchased Right of Way that is not a 365 Contract) that is not set forth on Schedule 7.4 but is discovered by Seller (or is identified by Buyer pursuant to the preceding sentence) prior to Closing, Seller shall send to the holder of each such Consent a notice in compliance with the contractual provisions applicable to such Consent seeking such holder’s consent to the transactions contemplated hereby as soon as reasonably practicable (but in any event, no later than two (2) Business Days after discovery of any such Consent). With respect to any Applicable Contract or Purchased Right of Way, in each case whether or not such Applicable Contract or Purchased Right of Way is a 365 Contract:

(i)If Seller fails to obtain a Consent prior to Closing and (A) with respect to any Applicable Contract or Purchased Right of Way that is not a 365 Contract, (1) the failure to obtain such Consent would cause the assignment of the Assets affected thereby to Buyer to be void or voidable or (2) the failure to obtain such Consent would reasonably result in the termination of an Assigned Contract or Purchased Rights of Way under the express terms thereof upon the purported assignment of such Assigned Contract or Purchased Rights of Way to Buyer pursuant to this Agreement or (B) with respect to any Applicable Contract or Purchased Right of Way that is a 365 Contract, a party to the Applicable Contract or Purchased Right of Way relating to such Consent has objected to the assignment of such Applicable Contract or Purchased Right of Way to Buyer in accordance with the terms of, or based on, any anti-assignment or consent to assign provision contained in, such Applicable Contract or Purchased Right of Way (each Consent as to which (A) or (B) is applicable, a “Required Consent”), then, unless the Bankruptcy Court has entered an order approving (or, in the case of clause (B), such objection is resolved to permit) the sale and assignment of the affected Assets to Buyer pursuant to this Agreement without obtaining such Required Consent, the Assets (or portions thereof) affected by such un-obtained Required Consent shall be excluded from the Assets to be assigned to Buyer at Closing (and shall be considered Excluded Assets hereunder) and the Purchase Price shall be reduced by the Allocated Value(s) of such Assets (or portions thereof) so excluded. In the event that any such Consent with respect to any such excluded Asset (or portion thereof) is obtained during the Post-Closing Consent Period (or if during the Post-Closing Consent Period the Bankruptcy Court enters an order providing that (x) such Required Consent is not required to consummate the sale and assignment of the affected Assets to Buyer pursuant to this Agreement without obtaining such Required Consent or (y) the affected Assets may be sold and assigned to Buyer pursuant to this Agreement free and clear of such Required Consent), then, (A) Seller shall so notify Buyer and (B) on the tenth (10th) Business Day after the date such Consent is obtained Seller shall assign the Assets (or portions thereof) that were so excluded as a result of such previously un-obtained Consent to Buyer pursuant to an instrument in substantially the same form as the Assignment or ROW Assignment Agreement, as applicable (and such Assets (or portions thereof) shall no longer be considered Excluded Assets hereunder) and, contemporaneously with said assignment, Buyer shall pay all Cure Costs (other than any Excess Cure Costs) with respect to such Assets that are 365 Contracts and reimburse Seller, by wire transfer in same day funds to Seller, to an account designated by Seller, an amount equal to all Cure Costs (other than any Excess Cure Costs) with respect to such Assets previously paid by Seller.

(ii)If Seller fails to obtain a Consent prior to Closing and such Consent is not a Required Consent (or if prior to Closing the Bankruptcy Court enters an order providing that (x) such Required Consent is not required to consummate the sale and assignment of the affected Assets to Buyer pursuant to this Agreement without obtaining such Required Consent or (y) the affected Assets may be sold and assigned to Buyer pursuant to this Agreement free and clear of such Required Consent), then the Assets (or portions thereof) subject to such un-obtained Consent shall nevertheless be assigned by Seller to Buyer at Closing as part of the Assets and Buyer shall be deemed to have assumed any and all Liabilities for the failure to obtain any such Consent as part of the Assumed Obligations hereunder and Buyer shall have no claim against the Seller Indemnified Parties from any Liability for, the failure to obtain such Consent.

(iii)Prior to Closing and until the earlier to occur of (x) the effective date of the Plan and (y) the one hundred twentieth (120th) day after Closing (the “Post-Closing Consent Period”), with respect to any unobtained Required Consents with respect to which the Bankruptcy Court shall not have entered an order proving that (x) such Required Consent is not required to consummate the sale and assignment of the affected Assets to Buyer pursuant to this Agreement without obtaining such Required Consent or (y) the affected Assets may be sold and assigned to Buyer pursuant to this Agreement free and clear of such Required Consent, Seller shall use its commercially reasonable efforts to obtain such Required Consents; provided, however, that Seller shall not be required to incur any Liability, pay any money or provide any other consideration in order to obtain any such Consent. Buyer shall use its commercially reasonable efforts (without any obligation to incur any Liability, pay money or provide any other consideration) to assist and cooperate with Seller in furtherance of Seller’s efforts pursuant to this Section 5.2(a)(iii).

ARTICLE VI[RESERVED]

ARTICLE VIIREPRESENTATIONS AND WARRANTIES OF SELLER

Seller represents and warrants to Buyer as of the Execution Date the following:

7.1Organization, Existence. Each Seller is a limited liability company duly formed and validly existing under the Laws of the State of Delaware. Seller has all requisite power and authority to own and operate its property (including the Assets) and to carry on its business as now conducted. Seller is duly licensed or qualified to do business as a foreign entity in the State of Oklahoma, except where the failure to be so qualified would not reasonably be expected to have a Material Adverse Effect.

7.2Authorization. Seller has full power and authority to enter into and, subject to the entry of the Sale Order (and provided no stay exists with respect thereto), perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by Seller of this Agreement have been, and each Transaction Document to which it is or will be a party will be, duly and validly authorized and approved by all necessary limited liability company action on the part of Seller. This Agreement is, and each Transaction Document to which Seller is or will be a party when executed and delivered by Seller will be, subject to requisite Bankruptcy Court approval following the filing of the Chapter 11 Cases, the valid and binding obligation of Seller and enforceable against Seller in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar Laws affecting the rights of creditors generally.

7.3No Conflicts. Except as set forth on Schedule 7.3, and assuming the receipt of all consents (including any Consent) required to effect the transactions contemplated herby and the waiver of all Preferential Purchase Rights (if any) applicable to the transactions contemplated hereby the execution, delivery and performance by Seller of this Agreement and each Transaction Document to which it is or will be a Party and the consummation of the transactions contemplated herein and therein do not and will not in any material respect (a) conflict with or result in a breach of any provisions of the organizational documents or other governing documents of Seller or (b) subject to the entry of the Sale Order (and provided no stay exists with respect thereto), result in a default or give rise to any right of termination, cancellation or acceleration or, except for Permitted Encumbrances, result in the creation of any Encumbrance under any of the terms, conditions or provisions of any Applicable Contract, note, bond, mortgage or indenture to which Seller is a party or by which Seller or any of the Assets may be subject or bound or (c) subject to the entry of the Sale Order (and provided no stay exists with respect thereto), violate any Law applicable to Seller or any of the Assets, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a Material Adverse Effect.

7.4Consents. To Seller’s Knowledge, except (a) as set forth in Schedule 7.4, (b) for Preferential Purchase Rights, (c) under Contracts that are terminable without cost upon not greater than sixty (60) days’ notice, (d) for Customary Post Closing Consents and (e) for compliance with the HSR Act, if applicable, after giving effect to the entry of the Sale Order (and provided no stay exists with respect thereto) there are no consents to assignment, prohibitions on assignments or requirements to obtain consents from any Third Party (in each case) that are required in connection with the consummation of the transactions contemplated by this Agreement (and the Instruments of Conveyance) by Seller or any of its Affiliates (each, a “Consent”).

7.5Foreign Person. Seller (or, if Seller is an entity disregarded as separate from any other Person within the meaning of Section 301.7701-3(a) of the Treasury Regulations, Seller’s regarded owner) is not a “foreign person” within the meaning of either Section 1445 or Section 1446(f) of the Code.

7.6Claims and Litigation. Except as set forth on Schedule 7.6, as of the Execution Date, there is no lawsuit, action, administrative or arbitration proceeding or litigation by any Person by or before any Governmental Authority or arbitrator, pending or, to Seller’s Knowledge, threatened in writing against Seller with respect to the Assets or which questions the validity of this Agreement or which could reasonably be likely to materially impair the ability of Seller to consummate the transactions contemplated hereby. For purposes of this Section 7.6, “threatened” shall mean that a Third Party has stated in writing the intention to pursue legal recourse against Seller.

7.7Material Contracts.

(a)To Seller’s Knowledge, Schedule 7.7(a) sets forth all Applicable Contracts of the type described below as of the Execution Date (collectively, the “Material Contracts”):

(i)any Applicable Contract that is a Hydrocarbon purchase and sale, transportation, gathering, treating, processing or similar Contract that is not terminable without penalty on ninety (90) days’ or less notice;

(ii)any Applicable Contract that constitutes a lease under which Seller is the lessor or the lessee of real or personal property that (A) cannot be terminated by Seller without penalty upon thirty (30) days’ or less notice and (B) involves an annual base rental of more than $50,000;

(iii)any Applicable Contract that is an indenture, mortgage, loan, credit agreement, sale-leaseback, guaranty of any obligation, bond, letter of credit or similar financial Contract (a “Debt Instrument”);

(iv)any Applicable Contract for the sale, lease or exchange, of Seller’s interest in the Assets;

(v)any Applicable Contract that can reasonably be expected to result in (A) aggregate payments by or on behalf of Seller or (B) aggregate revenues paid to Seller, in each case, of more than $200,000 during the current or any subsequent fiscal year or $500,000in the aggregate over the term of such Applicable Contract (in each case, based solely on the terms thereof);

(vi)any Applicable Contract between Seller and any Affiliate of Seller that will be binding on Buyer after the Effective Time;

(vii)any Applicable Contract, the primary purpose of which is to provide indemnity rights;

(viii)any Applicable Contract that (A) contains or constitutes an existing area of mutual interest agreement or (B) includes non-competition restrictions, non-solicitation or no-hire obligations;

(ix)any Applicable Contract that constitutes a partnership agreement or similar Contract (in each case, excluding any Tax partnership agreements); and

(x)any Applicable Contract that is a collective bargaining or other Contracts or agreements with any labor union or labor organization (“CBA”).

(b)Except as set forth on Schedule 7.7(b) or Schedule 7.6, there exist no material defaults under the Material Contracts by Seller or, to Seller’s Knowledge, by any other Person that is a party to such Material Contracts.

7.8No Violation of Laws. Except as set forth on Schedule 7.8, to Seller’s Knowledge, Seller is not in material non-compliance with or in material violation of any applicable Laws (other than Environmental Laws) with respect to the ownership and operation of the Assets.

7.9Preferential Purchase Rights. Except as set forth on Schedule 7.9, there are no preferential purchase rights, rights of first refusal, drag-along rights, tag-along rights or other similar rights that are applicable to the transfer of the Assets in connection with the transactions contemplated hereby (each a “Preferential Purchase Right”) that will not be extinguished pursuant to the Sale Order.

7.10Current Commitments. Schedule 7.10 sets forth, as of the Execution Date, all outstanding authorities for expenditures or other written capital proposals proposed by Seller to any Third Party or proposed by any Third Party to Seller, to conduct operations (“AFEs”) relating to the Assets that are in excess of $50,000 and for which all of the activities anticipated in such AFEs have not been (or that are not reasonably expected to be) completed on or before the Effective Time.

7.11Asset Taxes. To Seller’s Knowledge, except as set forth on Schedule 7.11, (a) all Tax Returns relating to or prepared in connection with material Asset Taxes that are required to be filed by Seller have been timely filed and all such Tax Returns are correct and complete in all material respects, (b) all material Asset Taxes that are or have become due have been timely paid in full, and Seller is not delinquent in the payment of any such Taxes, or, in either case, such Taxes are currently being contested in good faith by Seller, (c) there is not currently in effect any extension or waiver of any statute of limitations of any jurisdiction regarding the assessment or collection of any material Asset Taxes, (d) there are no administrative or judicial proceedings by any taxing authority pending or in progress relating to or in connection with any material amounts of Asset Taxes, (e) all Asset Tax withholding and deposit requirements imposed by applicable Laws with respect to any of the Assets have been satisfied in all material respects, (f) no claim has been made by a Governmental Authority in a jurisdiction where Seller does not file Tax Returns with respect to Asset Taxes that Seller is or may be subject to taxation by that jurisdiction with respect to Asset Taxes and (g) no Asset is subject to any tax partnership agreement or provisions requiring a partnership income tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute.

7.12Brokers’ Fees. Seller has incurred no responsibility, liability or expense, contingent or otherwise, for brokers’ fees or finders’ fees, agent’s commissions or other similar forms of compensation relating to the transactions contemplated by this Agreement or the Transaction Documents for which Buyer or any Affiliate of Buyer shall have any responsibility.

7.13Bonds and Credit Support. Schedule 7.13 lists all Asset Credit Support.

7.14Pipeline Imbalances. To Seller’s Knowledge, Schedule 7.14 sets forth all material Pipeline Imbalances as of the date set forth in such Schedule.

7.15Owned Real Property; Rights of Way.

(a)Schedule 7.15(a) lists the real property owned by Seller and used or held for use in connection with the ownership or operation of the Gathering Systems, the Plant or the Disposal Wells, together with all buildings and other structures, facilities, improvements or fixtures located thereon or attached thereto (the “Owned Real Property”).

(b)Seller has, in all material respects, Good and Defensible Title to all Owned Real Property (regardless of whether or not such Owned Real Property is listed in Schedule 7.15(a)) in fee simple, free and clear of all Encumbrances, other than Permitted Encumbrances.

(c)Schedule 7.15(c) lists all material easements, rights-of-way, surface leases, servitudes, licenses, surface use agreements, crossing rights and other surface or sub surface interests (other than the Owned Real Property and FCC Licenses) or rights held by Seller used or held for use in connection with the ownership or operation of the Gathering Systems, the Plant or the Disposal Wells or which are required for access to the Gathering Systems, the Plant or the Disposal Wells or any Owned Real Property (the “ROW Interests”).

(d)Seller holds the rights granted to it under ROW Interests (regardless of whether such ROW Interests are listed in Schedule 7.15(c)), free and clear of all Encumbrances, other than Permitted Encumbrances.

(e)Except as otherwise set forth on Schedule 7.15(e), (i) all pipelines included in the Assets are located on lands subject to the ROW Interests or on Owned Real Property and (ii) there are no gaps (including any gap arising as a result of any breach by Seller of the terms of any such ROW Interests or Owned Real Property) in such ROW Interests or Owned Real Property, other than, as to clause (i) and clause (ii), as could not reasonably be expected to adversely affect in any material respect the ability of Buyer to own and operate the Gathering Systems, the Plant or the Disposal Wells from and after the Closing in the ordinary course of business as currently conducted by Seller.

(f)There is no pending, or to Seller’s Knowledge, threatened taking (whether permanent, temporary, whole or partial) of any part of the Assets by reason of condemnation, and no such action in condemnation is pending.

(g)Seller is not in default of any ROW Interests, other than any defaults as would not reasonably be expected to result in the loss of any material right under such ROW Interest or adversely affect in any material respect the ability of Buyer to own and operate the Gathering Systems, the Plant or the Disposal Wells from and after the Closing in the ordinary course of business as currently conducted by Seller. Seller has not received any written notice of any alleged or threatened default or termination, under the terms of any ROW Interests that, in each case, would reasonably be expected to result in a material impairment or loss of title to any of the ROW Interests, other than any such impairments that would not reasonably be expected to adversely affect the ability of Buyer to own and operate the Gathering Systems, the Plant or the Disposal Wells from and after the Closing in the ordinary course of business as currently conducted by Seller.

(h)The representations and warranties contained in this Section 7.15 are the only representations and warranties being made with respect to real property, including Real Property Permits.

7.16Insurance. Schedule 7.16 sets forth a true and complete list and description of all insurance policies in force with respect to the Assets as of the Execution Date (the “Applicable Policies”).

7.17Personal Property. To Seller’s Knowledge, all equipment used or held for use in connection with the Assets, has been maintained in working order and operating condition in all material respects and is adequate for normal operation of the Assets in all material respects consistent with current practices, ordinary wear and tear excepted.

7.18Permits. To Seller’s Knowledge, (a) all necessary Permits with respect to the ownership or operation of the Gathering Systems, the Plant, and the Disposal Wells within the five (5)-year period prior to the Execution Date have been obtained and maintained by Seller and (b) there exists no material uncured violation of the terms and provisions of any such Permits. Neither Seller nor its Affiliates has received any written notice of from a Governmental Authority claiming the lack of a Permit or default under any Permit with respect to any Asset operated by Seller or its Affiliate.

7.19Environmental Matters.

(a)Except as set forth in Schedule 7.19(a) and any such failure to comply or obtain solely to the extent such failure would give rise to an Excluded Liability and not materially interfere with or prevent material compliance by Buyer after the Closing with any Environmental Law or the terms of any Environmental Permits issued pursuant thereto in connection with the ownership and operation of the Assets, Seller is and (to Seller’s Knowledge with respect to any portion of such five (5)-year period prior to the date Seller acquired the Assets) within the five (5)-year period prior to the Execution Date has been in compliance in all material respects with all applicable Environmental Laws with respect to the ownership and operation of the Assets and has obtained and is and (to Seller’s Knowledge with respect to any portion of such five (5)-year period prior to the date Seller acquired the Assets) within the five (5)-year period prior to the Execution Date has been in compliance with all material Environmental Permits required under applicable Law in connection with the ownership and operation of the Assets.

(b)(i) with respect to the Assets, Seller (or, to Seller’s Knowledge, any other Person to the extent giving rise to Liability for Seller) has not Released, transported, treated or stored or, to Seller’s Knowledge, exposed any Person to any Hazardous Materials and (ii) Seller has not received written notice from any Person of any Release or exposure of any Person to Hazardous Materials concerning any of the Assets in each case of (i) or (ii) that would (A) materially interfere with or prevent material compliance by Seller with any applicable Environmental Law or the terms of any Environmental Permits issued pursuant thereto or (B) result in any material Liability of Seller (other than Excluded Liabilities) to any Person under applicable Environmental Law.

(c)There are no Environmental Conditions that would reasonably likely result in any material Environmental Liability (other than Excluded Liabilities).

(d)Each Disposal Well drilled by Seller and, to Seller’s Knowledge, each Disposal Well drilled by an Affiliate of Seller or a Third Party, has been drilled, constructed, cased, and completed in accordance in all material respects with all applicable Laws, including Environmental Laws.

(e)The representations and warranties contained in Section 7.18 and this Section 7.19 are the only representations and warranties being made with respect to compliance with or liability under Environmental Laws or with respect to any Environmental Condition or any environmental or occupational health and safety matter, including natural resource.

7.20FCC Matters. Schedule 7.20 sets forth a true and complete list of all FCC Licenses held by Seller primarily for use in connection with the ownership or operation of the Gathering Systems or Plant (the “Applicable FCC Licenses”). For each Applicable FCC License, Schedule 7.20 sets forth (a) name of the licensee, (b) the FCC call sign, (c) the authorized channel(s), (d) the geographic area of authorization and (e) the date of original issuance or, if applicable, last renewal. Except for Permitted Encumbrances, all FCC Licenses are owned by the applicable licensee free and clear of all Encumbrances. There is no proceeding pending before the FCC or, to Seller’s Knowledge, threatened, with respect to any Applicable FCC License.

7.21Labor and Employment.

(a)Seller (with respect to the Assets and the Business Employees) is neither party to, nor bound by, any CBA; there are no CBAs or any other any labor-related agreements or arrangements that pertain to any Business Employees; and no Business Employees are represented by any labor union or other labor organization with respect to their employment with Seller. To Seller’s Knowledge, in the past three (3) years, there have been no labor organizing activities with respect to any Business Employees or relating to or affecting the Assets. In the past three (3) years, there has been no actual or, to Seller’s Knowledge, threatened in writing unfair labor practice charges, material grievances, labor-related grievances or arbitrations, strikes, lockouts, work stoppages, slowdowns, picketing, hand billing or other material labor disputes against or affecting Seller (with respect to the Assets or Business Employees).

(b)Seller (with respect to the Assets and the Business Employees) is, and for the last three (3) years has been, in compliance in all material respects with all applicable Laws respecting labor, employment and employment practices.

7.22Benefit Plans. Neither Seller nor any of its Affiliates has any, or is reasonably expected to have any, current or contingent liability or obligation: (i) under Title IV of ERISA; or (ii) on account of at any time being considered a single employer under Section 414 of the Code with any other Person. No Liability under Section 302 or Title IV of ERISA has, during the immediately preceding six (6) years, been incurred by any of Seller, its Affiliates or any of their respective ERISA Affiliates or their respective predecessors that has not been satisfied in full, and no condition exists that presents a risk to any of Seller, its Affiliates or any such ERISA Affiliate of incurring any such Liability.

ARTICLE VIIIBUYER REPRESENTATIONS AND WARRANTIES

Buyer represents and warrants to Seller the following:

8.1Organization; Existence. Buyer is a limited liability company, duly formed, validly existing and in good standing under the Laws of the State of Delaware and has all requisite power and authority to own and operate its property and to carry on its business as now conducted. Buyer is duly licensed or qualified to do business as a foreign limited liability company in Oklahoma.

8.2Authorization. Buyer has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery, and performance by Buyer of this Agreement have been, and of each Transaction Document to which it is or will be a party will be, duly and validly authorized and approved by all necessary limited liability company action on the part of Buyer. This Agreement is, and each Transaction Document to which Buyer is or will be a party when executed and delivered by Buyer will be, the valid and binding obligation of Buyer and enforceable against Buyer in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws affecting the rights of creditors generally.

8.3No Conflicts. The execution, delivery, and performance by Buyer of this Agreement and each Transaction Document to which it is or will be a Party and the consummation of the transactions contemplated herein and therein will not in any material respect (a) conflict with or result in a breach of any provisions of the organizational or other governing documents of Buyer or (b) result in a default or give rise to any right of termination, cancellation or acceleration or result in the creation of any Encumbrance under any of the terms, conditions or provisions of any note, bond, mortgage or indenture to which Buyer is a party or by which Buyer or any of its property may be subject or bound or (c) violate any Law applicable to Buyer or any of its property, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement or the Transaction Documents to which it is or will be a Party or perform its obligations hereunder or thereunder.

8.4Consents. Except (a) as set forth in Schedule 8.4, (b) for Customary Post Closing Consents and (c) for compliance with the HSR Act, if applicable, there are no consents, approvals, authorizations or other restrictions on assignment, including requirements for consents from Third Parties to any assignment, that are required or would be applicable in connection with the consummation of the transactions contemplated by this Agreement or any Transaction Document by Buyer.

8.5Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s Knowledge, threatened against Buyer or any Affiliate of Buyer, and Buyer is not insolvent or generally not paying its debts when they become due.

8.6Claims and Litigation. There is no lawsuit, action, administrative or arbitration proceeding or litigation by any Person by or before any Governmental Authority or arbitrator, pending, or to Buyer’s Knowledge, threatened in writing against Buyer or any of its Affiliates that would have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement. For purposes of this Section 8.6, “threatened” shall mean that a Third Party has stated in writing the intention to pursue legal recourse against Buyer or any of its Affiliates.

8.7Regulatory. As of the Closing Date, Buyer (or, if applicable, Buyer’s operating Affiliate) shall be qualified under all applicable Laws to own, operate and hold the Assets, and the consummation of the transactions contemplated in this Agreement will not cause Buyer (or, if applicable, Buyer’s operating Affiliate) to be disqualified as such an owner, operator or lessee. To the extent required by any applicable Laws, as of the Closing Date, Buyer (or, if applicable, Buyer’s operating Affiliate) (a) will have lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, all applicable Laws governing the ownership of the Assets, including those set forth on Schedule 7.13 and (b) will have filed any and all required reports necessary for such ownership or lease with all Governmental Authorities having jurisdiction over such ownership or lease, in each case of (a) and (b), except where the failure to do so would not have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement.

8.8Financing.

(a)Buyer shall have as of the Closing Date, sufficient cash with which to pay the Purchase Price; and Buyer has, or will have, sufficient cash to pay on a timely basis all costs required to be paid by Buyer under this Agreement and the Applicable Contracts as and when due from and after the Closing. Each Commitment, when delivered to Seller pursuant to Section9.13, will be a legal, valid and binding obligation of Buyer and, to the Knowledge of Buyer, the other parties thereto, in full force and effect, and enforceable against the parties thereto in accordance with its terms, subject to the effect of bankruptcy, insolvency, reorganization, moratorium and similar Laws affecting the rights of creditors generally.

(b)On January 17, 2020, Buyer furnished to Seller an accurate and complete copy of the Commitment Documentation as amended on the A&R Execution Date in an amount equal to at least $315,000,000 in the aggregate (the “Required Amounts”). The obligations of the Commitment Parties to fund the financing contemplated by the Commitment are not subject to any conditions or other contingencies related to the funding of the full Required Amounts other than as set forth in the Commitment Documentation. The Commitment Documentation constitutes the entire and complete agreement between the Commitment Parties with respect to the Commitment. Notwithstanding the foregoing, Buyer’s ability to consummate the transactions contemplated hereby is not contingent upon its ability to secure any financing (including the financing contemplated by the Commitment) or to complete any public or private placement of securities prior to or upon Closing.

8.9Independent Evaluation. Buyer is sophisticated in the evaluation, purchase, ownership and operation of midstream assets and related facilities, including assets similar to the Assets. In making its decision to enter into this Agreement and the Transaction Documents to which it is or will be a Party and to consummate the transaction contemplated hereby and thereby, except to the extent of Seller’s express representations and warranties in Article VII, Buyer has relied or shall rely on its own independent investigation and evaluation of the Assets, which investigation and evaluation was done by Buyer and its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors. In entering into this Agreement, Buyer acknowledges that it has relied solely upon the aforementioned investigation and evaluation and not on any factual representations or opinions of Seller or any representatives or consultants or advisors engaged by or otherwise purporting to represent Seller or any Affiliate of Seller (except the specific representations and warranties of Seller set forth in Article VII). Buyer hereby acknowledges that, other than the representations and warranties made in Article VII, neither Seller nor any representatives, consultants or advisors of Seller or its Affiliates make or have made any representation or warranty, express or implied, at Law or in equity, with respect to the Assets.

8.10Brokers’ Fees. Buyer has incurred no responsibility, liability or expense, contingent or otherwise, for brokers’ fees or finders’ fees, agent’s commissions or other similar forms of compensation relating to the transactions contemplated by this Agreement or the Transaction Documents for which Seller or Seller’s Affiliates shall have any responsibility.

8.11Accredited Investor. Buyer is an accredited investor, as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Assets for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws.

ARTICLE IXCERTAIN AGREEMENTS

9.1Conduct of Business. Except (u) for renewal of expiring insurance coverage in the ordinary course of business, (v) as set forth on Schedule 9.1, (w) for the operations covered by the capital commitments described on Schedule 7.10, (x) for emergency operations, (y) as required to comply with any applicable Laws (including by order or directive of the Bankruptcy Court or fiduciary duty of the boards of managers (or similar governing bodies) of Seller) or any requirements or limitations resulting from the Chapter 11 Cases, and (z) as expressly contemplated by this Agreement or expressly consented to in writing by Buyer:

(a)Seller agrees that from and after the Execution Date until Closing, Seller will:

(i)subject to any interruptions resulting from force majeure, mechanical breakdown and planned maintenance, maintain the Assets in the usual, regular and ordinary manner consistent with past practice;

(ii)maintain the books of account and Records relating to the Assets in the usual, regular and ordinary manner, in accordance with its usual accounting practices;

(iii)give written notice to Buyer as soon as is practicable of any material damage or casualty to or destruction or condemnation of any of the Assets of which Seller has Knowledge;

(iv)use commercially reasonable efforts to pay or cause to be paid all Operating Expenses and other payments incurred with respect to the Assets consistent with past practice;

(v)maintain insurance coverage on the Assets in the amounts and types described in Schedule 7.16; and

(vi)give prompt notice (and in any event within one (1) Business Day of receipt of written notice from any Third Party) to Buyer of any emergency requiring immediate action, or any emergency action taken, in the face of serious risk to life, property or the environment (including prevention of environmental contamination).

(b)Seller agrees that from and after the Execution Date until Closing, Seller will not:

(i)except for capital projects and expenditures set forth on Schedule 7.10 or undertaken as a result of any order of a Governmental Authority, incur or commit to any capital expenditure with respect to the Assets that is reasonably expected to result in expenditures greater than $150,000;

(ii)enter into any Applicable Contract that if entered into on or prior to the Execution Date, would be required to be listed on Schedule 7.7(a);

(iii)terminate (unless such instrument terminates pursuant to its express terms) or materially amend the terms of any Permit or Assigned Contract (or any Material Contract that could become an Assigned Contract);

(iv)transfer, sell, mortgage or pledge any of the Assets, other than sales of obsolete equipment that is no longer necessary in the operation of the Assets or for which replacement equipment has been obtained;

(v)settle any suit or litigation or waive any material claims, in each case, attributable to the Assets and affecting the period after the Effective Time;

(vi)grant or create any right to Consent to the disposition of, or Preferential Purchase Rights with respect to, any of the Assets;

(vii)unless required by Law, (A) enter into, amend, extend or terminate any CBA or (B) recognize or certify any labor union, labor organization or group of employees as the bargaining representative for any Business Employees;

(viii)terminate (other than for cause) any Business Employee or reassign the duties of (A) a Business Employee such that he or she is no longer a Business Employee or (B) any other employee of Seller such that he or she would be a Business Employee; or

(ix)authorize, agree or commit to do any of the foregoing.

For the avoidance of doubt, the pendency of the Chapter 11 Case and the effects thereof, including any actions required to be taken by Seller pursuant to an order of the Bankruptcy Court in connection with the Chapter 11 Cases, shall in no way be deemed a breach of this Section 9.1(b).

9.2Bonds. Buyer acknowledges that none of Asset Credit Support will be transferred to Buyer. At or prior to Closing, Buyer shall obtain, or cause to be obtained in the name of Buyer (or, if applicable, Buyer’s operating Affiliate), replacements for such Asset Credit Support (in each case, insofar and only to the extent related to or necessary under an Assigned Contract or as required under applicable Law) to the extent such replacements are necessary (i) to consummate the transactions contemplated by this Agreement and/or (ii) to permit the cancellation of such Asset Credit Support posted by Seller or any of its controlled Affiliates. In addition, at or prior to Closing, Buyer shall deliver to Seller evidence of Buyer’s posting of bonds or other security necessary to replace the Asset Credit Support listed on Schedule 7.13, in each case, insofar as and only to the extent related to or necessary under an Assigned Contract or as required under applicable Law. At or prior to Closing, Buyer shall use commercially reasonable efforts to cooperate with Seller and cause the cancellation of such Asset Credit Support, including (i) any gross production tax bond in favor of the Oklahoma Tax Corporation and (ii) discussions with PEPL to ensure the return of Asset Credit Support provided by or on behalf of Seller or its Affiliates under any PEPL Contract. Notwithstanding anything to the contrary herein, in no event shall the PEPL Contract be an Assigned Contract unless any Asset Credit Support provided by or on behalf of any Seller or Affiliate of Seller in connection with such Applicable Contract is returned to Seller at or prior to Closing.

9.3Notifications. If, prior to Closing, either Seller or Buyer obtains Knowledge that the other Party has breached a representation, warranty, covenant, obligation or other agreement under this Agreement, then Seller or Buyer, as applicable, shall promptly inform such other Party of such breach so that such other Party may attempt to remedy or cure such breach prior to Closing; provided that, such notice shall not be deemed and shall not constitute a waiver of any claim or recourse against the other Party or its Affiliates (including any claim for indemnity) with respect to any breach by such other Party of such other Party’s representations, warranties, covenants, obligations or other agreements, and shall not in any way preclude the right of any Party to rely on the representations and warranties of the other Party given in this Agreement or in the certificates delivered by such Party at Closing pursuant to this Agreement.

9.4RESERVED.

9.5Equitable and Other Remedies. The Parties agree that damages may not be a sufficient remedy to any breach of the provisions of Section 4.2, Section 9.6, Section 14.3, Section 16.6 or Section 16.8 of this Agreement and the non-breaching Party may be irreparably and immediately harmed if any of such provisions of this Agreement are not performed by the other Party or its Affiliates (as applicable) strictly in accordance with their respective terms. In the event of a breach of any of the above listed provisions, the non-breaching Party shall provide written notice and a demand to cease or cure any such breach; provided that, in the event such breach (a) is not susceptible to cure or (b) if susceptible to being cured, has not been cured within five (5) days after delivery of such written notice thereof to the breaching Party, the non-breaching Party shall have the right, in addition to any other rights such Party may have, to obtain injunctive relief, without the posting of any bond and without proof of actual damages, to restrain any breach or any anticipated or threatened breach by the other Party or obtain specific enforcement of such terms. Such remedy shall not be deemed to be the exclusive remedy for such breach of this Agreement, but shall be in addition to all of the remedies at Law or in equity available to the non-breaching Party.

9.6Record Retention. Buyer, for a period of seven (7) years following Closing, will (a) retain the Records, (b) provide Seller, its Affiliates, and its and their officers, employees and representatives with reasonable access to the Records during normal business hours for review and copying, and (c) provide Seller, its Affiliates and its and their officers, employees and representatives with access, during normal business hours, to materials received or produced after the Closing relating to any indemnity claim made under Section 13.1(b); provided that Buyer may destroy Records from time to time and prior to the end of such period in accordance with its normal document retention policy as long as Buyer notifies Seller at least thirty (30) days in advance and provides Seller an opportunity to remove or copy such Records.

9.7Permits; Operatorship.

(a)Buyer agrees that it shall be Buyer’s responsibility to obtain the issuance or transfer of all Permits necessary for the operation of the Assets after the Closing; provided, however, that Seller shall use commercially reasonable efforts to cooperate with Buyer’s reasonable efforts to obtain the transfer of such permits held by Seller (to the extent transferable) at the sole expense of Buyer.

(b)Upon the Closing, Buyer shall assume all responsibilities of the operator of record of the Assets including for all operations, maintenance, repair, expansion and management activities (including all emergency response and regulatory compliance).

(c)As soon as practicable after the Closing, Buyer shall file all such forms necessary to assume the duties of operator of record of the Gathering Systems and the Disposal Wells, as applicable, effective as of the Closing.

9.8HSR Act. If applicable, within ten (10) Business Days following the execution by Buyer and Seller of this Agreement, Buyer and Seller will each prepare and simultaneously file with the DOJ and the FTC the notification and report form required by the HSR Act for the transactions contemplated by this Agreement, and request early termination of the waiting period thereunder. Buyer and Seller agree to respond promptly to any inquiries from the DOJ or the FTC concerning such filings and to comply in all material respects with the filing requirements of the HSR Act. Buyer and Seller shall cooperate with each other and, subject to the terms of the Confidentiality Agreement, shall promptly furnish all information to the other Party that is necessary in connection with Buyer’s and Seller’s compliance with the HSR Act. To the extent required by applicable Law, Buyer and Seller shall keep each other fully advised with respect to any requests from or material communications with the DOJ or FTC concerning such filings, and to the extent reasonably practicable, and shall consult with each other with respect to all responses thereto. Each of Seller and Buyer shall use its commercially reasonable efforts to take all actions reasonably necessary and appropriate in connection with any HSR Act filing to consummate the transactions consummated hereby as promptly as practicable; notwithstanding any other provision of this Agreement, the Parties’ commercially reasonable efforts shall not include (i) entering into any settlement, undertaking, consent decree, stipulation or agreement with the DOJ or FTC in connection with the transactions contemplated by this Agreement; (ii) litigating, challenging or taking any other action with respect to any judicial or administrative action or proceeding by the DOJ or FTC in connection with the transactions contemplated by this Agreement; (iii) contesting, resisting, and seeking to have vacated, lifted, reversed or overturned any order that is in effect that prohibits, prevents or restricts the consummation of the transactions contemplated by this Agreement; (iv) divesting, licensing, or otherwise holding separate, or taking any other action (or otherwise agreeing to do any of the foregoing) with respect to any party’s or its respective Affiliates’ businesses, assets, or properties. Any fees paid to Third Parties related to filings required by this Section 9.8 shall be paid by the Buyer.

9.9Bankruptcy Court Approval; Bidding Procedures.

(a)Buyer and Seller acknowledge that this Agreement and the sale of the Assets and assumption and assignment of the Assigned Contracts are subject to Bankruptcy Court approval. Buyer and Seller acknowledge that (i) to obtain such approval and to satisfy Seller’s fiduciary duties to all applicable stakeholders in accordance with applicable Law, Seller must demonstrate that it has taken reasonable steps to obtain the highest or otherwise best offer possible for the Assets, and that such demonstration shall include giving notice of the transactions contemplated by this Agreement to creditors and other interested parties, including as may be ordered by the Bankruptcy Court and, if necessary, conducting the Auction and (ii) Buyer must provide adequate assurance of future performance as required under the Bankruptcy Code with respect to each Assigned Contract.

(b)Buyer agrees and acknowledges that Seller, including through its representatives, is and may continue soliciting and responding to inquiries, proposals or offers from Third Parties for all or any part of the Assets, as contemplated by the Bidding Procedures and Supplemental Bidding Procedures Order and such actions shall not be a breach or violation of this Agreement.

9.10Bankruptcy Proceedings.

(a)From and after commencement of the Chapter 11 Cases, Seller shall take such actions as may be reasonably necessary to obtain entry of the Sale Order, and Buyer shall reasonably cooperate with Seller in connection therewith, including filing any reasonably necessary affidavits in support of entry of the Sale Order. Seller and Buyer shall take such actions as may be reasonably necessary to consummate the transactions contemplated by this Agreement, in each case, in accordance with this Agreement; provided that, in the case of Seller, any such actions shall be subject to the fiduciary duties of the Board of Directors.

(b)To the extent not otherwise set forth in the Sale Order, Seller shall take such actions as may be reasonably necessary to obtain entry of a Final Order approving release and exculpation provisions substantially in the form attached hereto as Exhibit N.

(c)Except as provided herein or permitted hereby, from and after the Execution Date and prior to the Closing or the termination of this Agreement in accordance with Section 14.1, Seller shall not take any action which is intended to (or is reasonably likely to), or fail to take any action the intent (or the reasonably likely result) of which failure to act is to, result in the reversal, voiding, modification or staying of the Supplemental Bidding Procedures Order or this Agreement. If Buyer is the Successful Bidder at the Auction, Seller shall not take any action which is intended to (or is reasonably likely to), or fail to take any action the intent (or the reasonably likely result) of which failure to act is to, result in the reversal, voiding, modification or staying of the Sale Order or this Agreement.

(d)Seller agrees to provide Buyer and its counsel with copies of the Sale Order, the Supplemental Bidding Procedures Order and the Plan (to the extent it provides for the sale of the Assets pursuant to this Agreement), which shall be in form and substance reasonably acceptable to Seller and Buyer, prior to the filing of such documents and shall provide Buyer, to the extent practicable, with a reasonable opportunity to review and comment on same. Seller shall also provide Buyer with any and all material pleadings, motions, notices, statements, applications, schedules, reports, and other papers to be filed or submitted by any Seller Party related to this Agreement for Buyer’s prior review.

(e)Seller and Buyer agree that, in the event that Buyer is not the Successful Bidder pursuant to the Supplemental Bidding Procedures Order, if and only if (i) Buyer is chosen as the Backup Bidder and (ii) Seller gives notice to Buyer as soon as reasonably practicable after the date Seller fails to consummate a sale of the Assets to the Successful Bidder and in any event prior to the Back-Up Termination Date, stating that Seller (A) failed to consummate the sale with the winning bidder, and (B) terminated the purchase agreement with the winning bidder, Buyer shall promptly consummate the transactions contemplated by this Agreement upon the terms and conditions as set forth herein, including (without limitation) the Purchase Price and the conditions to Closing set forth in Article X, as the same may be revised by Seller and Buyer at the Auction; provided that Buyer shall not be required to serve as Backup Bidder if the Successful Bids (as defined in the Bidding Procedures) does not contemplate acquisition of all or substantially all of the assets of both AMH and KFM.

(f)Seller shall apply the Deposit to the Purchase Price or return the Deposit to Buyer (as applicable) in accordance with the Supplemental Bidding Procedures Order and the Bidding Procedures (including the section of the Bidding Procedures titled “Return of Good Faith Deposit”, mutadis mutandis). Any instructions provided by Seller to Escrow Agent in respect of the Deposit shall be consistent with the Bidding Procedures, and this Section 9.10(f), in all respects.

9.11Certain Litigation Matters. At the Auction, Buyer notified Seller that it desired that all of the matters identified on Schedule 7.6 be Excluded Liabilities, and all such matters shall be Excluded Liabilities for all purposes of this Agreement.

9.12RESERVED.

9.13Financing.

(a)From and after the A&R Execution Date until Closing:

(i)Buyer shall use its reasonable best efforts to obtain the financing under the Commitment required to effect the transactions contemplated by this Agreement as promptly as practicable, including, without limitation, (1) using reasonable best efforts to (A) maintain in effect the Commitment Documentation, (B) satisfy on a timely basis all terms, covenants and conditions set forth in the Commitment, (C) enter into definitive agreements with respect thereto on the terms and conditions contemplated by the Commitment Documentation and (D) consummate such financing at or prior to Closing and (2) seeking to enforce its rights under the Commitment.

(ii)Upon Seller’s reasonable request, Buyer shall keep Seller reasonably informed with respect to all material activity concerning the status of the financing contemplated by the Commitment and shall give Seller prompt notice of any adverse change with respect to such financing. Without limiting the foregoing, Buyer agrees to notify Seller promptly if at any time, prior to the Closing Date, (1) any Commitment shall expire or be terminated for any reason, (2) any financing source that is a party to any Commitment notifies Buyer that such source no longer intends to provide financing to Buyer on the terms set forth therein, or (3) for any reason Buyer no longer believes in good faith that it will be able to obtain all or any portion of the financing contemplated by the Commitment on the terms described therein.

(iii)Buyer shall not permit any amendment, supplement or modification to be made to, or any waiver of any provision under, the Commitment Documentation if such amendment, supplement, modification or waiver, (A) reduces (or could reasonably be expected to have the effect of reducing) the aggregate amount of the financing, or (B) imposes new or additional conditions or otherwise expands, amends or modifies any of the conditions to the Commitment, or imposes new or additional conditions or otherwise expands, amends or modifies any other provision of the Commitment Documentation, in case of clause (B), in a manner that would (x) reasonably be expected to prevent or make less likely the funding of the Commitment in an amount necessary to fund the Required Amounts on the Closing Date or (y) adversely impact the ability of Buyer to enforce its rights against other parties to the Commitment Documentation with respect thereto (provided that, subject to compliance with the other provisions of this Section 9.13, Buyer may amend the Commitment Documentation to add additional lenders, arrangers, bookrunners and agents). Buyer shall promptly deliver to Seller copies of any amendment, supplement, waiver, consent, modification or replacement in respect of the Commitment Documentation (other than an amendment to add additional lenders, arrangers, bookrunners and agents). Buyer shall not agree to the withdrawal, termination, repudiation, reduction or rescission of any commitment in respect of the Commitment, and shall not release or consent to the termination of the obligations of the financing sources under the Commitment, in each case, without the prior written consent of Seller, to the extent such withdrawal, termination, repudiation, reduction or rescission is in an amount such that the net proceeds of the Commitment would not be in an amount sufficient to fund the Required Amounts at Closing after giving effect thereto. For purposes of this Agreement, (i) references to “Commitment” and “Commitment Documentation” shall include the financing contemplated by the Commitment Documentation as permitted to be amended, modified, supplemented or replaced by this Section 9.13.

(iv)If any portion of the financing becomes unavailable in the amount contemplated in any Commitment or any Commitment shall be terminated or modified in a manner materially adverse to Buyer for any reason, Buyer shall use its reasonable best efforts to obtain alternative financing from alternative sources in an amount sufficient to enable Buyer to perform its obligations under, and to consummate the transactions contemplated by, this Agreement and to obtain, and, if obtained, will provide Seller with a copy of, a new financing commitment that provides for at least the same amount of financing as the Commitment as originally issued, to the extent needed to fund the Required Amounts, and on terms and conditions (including termination rights and funding conditions) not materially less favorable to Buyer than those included in the Commitment (the “New Commitment”). To the extent applicable, Buyer shall use reasonable best efforts to obtain the alternative financing as set forth in the New Commitment as promptly as practicable, including, without limitation, (1) using reasonable best efforts to (A) satisfy on a timely basis all terms, covenants and conditions set forth in the New Commitment, (B) enter into definitive agreements with respect thereto on the terms and conditions contemplated by the New Commitment and (C) consummate such financing at or prior to Closing and (2) seeking to enforce its rights under the New Commitment (including through litigation). In the event alternative financing is obtained and a New Commitment is entered into, references in this Agreement to the Commitment shall be deemed to refer to the New Commitment, and references in this Agreement to the financing under the Commitment shall be deemed to refer to the alternative financing under the New Commitment, in each case as applicable.

(b)Prior to the Closing Date, Seller shall use, and shall cause each of its controlled Affiliates to use, and shall use reasonable best efforts to have each of its and its controlled Affiliates’ respective directors, officers and advisors to use, in each case, their respective reasonable best efforts to provide to Buyer, all cooperation reasonably necessary and customary in connection with the arrangement of the Commitment (provided that such requested cooperation does not unreasonably interfere with the ongoing operations of Seller or its controlled Affiliates), which reasonable best efforts shall include (i) upon reasonable notice, and at reasonable times and locations to be mutually agreed, causing the management teams of Seller and its controlled Affiliates with appropriate seniority and expertise and external auditors to participate in a reasonable number of meetings, drafting sessions, presentations, road shows, and rating agency and due diligence sessions, (ii) assisting with the preparation of (A) offering documents, private placement memoranda, bank information memoranda, prospectuses and similar documents reasonably necessary in connection with the Commitment and (B) materials for rating agency presentations, (iii) executing customary authorization letters or management representation letters, as applicable, (iv) furnishing Buyer reasonably promptly with the financial statements which are necessary to satisfy the conditions set forth in the Commitment Documentation as and when it becomes available, (v) assisting with the preparation of any pledge and security documents, guarantees, other definitive financing documents, or other related certificates or documents as may be reasonably requested by Buyer and otherwise facilitating the pledging of collateral to the extent required at Closing by the Commitment Documentation (including cooperation in connection with the pay-off at Closing of existing Indebtedness and the release, following such repayment, of related Liens and termination, following such repayment, of security interests (including delivering prepayment or termination notices as required), and (vi) to the extent requested at least ten (10) Business Days prior to the Closing Date, providing, at least three (3) Business Days prior to the Closing Date, all documentation with respect to Seller and its controlled Affiliates required by applicable “know your customer” and anti-money laundering applicable Laws, including the USA PATRIOT Act, to the extent requested in writing at least ten Business Days prior to the Closing Date; provided, however, that Seller shall not be required to provide, or cause its controlled Affiliates to provide, cooperation under this Section 9.13 that: (A) unreasonably interferes with the ongoing business of Seller or its controlled Affiliates; (B) causes any covenant, representation or warranty in this Agreement to be breached or otherwise causes the breach of this Agreement or any Contract to which the any of Seller or its controlled Affiliates is a party, in each case, in a manner that would cause any closing condition set forth herein to fail to be satisfied; (C) requires Seller or its controlled Affiliates to incur any liability (including, without limitation, any commitment fees and expense reimbursement) in connection with the Commitment (other than the authorization letters and management representation letters) prior to, or that are not conditioned upon, the Closing; (D) requires Seller or its controlled Affiliates or their respective directors, officers, managers or employees (other than execution and delivery into escrow by those officers that will act in a similar capacity after the Closing) to execute, deliver or enter into, or perform any agreement, document, certificate or instrument with respect to the Commitment (other than with respect to the authorization letters and management representation letters) or adopt resolutions approving the agreements, documents and instruments pursuant to which the Commitment is obtained; or (E) requires Seller or its controlled Affiliates to provide any information that is prohibited or restricted by applicable Law or applicable confidentiality undertaking or that constitutes privileged information or attorney-client work product, to the extent Seller and its controlled Affiliates uses reasonable best efforts to provide such information in a manner that does not breach such undertaking, obligation or privilege.

(c)Buyer shall promptly, upon request by any Seller, reimburse Seller for all reasonable out-of-pocket costs and expenses incurred by Seller in connection with the Commitment, including the cooperation contemplated by this Section 9.13 and shall indemnify and hold harmless Seller and its representatives from and against any and all liabilities, losses, damages, claims, costs, expenses (including reasonable attorney’s fees), interest, awards, judgments and penalties of any kind imposed on, sustained, suffered or incurred by, or asserted against, any of them, directly or indirectly, relating to, arising out of or resulting from the Commitment, any cooperation pursuant to this Section 9.13 and/or the provision of information utilized in connection therewith, except to the extent arising out of gross negligence, or willful misconduct of Seller, in each case, whether or not the Closing occurs.

(d)Seller hereby consents to the use of its and its controlled Affiliates’ logos in connection with the Commitment; provided that such logos are used solely in a manner that is not intended to or reasonably likely to harm or disparage Seller or any of its controlled Affiliates or the reputation or goodwill of the Company or any of its controlled Affiliates.

9.14Material Contracts. Seller shall use commercially reasonable efforts to deliver to Buyer as promptly as possible after the Execution Date, and shall in any event make available to Buyer (electronically or otherwise) within five (5) Business Days after the Execution Date, copies of the Material Contracts, in each case, including any and all amendments and supplements thereto in Seller’s possession.

ARTICLE XBUYER’S CONDITIONS TO CLOSING

The obligations of Buyer to consummate the transactions provided for herein is subject, at the option of Buyer, to the fulfillment by Seller or written waiver by Buyer, on or prior to the Closing of each of the following conditions:

10.1Representations. The representations and warranties of Seller (a) set forth in Article VII (other than the representations and warranties set forth in Section 7.15(a), (b), (c), (d), (e) and (g) and Section 7.19) shall be true and correct as of the Closing Date as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties that in the aggregate would not have a Material Adverse Effect and (b) set forth in Section 7.15(a), (b), (c), (d), (e) and (g) and Section 7.19 shall be true and correct in all material respects (provided that any such representation or warranty that is qualified, in any material respect, in all material respects or by a similar material qualifier shall not be further qualified by “in all material respects” for purposes of this clause (b)) as of the Closing Date as though made on and as of the Closing Date (provided that the failure of any Owned Real Property or ROW Interests, in each case that does not have any associated material Liability that would be an Assumed Obligation, to be listed on Schedule 7.15(a) or Schedule 7.15(c) shall not constitute a failure of the Closing condition in this Section 10.1(b)).

10.2Performance. Seller shall have performed or complied with all material obligations, agreements, and covenants contained in this Agreement (without regard to Seller’s obligations under Section 9.10(b)) and the Sale Order, as to which performance or compliance by Seller is required prior to or at the Closing Date in all material respects.

10.3No Legal Proceedings. No order, injunction or judgment shall have been issued by any Governmental Authority or arbitrator to restrain, prohibit, enjoin or declare illegal the transactions contemplated by this Agreement, and no Law has been promulgated or enacted and is in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated by this Agreement.

10.4Casualty Losses; Consents. The sum of (a) the amount of all uncured, unrestored and uninsured Casualty or Condemnation Losses pursuant to Section 5.1, plus (b) all reductions to the Purchase Price pursuant to Section 5.2 in respect of unobtained Required Consents, shall, in the aggregate, be less than ten percent (10%) of the unadjusted Purchase Price.

10.5Certificate. An authorized officer of Seller shall execute and deliver (or be ready, willing and able to deliver at Closing) a certificate dated as of the Closing Date certifying on behalf of Seller that the conditions set forth in Section 10.1 and Section 10.2 have been fulfilled by Seller.

10.6HSR Act. If applicable, the waiting period under the HSR Act applicable to the consummation of the transactions contemplated hereby shall have expired or been terminated.

10.7Closing Deliverables. Seller shall have delivered (or be ready, willing and able to deliver at Closing) to Buyer the documents and other items required to be delivered by Seller under Section 12.3.

10.8Sale Order. The Bankruptcy Court shall have entered the Sale Order and the Sale Order shall be in full force and effect and not subject to a stay.

10.9Closing of Transactions under AMH Agreement. The transactions under the AMH Agreement shall close contemporaneously with, or prior to, the Closing.

ARTICLE XISELLER’S CONDITIONS TO CLOSING

The obligations of Seller to consummate the transactions provided for herein is subject, at the option of Seller, to the fulfillment by Buyer or written waiver by Seller, on or prior to the Closing of each of the following conditions precedent:

11.1Representations. The representations and warranties of Buyer set forth in Article VIII shall be true and correct in all material respects as of the Closing Date (except with respect to the representations and warranties set forth in Section 8.8, Section 8.9 or Section 8.11 which shall be true in all respects) as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties (other than the representations and warranties set forth in Section 8.8, Section 8.9 or Section 8.11) that in the aggregate would not have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement or the Transaction Documents to which it is or will be a Party or perform its obligations hereunder or thereunder.

11.2Performance. Buyer shall have performed or complied with all obligations, agreements, and covenants contained in this Agreement as to which performance or compliance by Buyer is required prior to or at the Closing Date in all material respects.

11.3No Legal Proceedings. No order, award or judgment shall have been issued by any Governmental Authority or arbitrator to restrain, prohibit, enjoin or declare illegal the transactions contemplated by this Agreement, and no Law, statute, rule, regulation or other requirement has been promulgated or enacted and is in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated by this Agreement.

11.4Casualty Losses; Consents. The sum of (a) the amount of all uncured, unrestored and uninsured Casualty or Condemnation Losses pursuant to Section 5.1, plus (b) all reductions to the Purchase Price pursuant to Section 5.1(b) in respect of unobtained Required Consents, shall, in the aggregate, be less than ten percent (10%) of the unadjusted Purchase Price.

11.5Certificate. An authorized officer of Buyer shall execute and deliver (or be ready, willing and able to deliver at Closing) a certificate dated as of the Closing Date certifying on behalf of Buyer that the conditions set forth in Section 11.1 and Section 11.2 have been fulfilled by Buyer.

11.6Sale Order. The Bankruptcy Court shall have entered the Sale Order and the Sale Order shall be final, binding and non-appealable and in full force and effect and not subject to a stay.

11.7HSR Act.If applicable, the waiting period under the HSR Act applicable to the consummation of the transactions contemplated hereby shall have expired, or been terminated.

11.8Closing Deliverables. Buyer shall have delivered (or be ready, willing and able to deliver at Closing) to Seller the documents and other items, including the Adjusted Purchase Price, required to be delivered by Buyer under Section 12.3.

11.9Closing of Transactions under AMH Agreement. The transactions under the AMH Agreement shall close contemporaneously with, or prior to, the Closing.

ARTICLE XIICLOSING

12.1Date of Closing. Subject to the conditions stated in this Agreement, the transfer by Seller to Buyer of the Assets pursuant to this Agreement (the “Closing”) shall occur on February 12, 2020 (the “Target Closing Date”); provided,that if the conditions to Closing in Article X and Article XI have not yet been satisfied or waived by such applicable date, then the Closing shall occur five (5) Business Days after such conditions have been satisfied or waived, or such other date as Buyer and Seller may agree upon in writing. The date of the Closing shall be the “Closing Date.”

12.2Place of Closing. The Closing shall be held at the offices of Latham & Watkins LLP, 811 Main Street, Suite 3700, Houston, Texas 77002, or such other location as Seller may designate in writing.

12.3Closing Obligations. At the Closing, the following documents shall be delivered and the following events shall occur, the execution of each document and the occurrence of each event being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a)Seller and Buyer shall execute, acknowledge and deliver the Assignment and Deed(s) in sufficient counterparts, including all information and formatting required to be accepted by the appropriate Governmental Authorities, to be recorded in the applicable counties, covering the Assets;

(b)Seller and Buyer shall execute and deliver the ROW Assignment Agreements in sufficient counterparts, including all information and formatting required to be accepted by the appropriate Governmental Authorities, to be recorded in the applicable counties, covering the Purchased Rights of Way;

(c)Seller and Buyer shall execute and deliver the Closing Settlement Statement;

(d)Buyer shall deliver, to the account(s) designated in the Closing Settlement Statement, by direct bank or wire transfer in same day funds (x) to Seller, the Adjusted Purchase Price, less the sum of (i) the Deposit and (ii) any amounts deposited into the Escrow Account by Buyer pursuant to, and calculated in accordance with, Section 3.4(a) and (y) to the Escrow Agent, in accordance with Section 3.4(a);

(e)Seller and Buyer shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse the Deposit to Seller;

(f)Seller (or, if Seller is an entity disregarded as separate from any other Person within the meaning of Section 301.7701-3(a) of the Treasury Regulations, Seller’s regarded owner) shall deliver an executed statement described in Treasury Regulation §1.1445-2(b)(2);

(g)Seller shall deliver a validly executed blanket transfer of applicable forms designating Buyer (or, if applicable, Buyer’s operating Affiliate) as operator of the Gathering Systems and the Disposal Wells, as applicable;

(h)Seller and Buyer shall execute and deliver the Escrow Agreement; and

(i)Seller and Buyer shall execute and deliver any other agreements, instruments and documents that are required by other terms of this Agreement to be executed and/or delivered at or prior to the Closing.

12.4Records. In addition to the obligations set forth under Section 12.3 above, Seller shall use commercially reasonable efforts to make available to Buyer on the Closing Date (and shall in any event make available to Buyer within five (5) Business Days after the Closing Date) for pick-up (or will deliver electronically, if applicable), the Records to which Buyer is entitled pursuant to the terms of this Agreement, including all electronic Records.

12.5FCC Filings. Seller and Buyer shall prepare, as soon as is practical following the Closing, any necessary filings in connection with the transactions contemplated by this Agreement that may be required to be filed by the Parties or any Affiliate thereof with the Federal Communications Commission with respect to transfer of the Assigned FCC Licenses. Buyer shall pay all amounts payable to the Federal Communications Commission or other Governmental Authority with respect to the transfer of the Assigned FCC Licenses under this Agreement (provided that each Party shall be responsible for its out-of-pocket expenses incurred in connection with the preparation of any such filings). Seller and Buyer shall promptly furnish each other with copies of any notices, correspondence or other written communication from the FCC, shall promptly make any appropriate or necessary subsequent or supplemental filings and shall cooperate in the preparation of such filings as is reasonably necessary and appropriate. In addition, at or prior to, or as soon as practical after, the Closing, Buyer shall deliver evidence to Seller of its Federal Registry Number with respect to the Assigned FCC Licenses and its designation of an applicable contact person with respect to the Assigned FCC Licenses. Promptly following Closing, Buyer and Seller shall execute and deliver the forms and documents required by the applicable Governmental Authority to transfer the Assigned FCC Licenses to Buyer.

ARTICLE XIIIASSUMPTION; INDEMNIFICATION; SURVIVAL

13.1Assumed Obligations; Excluded Obligations.

(a)Assumed Obligations. Without prejudice to the Purchase Price adjustments described in Section 3.3, Buyer shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) the following obligations and Liabilities (and only the following obligations and Liabilities) (collectively, the “Assumed Obligations”):

(i)all of Seller’s Liabilities (excluding Environmental Liabilities) related to the Owned Real Property, Purchased Rights of Way, Gathering Systems and the Disposal Wells that are attached to or run with the Assets (i.e., excluding personal Liabilities of Seller or its Affiliates that are not attached to the Assets) to the extent such Liabilities are attributable to periods at or after the Effective Time;

(ii)all of Seller’s obligations or Liabilities under the Assigned Contracts to the extent attributable to periods at or after the Effective Time;

(iii)except for the Excluded Liabilities described in Section 13.1(b)(xi) and Section 13.1(b)(xii), Environmental Liabilities related to the Owned Real Property, Purchased Rights of Way, Gathering Systems and the Disposal Wells that are attached to or run with the Assets (i.e., excluding personal Liabilities of Seller or its Affiliates that are not attached to the Assets), whether arising prior to, at or after the Effective Time;

(iv)all obligations with respect to the Cure Costs (other than Excess Cure Costs) required to be paid by Buyer in accordance with Section 2.4;

(v)all Operating Expenses arising from, related to or associated with the Assets, in each case, to the extent attributable to periods at or after the Effective Time;

(vi)all obligations and amounts owed to the Continuing Employees relating to the employment of such individuals by Buyer or one of Buyer’s Affiliates from and after the Closing Date (but excluding any Liabilities or obligations owing under any Benefit Plans); and

(vii)all Asset Taxes and Transfer Taxes that are the responsibility of Buyer pursuant to Section 16.2.

Notwithstanding anything herein to the contrary, assumption by Buyer of the Assumed Obligations shall not, in any way, enlarge the rights of any Third Parties relating thereto.

(b)Excluded Liabilities. Notwithstanding any provision in this Agreement to the contrary, Buyer shall not assume and shall not be obligated to assume or be obligated to pay, perform or otherwise discharge any Liability or obligation of Seller not associated with the Assets, and Seller shall be solely and exclusively liable with respect to all obligations and Liabilities associated with the Assets, other than the Assumed Obligations (such Liabilities other than Assumed Obligations, collectively, the “Excluded Liabilities”). For purposes of clarity, and without limitation of the generality of the foregoing, the Excluded Liabilities shall include, without limitation, each of the following Liabilities of Seller or any Affiliate of Seller, other than the Assumed Obligations:

(i)all indebtedness for borrowed money of Seller;

(ii)all guarantees of Third Party obligations by Seller and reimbursement obligations to guarantors of Seller’s obligations or under letters of credit;

(iii)other than Liabilities assumed by Buyer pursuant to Section 13.1(a)(iii) and Section 13.1(a)(iv), all accrued expenses and accounts payables to the extent attributable to the period prior to the Effective Time;

(iv)all Seller Taxes;

(v)any claim, action, order, proceeding or other matter set forth on Schedule 7.6;

(vi)all Liabilities of Seller to any owner or former owner of capital stock or warrants, or holder of indebtedness for borrowed money;

(vii)any Liabilities related to the Excluded Assets;

(viii)except to the extent specifically assumed by Buyer pursuant to Article XV of this Agreement, all Liabilities at any time relating to or arising out of the employment or service with or termination of employment or service from Seller or any of its Affiliates of any Person (including any Continuing Employees), including any severance or incentive compensation, bonus payments, retention payments, change of control payments or similar payments whether or not such Liabilities, obligations or commitments arise or vest (whether fully or partially) as a result of the transactions contemplated by this Agreement and whether or not immediately due and payable upon the consummation of the transactions contemplated by this Agreement;

(ix)all Liabilities and any obligations relating to or at any time arising under, with respect to, or in connection with any Benefit Plans or any other compensation or benefit plan, program, policy, agreement or arrangement of any kind (including all assets, trusts, insurance policies and administration service contracts related thereto) that at any time is or was maintained, sponsored, contributed to or required to be contributed to by Seller or any of its Affiliates or under or with respect to which Seller or any of its Affiliates has (or has had) any Liability, including on account of an ERISA Affiliate or on account of Buyer or any of its Affiliates being deemed successor due to the operation of the Assets;

(x)Liabilities incurred by Seller or any of its Affiliates for brokerage or finders’ fees or agents’ commissions or other similar payments in connection with this Agreement, the other Transaction Documents or the transactions contemplated hereby;

(xi)the off-site transportation, disposal or arrangement therefor of any Hazardous Materials off the premises of the Assets prior to the Closing;

(xii)civil or criminal fines or penalties relating to violations occurring prior to the Closing Date of any Environmental Law with respect to the Assets or the operation thereof;

(xiii)all unpaid Operating Expenses attributable to periods prior to the Effective Time that are not taken into account pursuant to Section 3.3;

(xiv)all Liabilities at any time arising out of, or relating to, the WARN Act or any similar state Law as it relates to Business Employees terminated by Seller or its Affiliates; and

(xv)all Liabilities at any time arising or related to any CBA.

13.2Indemnities of Buyer. From and after the Closing, subject to the provisions and limitations set forth in Sections 13.3 through 13.10 (inclusive), Buyer shall assume, be responsible for, shall pay on a current basis, and hereby agrees to release, defend, indemnify and hold harmless Seller and its Affiliates, and all of its and their respective stockholders, partners, members, directors, officers, managers, employees, attorneys, agents and representatives (collectively, “Seller Indemnified Parties”) from and against any and all Liabilities, whether or not relating to Third Party Claims or incurred, directly or indirectly, in the investigation or defense of any of the same or in asserting, presenting or enforcing any of their respective rights hereunder arising from, based upon, related to or associated with:

(a)any breach by Buyer of its representations or warranties contained in Article VIII or in any certificate furnished by or on behalf of Buyer in connection with this Agreement;

(b)any breach by Buyer of its covenants, obligations or agreements under this Agreement (including, for the avoidance of doubt, any other indemnity obligations of Buyer and its Affiliates contained in this Agreement, including pursuant to Section 4.1(d));

(c)the Assumed Obligations; and

(d)any other indemnity obligations of Buyer and its Affiliates expressly set forth in this Agreement.

13.3Express Negligence. THE INDEMNIFICATION, RELEASE, ASSUMED OBLIGATIONS, WAIVER AND LIMITATION OF LIABILITY PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY; PROVIDED, HOWEVER, SUCH PROVISIONS SHALL NOT APPLY TO LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES TO THE EXTENT ARISING OUT OF THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF THE SELLER INDEMNIFIED PARTIES OR BUYER INDEMNIFIED PARTIES, AS APPLICABLE. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS CONSPICUOUS.

13.4Exclusive Remedy. Notwithstanding anything to the contrary contained in this Agreement, except as provided in Section 9.5, from and after Closing, Section 4.1(d), Section 9.2, Section 9.7, Section 12.5 and Section 13.2 shall contain Seller’s exclusive remedies against Buyer with respect to the transactions contemplated by this Agreement, including breaches of the representations, warranties, covenants, obligations and agreements of the Parties contained in this Agreement or the affirmations of such representations, warranties, covenants, obligations and agreements contained in the certificate(s) delivered by Buyer at Closing pursuant to Section 11.5. Without limiting Buyer’s rights under Article VI or Article XIII, Buyer releases, remises and forever discharges Seller and all Seller Indemnified Parties from any and all Liabilities in Law or in equity, known or unknown, which any of the Buyer Parties might now or subsequently may have, based on, relating to or arising out of this Agreement, the ownership, use or operation of the Assets prior to the Closing, or the condition, quality, status or nature of the Assets prior to the Closing, including rights to contribution under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, breaches of statutory or implied warranties, nuisance or other tort actions, rights to punitive damages, common Law rights of contribution, and rights under insurance maintained by Seller or any of its Affiliates.

13.5Indemnification Procedures. All claims for indemnification under Section 4.1(d), and Section 13.2 shall be asserted and resolved as follows:

(a)For purposes of this Agreement, the term “Indemnifying Party” means Buyer, and the term “Indemnified Party” when used in connection with particular Liabilities shall mean Seller or the Person(s) having the right to be indemnified with respect to such Liabilities by another Party pursuant to Section 4.1(d) or Section 13.2.

(b)To make claim for indemnification under Section 4.1(d) or Section 13.2, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 13.5, including the specific details of and specific basis under this Agreement for its claim (the “Claim Notice”). In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Party (a “Third PartyClaim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has Knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section 13.5(b) shall not relieve the Indemnifying Party of its obligations under Section 4.1(d) or Section 13.2 (as applicable) except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Third Party Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant, obligations or agreement, the Claim Notice shall specify the representation, warranty, covenant, obligation or agreement that was inaccurate or breached.

(c)In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Party shall have thirty (30) days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Third Party Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such thirty (30) day period, at the expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party. Failure of an Indemnifying Party to admit its liability to defend an Indemnified Party within such thirty (30) day period shall be deemed a denial of liability to so defend such Indemnified Party.

(d)If the Indemnifying Party admits its liability to defend the Indemnified Party against a Third Party Claim, it shall have the right and obligation to diligently defend, at its sole cost and expense, such Third Party Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified Party shall cooperate in contesting any Third Party Claim that the Indemnifying Party elects to contest. The Indemnified Party may participate in, at its own expense, but subject to the Indemnifying Party’s full control of, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 13.5(d); provided, however, that the Indemnified Party shall not be required to bring any counterclaim or cross complaint against any Person. An Indemnifying Party shall not, without the prior written consent of the Indemnified Party, (i) settle any Third Party Claim or consent to the entry of any judgment or order with respect thereto which does not result in a final resolution of the Indemnified Party’s Liability in respect of such Third Party Claim (including, in the case of a settlement, an unconditional written release of the Indemnified Party from all Liability in respect of such Third Party Claim), or (ii) settle any Third Party Claim or consent to the entry of any judgment or order with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(e)If the Indemnifying Party does not admit its liability or admits its liability to defend the Indemnified Party against the Third Party Claim, but fails to diligently prosecute or settle such Third Party Claim, then the Indemnified Party shall have the right to defend against the Third Party Claim at the sole cost and expense of the Indemnifying Party, with counsel of its choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its liability to defend the Indemnified Party against the Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement, unless the proposed settlement is solely for money damages and results in a final resolution, and the Indemnifying Party shall have the option for ten (10) days following receipt of such notice to (i) admit in writing its liability to indemnify the Indemnified Party from and against the liability and consent to such settlement, (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement, or (iii) deny liability. Any failure to respond to such notice by the Indemnified Party within such ten (10) day-period shall be deemed to be an election under subsection (i) above.

(f)In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party shall have thirty (30) days from its receipt of the Claim Notice to (i) cure the Liabilities complained of, (ii) admit its liability for such Liability or (iii) dispute the claim for such Liabilities. If the Indemnifying Party does not notify the Indemnified Party within such thirty (30) day period that it has cured the Liabilities or that it disputes the claim for such Liabilities, the Indemnifying Party shall be deemed to have disputed the claim for such Liabilities.

13.6Survival.

(a)The representations and warranties of Seller in Article VII and in the certificate delivered pursuant to Section 10.5 shall terminate at the Closing. All covenants, obligations and agreements of Seller in this Agreement (i) that are required to be performed at or prior to Closing shall terminate at the Closing and (ii) that cannot be performed until after the Closing shall survive until fully performed.

(b)Subject to Section 13.6(a) and except as set forth in Section 13.6(c), the remainder of this Agreement shall survive the Closing without time limit. Representations, warranties, covenants, obligations and agreements shall be of no further force and effect after the date of their expiration as set forth in Section 13.6(a) or Section 13.6(c); provided, that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant, obligation or agreement prior to its expiration date.

(c)The indemnities in Section 13.2(a) and Section 13.2(b) shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification. Buyer’s indemnities set forth in Section 13.2(c), and Section 13.2(d) shall survive the Closing without time limit. Notwithstanding the foregoing, there shall be no termination of any bona fide claim asserted pursuant to the indemnities in Section 13.1(b) prior to the date of termination for such indemnity.

13.7Non-Compensatory Damages. WITHOUT LIMITING SECTION 9.5, NOTWITHSTANDING ANYTHING CONTAINED IN THIS AGREEMENT TO THE CONTRARY, NONE OF THE BUYER PARTIES NOR THE SELLER INDEMNIFIED PARTIES SHALL BE ENTITLED TO RECOVER FROM THE OTHER PARTY OR SUCH OTHER PARTY’S AFFILIATES ANY INDIRECT, CONSEQUENTIAL, SPECIAL, PUNITIVE, INCIDENTAL, SPECULATIVE OR EXEMPLARY DAMAGES OR DAMAGES FOR LOST PROFITS OR LOSS OF BUSINESS OPPORTUNITY OF ANY KIND ARISING UNDER, RELATED TO OR IN CONNECTION WITH THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY, EXCEPT TO THE EXTENT ANY SUCH PERSON SUFFERS SUCH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEYS’ FEES INCURRED IN CONNECTION WITH THE DEFENSE OF SUCH DAMAGES) TO A THIRD PARTY, WHICH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEYS’ FEES INCURRED IN CONNECTION WITH THE DEFENSE OF SUCH DAMAGES) SHALL NOT BE EXCLUDED BY THIS PROVISION AS TO RECOVERY HEREUNDER. SUBJECT TO THE PRECEDING SENTENCE AND SECTION 9.5, AND NOTWITHSTANDING ANYTHING CONTAINED IN THIS AGREEMENT TO THE CONTRARY, EACH OF SELLER, ON BEHALF OF ITSELF AND THE SELLER INDEMNIFIED PARTIES, AND BUYER, ON BEHALF OF ITSELF AND THE BUYER PARTIES, WAIVES ANY RIGHT TO RECOVER INDIRECT, CONSEQUENTIAL, SPECIAL, PUNITIVE, INCIDENTAL, SPECULATIVE AND EXEMPLARY DAMAGES, INCLUDING DAMAGES FOR LOST PROFITS OR LOSS OF BUSINESS OPPORTUNITY OF ANY KIND, ARISING IN CONNECTION WITH OR WITH RESPECT TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY. THIS SECTION 13.7 SHALL NOT RESTRICT ANY PARTY’S RIGHT TO OBTAIN SPECIFIC PERFORMANCE OR ANY INJUNCTION IN ACCORDANCE WITH THE TERMS AND CONDITIONS OF THIS AGREEMENT.

13.8Waiver or Right to Rescission. Seller and Buyer acknowledge that, subject to any rights the Parties may have hereunder to seek and obtain specific performance or other express injunctive remedies, following Closing, the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant, obligation or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated by this Agreement. As such, Buyer and Seller waive any right to rescind this Agreement or any of the transactions contemplated hereby.

13.9Insurance. The amount of any Liabilities for which any Indemnified Party is entitled to indemnification under this Agreement or in connection with or with respect to the transactions contemplated by this Agreement shall be reduced by any corresponding insurance proceeds, from insurance policies carried by such Indemnified Party or its Affiliates, that are actually realized by such Indemnified Party from Third Party insurers with respect to such Liabilities.

13.10Waiver of Consumer Rights. The Parties each can and do expressly waive those provisions, if any, of the Texas Deceptive Trade Practices-Consumer Protection Act, Texas Business and Commerce Code Article 17.41 et seq. (and any similar Law that gives consumers special rights and protection, including the Oklahoma Consumer Protection Act, Okla. Stat. tit. 15, §§ 751 through 763). Buyer acknowledges, represents and warrants to Seller that Buyer is purchasing the Assets for commercial or business use; that Buyer has Knowledge and experience in financial and business matters that enable Buyer to evaluate the merits and risks of a transaction such as this; and that Buyer is not in a significantly disparate bargaining position with Seller. Further, Buyer expressly recognizes that the price for which Seller has agreed to perform its obligations under this Agreement has been predicated upon the inapplicability of Laws similar to those described above, and Buyer further recognizes that Seller, in determining to proceed with the entering into this Agreement, has expressly relied on this waiver and the inapplicability of such Laws. It is not the intent of the Parties to waive, and the Parties shall not waive, any applicable provision thereof that is prohibited by Law from being waived.

ARTICLE XIVTERMINATION, DEFAULT AND REMEDIES

14.1Right of Termination. This Agreement and the transactions contemplated herein may be terminated at any time at or prior to Closing:

(a)by Seller, at Seller’s option, in the event of a breach by Buyer of any representation, warranty, covenant or other agreement contained in this Agreement which would give rise to the failure of a condition set forth in Section 11.1 or Section 11.2 and (i) such breach is not waived in writing by Seller or (ii) solely to the extent such breach is capable of being cured, following written notice thereof from Seller to Buyer specifying the reason such condition is unsatisfied, such breach remains uncured for a period of ten (10) Business Days after Buyer’s receipt of such written notice from Seller;

(b)by Buyer, at Buyer’s option, in the event of a breach by Seller of any representation, warranty, covenant or other agreement contained in this Agreement which would give rise to the failure of a condition set forth in Section 10.1 or Section 10.2 and (i) such breach is not waived in writing by Buyer or (ii) solely to the extent such breach is capable of being cured, following written notice thereof from Buyer to Seller specifying the reason such condition is unsatisfied, such breach remains uncured for a period of ten (10) Business Days after Seller’s receipt of such written notice from Buyer;

(c)by either Party if the conditions set forth in Section 10.3, Section 10.4, Section, 10.6, Section 10.8 or Section 10.9 in the case of Buyer, or Section 11.3, Section 11.4, Section 11.6, Section 11.7 or Section 11.9, in the case of Seller, have not been satisfied, or waived, by the applicable Party, by the Outside Termination Date;

(d)upon the mutual written agreement of the Parties;

(e)by either Party, at such Party’s option, at any time following the Outside Termination Date;

(f)by Buyer, if:

(i)Buyer is not the Successful Bidder or the Backup Bidder for the Assets at the Auction, and Seller does not close the transactions contemplated by this Agreement with Buyer by the Outside Termination Date;

(ii)[reserved];

(iii)there is a termination of the Cash Collateral Order and within fifteen (15) days of such termination (A) such termination is not reversed, vacated or stayed, (B) the Bankruptcy Court has not reinstated the Cash Collateral Order or (C) the Bankruptcy Court has not entered a new order authorizing the Seller to use the cash collateral of the prepetition lenders or entry into debtor-in-possession financing;

(iv)[reserved]; or

(v)Seller withdraws or seeks authority to withdraw the Sale Order at any time after the filing thereof, or announces any standalone plan of reorganization or liquidation, in each case, with respect to the Assets other than as set forth herein;

(g)by Buyer or Seller, if:

(i)Seller enters into a definitive agreement regarding a Highest or Best Proposal for the Assets and Buyer is not the Backup Bidder;

(ii)[reserved];

(iii)the Bankruptcy Court enters an order dismissing, or converting to a case under chapter 7 of the Bankruptcy Code, the Chapter 11 Cases, where such order was not requested, encouraged or supported by Seller and Buyer;

(iv)a Governmental Authority of competent jurisdiction shall have issued an order, injunction or judgment or Law that permanently restrains, prohibits, enjoins or declare illegal the transactions contemplated by this Agreement and such order, injunction or judgment becomes final and non-appealable;

(v)there shall be in effect a Final Order restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated hereby;

(vi) Seller enters into (or provides written notice to Buyer of its intent to enter into) one or more agreements to sell, transfer or otherwise dispose of any material portion of the Assets having a fair market value in excess of $20,000,000 in a transaction or series of transactions other than in the ordinary course of business with one or more Persons other than Buyer or the Successful Bidder at the Auction;

(h)by Seller or Buyer if the AMH Agreement has been terminated by its terms; or

(i)by Seller, at any time after 5:00 p.m. (Central Prevailing Time) on January 20, 2020 if, at the time of such termination, Buyer has failed to fund the Supplemental Deposit into the Escrow Account;

provided, however, that no Party shall have the right to terminate this Agreement pursuant to clause (a), (b), (c) or (e) above if such terminating Party is at such time in material breach of any provision of this Agreement.

14.2Effect of Termination.

(a)If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 14.1 hereof, then, except for the provisions of Section 1.2, Sections 4.1(d) through 4.1(f), Section 4.2, Section 4.3, Section 9.5, Section 13.4, Section 13.7, this Section 14.2,Section 14.3, Article XVI (other than Section 16.2(b) through (e), Section 16.3, Section 16.8, Section 16.9 and Section 16.17) and such of the defined terms in Section 1.1 necessary to give context to the surviving provisions, this Agreement shall forthwith become void and the Parties shall have no liability or obligation hereunder.

(b)If Seller is entitled to terminate this Agreement pursuant to (i) Section 14.1(a),(ii) Section 14.1(c) due to a failure of the condition in Section 11.9 to be met or Section 14.1(h) and, in the case of this clause (ii), (A) “Seller” (as defined in the AMH Agreement) is entitled to the “Deposit” (as defined in the AMH Agreement) pursuant to the terms of the AMH Agreement (or, if the AMH Agreement has been amended without the prior written consent of Seller, would be entitled to such Deposit pursuant to the terms of the AMH Agreement as in effect on the A&R Execution Date), (B) the termination of the AMH Agreement is by the mutual agreement of Buyer and “Seller” (as defined in the AMH Agreement) or (C) an AMH Change has occurred and any closing conditions in the AMH Agreement that were modified by such AMH Change have not been satisfied or waived by the Outside Termination Date or the failure of the AMH Agreement to close on or prior to the Outside Termination Date is otherwise the result of such AMH Change (regardless of whether Buyer also may have the right to terminate this Agreement pursuant to Section 14.1(c), Section 14.1(e) or Section 14.1(h)) or (iii) Section 14.1(e) and, in the case of this clause (iii), (A) Buyer is then in Willful Breach of this Agreement, or (B) Buyer has failed to close in the instance where, as of the Outside Termination Date, (1) all of the conditions in Article X (excluding conditions that, by their terms, cannot be satisfied until the Closing and, in the case of Section 10.9, excluding Section 10.9 so long as it remains capable of being satisfied) have been satisfied (or waived by Buyer), (2) Seller is ready, willing and able to perform its obligations under Section 12.3, and (3) Buyer nevertheless elects not to close, then, in each such event, Seller shall be entitled to, at its option, (x) obtain specific performance in lieu of termination or (y) terminate this Agreement and retain the Deposit(or if Buyer terminates this Agreement pursuant to any of Section 14.1(c), Section 14.1(e) or Section 14.1(h) at a time when Seller had the right to terminate this Agreement and retain the Deposit pursuant to this Section 14.2(b), Seller shall be entitled to retain the Deposit) as liquidated damages for such termination (the Parties agree that the foregoing liquidated damages are reasonable considering all of the circumstances existing as of the A&R Execution Date, shall not serve as a penalty and constitute the Parties’ good faith estimate of the actual damages reasonably expected to result from such termination of this Agreement by Seller). Seller agrees that, to the fullest extent permitted by Law, Seller’s rights set forth in the preceding sentence shall be the sole and exclusive remedies of Seller (other than with respect to those provisions that survive termination pursuant to Section 14.2(a)) if the Closing does not occur as a result of the termination of this Agreement pursuant to Section 14.1(a), Section 14.1(h) (and clause (A), (B) or (C) of clause (ii) above applies) or Section 14.1(e), as applicable. Nothing herein shall be construed to prohibit Seller from first seeking specific performance in accordance with the last sentence of this Section 14.2(b), but thereafter terminating this Agreement and retaining the Deposit as liquidated damages in lieu of fully prosecuting its claim for specific performance. Each Party acknowledges that the remedies at Law of Seller for a breach or threatened breach of this Agreement by Buyer as contemplated pursuant to this Section 14.2(b) may be inadequate and, in recognition of this fact, Seller, without posting any bond or the necessity or proving the inadequacy as a remedy of monetary damages, and in addition to all other remedies that may be available, shall be entitled to obtain equitable relief in the form of specific performance, a temporary restraining order, a temporary or permanent injunction or any other equitable remedy that may then be available.

(c)If this Agreement is terminated by Buyer pursuant to (i) Section 14.1(b) or (ii) Section 14.1(e) and, in the case of this clause (ii), (A) Seller is then in Willful Breach of this Agreement, or (B) Seller has failed to close in the instance where, as of the Outside Termination Date, (1) all of the conditions in Article XI (excluding conditions that, by their terms, cannot be satisfied until the Closing) have been satisfied by Buyer (or waived by Seller), (2) Buyer is ready, willing and able to perform its obligations under Section 12.3, and (3) Seller nevertheless elects not to close, then, in either such event, Buyer shall be entitled to return of the Deposit pursuant to Section 14.2(e) and, if such termination is pursuant to Section 14.1(b), such termination is as a result of a failure of the Closing condition in Section 10.1(b) to be satisfied and such failure is due to Seller’s Willful Breach of this Agreement, Buyer shall be entitled to seek actual, direct damages (subject always to Section 13.7) up to an aggregate amount not greater than an amount equal to the Deposit. Buyer agrees that, to the fullest extent permitted by Law, Buyer’s rights set forth in the preceding sentence shall be its sole and exclusive remedies of Buyer (other than with respect to those provisions that survive termination pursuant to Section 14.2(a))if the Closing does not occur as a result of the termination of this Agreement pursuant to Section 14.1(b) or Section 14.1(e), as applicable.

(d)[Reserved.]

(e)If this Agreement is terminated by Seller or by Buyer pursuant to Section 14.1 (other than under the circumstances described in Section 14.2(b)), within two (2) Business Days after such termination, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse the Deposit to Buyer; provided, however, that if (i) this Agreement is terminated by Seller pursuant to Section 14.1(h) or pursuant to Section 14.(c) due to a failure of the condition in Section 11.9 to be met and (ii) in either case, “Seller” (as defined in the AMH Agreement) is entitled to the “Deposit” (as defined in the AMH Agreement) pursuant to the terms of the AMH Agreement (or, if the AMH Agreement has been amended without the prior written consent of Seller, would be entitled to such Deposit pursuant to the terms of the AMH Agreement as in effect on the A&R Execution Date), then the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse the Deposit to Seller.

(f)Subject to the foregoing, upon the termination of this Agreement neither Party shall have any other liability or obligation hereunder, and Seller shall be free to immediately enjoy all rights of ownership of the Assets and to sell, transfer, encumber or otherwise dispose of the Assets to any Person without any restriction under this Agreement.

14.3Return of Documentation and Confidentiality. Upon termination of this Agreement, Buyer shall return or destroy, at Buyer’s sole expense, all title, engineering, geological and geophysical data, environmental assessments and/or reports, maps and other data and information (including all copies, extracts and other reproductions, in whole or in part) furnished by Seller or any of its Affiliates or representatives to Buyer or any of the Buyer Representatives or prepared by or on behalf of Buyer in connection with its due diligence investigation of the Assets, in each case, in accordance with the Confidentiality Agreement and/or the terms of this Agreement, and an officer of Buyer shall certify same to Seller in writing. Any oral information will continue to be subject to the terms of the Confidentiality Agreement notwithstanding the termination of this Agreement.

ARTICLE XVEMPLOYEES

15.1Business Employees. On January 6, 2020, Seller provided Buyer with a list containing the name, position, exempt or non-exempt status and location of those current Business Employees, whether or not actively employed (e.g., including employees on vacation and leave of absence, including maternity, family and medical leave, sick, military (whether qualified or otherwise) or short-term disability leave), and the base salary or hourly wage rate and any target annual incentive applicable to each such Business Employee, and Seller shall update the list periodically prior to the Closing Date, including within five (5) Business Days at Buyer’s reasonable request, to reflect new hires, leaves of absence and employment terminations. Buyer shall, in its sole discretion, have the option, but not the obligation, to offer employment as of the Closing Date to certain Business Employees (the “Offered Employees”) on terms and conditions to be determined in Buyer’s sole discretion. Not later than ten (10) Business Days prior to the Closing Date, Buyer shall provide Seller with a list of the material terms (including compensation details, position and location of employment) of each such offer made to each Business Employee. Within five (5) Business Days after the Execution Date and until the Closing, Seller shall use its commercially reasonable efforts to provide Buyer reasonable access to the Business Employees for the sole purpose of interviewing such Business Employees and discussing employment with Buyer. Buyer may directly communicate any offer of employment to a Business Employee; provided, however, that Buyer will notify Seller prior to contacting any such Business Employee and will provide Seller with a reasonable opportunity to review any material communications or correspondence with the Business Employees prior to the Closing Date. Each Offered Employee who accepts Buyer’s offer of employment and actually commences employment with Buyer shall be referred to as a “Continuing Employee”. Prior to the Closing Date, Seller shall waive, effective as of the Closing Date, any restrictions otherwise applicable to a Continuing Employee pursuant to any agreement or other arrangement between Seller and such Continuing Employee, which would restrict or otherwise prevent such Continuing Employee from accepting or commencing employment with Buyer. For the avoidance of doubt, Seller and Buyer are not, and do not intend to be, joint employers at any time, and nothing herein may be construed as creating a joint employer relationship between Seller and Buyer.

15.2Employee Matters.

(a)Following Closing, Buyer agrees and shall be responsible for providing continuation coverage as required by COBRA, under a group health plan maintained by Buyer, to Continuing Employees.

(b)During the period prior to the Closing Date, Seller shall use commercially reasonable efforts to make individual natural person independent contractors related to the Assets and directly engaged by Seller available to Buyer for the purpose of allowing Buyer to interview each such contractor and determine the nature and extent of each such Person’s continuation with Buyer, if any. Seller shall provide to Buyer contact information for Third Party service providers providing contingent personnel relating to the Assets and reasonably cooperate in identifying and transferring such contingent work force to the extent requested by Buyer.

(c)The provisions of this Article XV are solely for the benefit of the respective parties to this Agreement and nothing in this Article XV or elsewhere in this Agreement, express or implied, shall create any Third Party beneficiary or other rights or confer upon any employee, Continuing Employee, or legal representative or beneficiary or dependent thereof, any rights or remedies, including any right to employment or continued employment for any specified period, or compensation or benefits of any nature or kind whatsoever. Nothing in this Agreement is intended as an amendment, modification or waiver of the provisions of any benefit or compensation plan, program, policy, agreement, arrangement or contract (including any Benefit Plan), or shall prohibit or limit the ability of Buyer or any of its Affiliates to amend, modify or terminate any benefit or compensation plan, program, policy, agreement, arrangement or contract at any time assumed, established, sponsored or maintained by Buyer or any of its Affiliates.

ARTICLE XVIMISCELLANEOUS

16.1Exhibits and Schedules. All of the Exhibits and Schedules referred to in this Agreement constitute a part of this Agreement. Each Party to this Agreement and its counsel has received a complete set of Exhibits and Schedules prior to and as of the execution of this Agreement.

16.2Expenses and Taxes.

(a)Except as otherwise specifically provided, all fees, costs and expenses incurred by the Parties in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including legal and accounting fees, costs and expenses.

(b)All Transfer Taxes and all required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to the Assets to Buyer shall be borne by Buyer. The Parties shall cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such Transfer Taxes.

(c)All Taxes that are real property Taxes, ad valorem Taxes, personal property Taxes and similar obligations attributable to the Assets, but excluding, for the avoidance of doubt, income, capital gains and franchise Taxes and Transfer Taxes (the “Asset Taxes”) with respect to the Tax period in which the Effective Time occurs or estimate(s) thereof shall be apportioned as of the Effective Time between Seller and Buyer. Such Asset Taxes shall be apportioned as of the Effective Time between Seller and Buyer and included in the Final Settlement Statement. To the extent the actual amount of any Asset Taxes described in this Section 16.2(c) is not determinable at the time of the Final Settlement Statement, Buyer and Seller shall utilize the most recent information available in estimating the amount of such Asset Taxes for purposes of the Final Settlement Statement. For purposes of the foregoing, in each case, the Asset Taxes shall be allocated pro rata per day between the period immediately prior to the Effective Time and the period beginning on the Effective Time, with the portion of Asset Taxes attributable to the period immediately prior to the Effective Time being allocated to Seller, and the portion of the Asset Taxes attributable to the period beginning on the Effective Time being allocated to Buyer. Seller shall pay or cause to be paid to the taxing authorities all Asset Taxes due prior to the Closing Date. Buyer shall pay or cause to be paid to the taxing authorities all Asset Taxes due after the Closing Date relating to the Tax period in which the Effective Time occurs without thereby becoming entitled to any additional payment from Seller other than as required by Article III and neither Party shall be liable to make any additional payment to the other Party in the event an estimate of such Asset Taxes used in arriving at the Final Settlement Statement varies from the actual amount thereof.

(d)Buyer and Seller agree to furnish or cause to be furnished to the other, upon request, as promptly as practicable, such information and assistance relating to the Assets, including access to books and Records, as is reasonably necessary for the filing of all Tax Returns by Buyer or Seller, the making of any election relating to Taxes, the preparation for any audit by any taxing authority and the prosecution or defense of any claim, suit or proceeding relating to any Tax.

(e)Any payments made to any Party pursuant to Article XIII shall constitute an adjustment to the Purchase Price for Tax purposes and shall be treated as such by Buyer and Seller on their respective Tax Returns to the extent permitted by Law.

16.3Value Allocations for Tax Purposes. Seller and Buyer agree that the portion, if any, of the Adjusted Purchase Price and any other items treated for federal Tax purposes as consideration for a sale transaction (collectively, the “Allocable Amount”) shall be allocated among the various Assets for federal and state income Tax purposes in accordance with Section 1060 of the Code and Treasury Regulations promulgated thereunder. The initial draft of such allocations shall be prepared by Seller and shall be provided to Buyer concurrently with the delivery of the Final Settlement Statement. Seller and Buyer shall then prepare a mutually agreeable final schedule of any Allocable Amount among the Assets (as adjusted, the “Allocation Schedule”), which agreementwill not be unreasonably withheld, conditioned or delayed by either Party. The Allocation Schedule shall be updated to reflect any adjustments to the Allocable Amount. If required, the allocation of the Allocable Amount shall be reflected on a completed Internal Revenue Service Form 8594 (Asset Acquisition Statement under Section 1060), which such form will be timely filed separately by Seller and Buyer with the Internal Revenue Service pursuant to the requirements of Section 1060(b) of the Code. Neither Buyer nor Seller shall take any Tax position inconsistent with such allocation and neither Buyer nor Seller shall agree to any proposed adjustment to the Allocation by any Taxing authority unless required by a “determination” within the meaning of Section 1313(a) of the Code or with the prior written consent of the other Party; provided, however, that nothing contained herein shall prevent Buyer or Seller from settling any proposed deficiency or adjustment by any Taxing authority based upon or arising out of the Allocation, and neither Buyer nor Seller shall be required to litigate before any court any proposed deficiency or adjustment by any taxing authority challenging such Allocation. The procedures of Section 3.5 shall be applied in the event of a dispute for any item under this Section 16.3, mutatis mutandis.

16.4Assignment; Liquidating Trust.

(a)Neither this Agreement, nor any rights, obligations, liabilities, covenants, duties or responsibilities hereunder, may be assigned by any Party, in whole or in part, without the prior written consent of the other Party, which consent may be withheld for any reason; provided, however, that Buyer shall be permitted to assign all or any portion of its rights or obligations under this Agreement to one or more of its Affiliates without the prior consent of Seller; provided that the assigning Party shall remain primarily liable for all obligations of Buyer hereunder together with its assignee. Any assignment in violation of the foregoing shall be deemed void ab initio; provided, further, that, Buyer may assign all or any portion of its rights and obligations pursuant to this Agreement to the Debt Financing Sources pursuant to the terms of the Commitment Documentation for purposes of creating a security interest herein or otherwise assigning as collateral in respect of the Commitment. No assignment by any Party of this Agreement shall relieve such Party of any of its obligations (including indemnity obligations), liabilities, covenants, duties or responsibilities hereunder.

(b)If a Liquidating Trust is established, from and after the formation of the Liquidating Trust all rights and obligations of Seller under this Agreement shall accrue to and be for the benefit of an shall be exercisable by the Liquidating Trust, as provided by any order of the Bankruptcy Court and the Liquidating Trustee shall be entitled to exercise all of the rights of Sellers under this Agreement.

16.5Preparation of Agreement. Both Seller and Buyer and their respective counsel participated in the preparation of this Agreement. In the event of any ambiguity in this Agreement, no presumption shall arise based on the identity of the draftsman of this Agreement.

16.6Publicity; Disclosure of Agreement and Transaction. Seller and Buyer and their respective Affiliates, if applicable, shall consult with each other with regard to all press releases or other public or private announcements issued or made at or prior to the Closing concerning this Agreement or the transactions contemplated herein, and neither Buyer nor Seller shall issue, and each of them shall not permit any Affiliate to issue any such press release or other publicity without the prior written consent of the other Party, which consent shall not be unreasonably withheld, conditioned or delayed. The foregoing limitations shall not (A) restrict disclosures by a Party that are permitted or required under this Agreement, including Section 3.4(a), (B) restrict disclosures by Buyer or Seller that are required by applicable securities or other Laws or regulations or the applicable rules of any Governmental Authority or stock exchange having jurisdiction over the disclosing Party or its Affiliates, (C) prevent Buyer or Seller from recording the Assignment and Deed or any federal or state assignments delivered at Closing or from complying with any disclosure requirements of Governmental Authorities that are applicable to the transfer of the Assets from Seller to Buyer, (D) prevent Buyer or Seller from making any disclosure of information relating to this Agreement if made in a manner, under conditions and to Persons that would be permitted under the terms of the Confidentiality Agreement so long as such Person continues to hold such information confidential on the same terms as set forth in such agreement, and (E) prevent Seller from making disclosures to the extent reasonably required in connection with complying with Preferential Purchase Rights and seeking to obtain Consents.

16.7Notices. All notices and communications which are required or may be given to a Party hereunder shall be in writing and shall be deemed to have been duly given upon the earliest of: (a) if by personal delivery, then the date of delivery if such date is a Business Day during normal business hours, or, if such date is not a Business Day during normal business hours, then the next Business Day, (b) if sent by U.S. certified mail, postage prepaid, return receipt requested, then the date shown as received on the return notice, (c) if sent by email, with delivery receipt to sender or (d) if by Federal Express overnight delivery (or other reputable overnight delivery service), the date shown on the notice of delivery if such date is a Business Day during normal business hours, or, if such date is not a Business Day during normal business hours, then on the next Business Day:

If to Seller:

Kingfisher Midstream, LLC15021 Katy Freeway, Suite 400Houston, Texas 77094Attention: Ryan McKenzie, Associate General CounselE-mail: rmckenzie@AltaMesa.net

with a copy to:

Kingfisher Midstream, LLC15021 Katy Freeway, Suite 400Houston, Texas 77094Attention: John Campbell, President and Chief Operating OfficerE-mail: jcampbell@AltaMesa.net

and

Kingfisher Midstream, LLC15021 Katy Freeway, Suite 400Houston, Texas 77094Attention: Allison Davis, Associate General CounselE-mail: adavis@AltaMesa.net

with a copy to (which shall not constitute notice):

Weil, Gotshal & Manges LLP200 Crescent Court, Suite 300Dallas, Texas 75201Attention: Rodney L. MooreE-mail: rodney.moore@weil.com

If to Buyer:

c/o Mach Resources LLC14201 Wireless Way, Suite 300Oklahoma City, Oklahoma 73134 Attention: Michael Reel, Senior CounselE-mail: mreel@machresources.com

with a copy to:

Bayou City Energy1201 Louisiana Street, Suite 3308Houston, Texas 77002
Attention: Darren Lindamood, Director & General CounselE-mail: Darren@bayoucityenergy.com

with a copy to (which shall not constitute notice):

Kirkland & Ellis LLP609 Main Street, 45^th FloorHouston, Texas 77002Attention: David M. Castro Jr., P.C.     Christopher S.C. Heasley E-mail: david.castro@kirkland.com     christopher.heasley@kirkland.com

and

Kirkland & Ellis LLP300 North LaSalleChicago, Illinois 60654Attention: Gregory F. Pesce E-mail: gregory.pesce@kirkland.com

The Parties may change the identity, address and email addresses to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 16.7.

16.8Further Cooperation. After the Closing, Buyer and Seller shall execute and deliver, or shall cause to be executed and delivered from time to time, such further instruments of conveyance and transfer, and shall take such other actions as any Party may reasonably request, to transfer and deliver the Assets to Buyer, and to otherwise accomplish the transactions contemplated by this Agreement.

16.9Filings, Notices and Certain Governmental Approvals. Promptly after Closing, Buyer shall (with commercially reasonable cooperation from Seller, as necessary) (a) record the Instruments of Conveyance relating to the Assets and all state/federal assignments executed at the Closing in all applicable real property records and, if applicable, all state or federal agencies, (b) if applicable, send notices to vendors supplying goods and services for the Assets of the assignment of the Assets to Buyer and, if applicable, the designation of Buyer (or, if applicable, Buyer’s operating Affiliate) as the operator thereof, (c) pursue the approval of all applicable Governmental Authorities of the assignment of the Assets to Buyer and, if applicable, the designation of Buyer (or, if applicable, Buyer’s operating Affiliate) as the operator thereof and (d) subject to the provisions of Section 5.2(a)(iii), pursue all other consents and approvals that may be reasonably required in connection with the assignment of the Assets to Buyer and the assumption of the Liabilities assumed by Buyer hereunder, that shall not have been obtained prior to Closing. Buyer obligates itself to take any and all action reasonably required of it by any Governmental Authority in order to obtain such approval, including but not limited to, the posting of any and all bonds or other security that may be required in excess of its existing lease, pipeline or area-wide bond.

16.10Entire Agreement; Conflicts. THIS AGREEMENT, THE CONFIDENTIALITY AGREEMENT, THE EXHIBITS AND SCHEDULES HERETO AND THE TRANSACTION DOCUMENTS COLLECTIVELY CONSTITUTE THE ENTIRE AGREEMENT AMONG THE PARTIES PERTAINING TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ALL PRIOR AGREEMENTS, UNDERSTANDINGS, NEGOTIATIONS, AND DISCUSSIONS, WHETHER ORAL OR WRITTEN, OF THE PARTIES PERTAINING TO THE SUBJECT MATTER OF THIS AGREEMENT, INCLUDING THE ORIGINAL AGREEMENT. THERE ARE NO WARRANTIES, REPRESENTATIONS, OR OTHER AGREEMENTS AMONG THE PARTIES RELATING TO THE SUBJECT MATTER OF THIS AGREEMENT EXCEPT AS SPECIFICALLY SET FORTH IN THIS AGREEMENT AND THE TRANSACTION DOCUMENTS, AND NO PARTY SHALL BE BOUND BY OR LIABLE FOR ANY ALLEGED REPRESENTATION, PROMISE, INDUCEMENT OR STATEMENTS OF INTENTION NOT SO SET FORTH. IN THE EVENT OF A CONFLICT BETWEEN: (A) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY SCHEDULE OR EXHIBIT HERETO, THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL; OR (B) THE TERMS AND PROVISION OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY TRANSACTION DOCUMENT, THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL; PROVIDED, HOWEVER, THAT THE INCLUSION IN ANY OF THE SCHEDULES OR EXHIBITS HERETO OR ANY TRANSACTION DOCUMENT OF TERMS AND PROVISIONS NOT ADDRESSED IN THIS AGREEMENT SHALL NOT BE DEEMED A CONFLICT, AND ALL SUCH ADDITIONAL PROVISIONS SHALL BE GIVEN FULL FORCE AND EFFECT, SUBJECT TO THE PROVISIONS OF THIS SECTION 16.10.

16.11Successors and Permitted Assigns. This Agreement shall be binding upon and inure to the benefit of the Parties and their permitted successors and assigns.

16.12Parties in Interest. Notwithstanding anything contained in this Agreement to the contrary, nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Parties, or their respective related Indemnified Parties hereunder any rights, remedies, obligations or liabilities under or by reason of this Agreement; provided, that only a Party will have the right to enforce the provisions of this Agreement on its own behalf or on behalf of any of its related Indemnified Parties (but shall not be obligated to do so); provided, further, that that the Debt Financing Sources may enforce on behalf of the Debt Financing Related Parties (and each is an intended third party beneficiary of) the provisions of Section 8.8, Section 9.13, Section 16.3, Section 16.4, Section 16.12, Section 16.13, Section 16.14, Section 16.15, and Section 16.21.

16.13Amendment. This Agreement may be amended only by an instrument in writing executed by all of the Parties and expressly identified as an amendment or modification; provided, that notwithstanding anything to the contrary contained herein, none of Section 8.8, Section 9.13, Section 16.3, Section 16.4, Section 16.12, Section 16.13, Section 16.14, Section 16.15, and Section 16.21 (or any other provision of this Agreement to the extent an amendment, modification, waiver or termination of such provision would modify the substance of any of the foregoing provisions) may be amended, modified, waived or terminated in a manner that is materially adverse to a Debt Financing Related Party without the prior written consent of the Debt Financing Sources.

16.14Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance; provided, that notwithstanding anything to the contrary contained herein, none of Section 8.8, Section 9.13, Section 16.3, Section 16.4, Section 16.12, Section 16.13, Section 16.14, Section 16.15, and Section 16.21 (or any other provision of this Agreement to the extent an amendment, modification, waiver or termination of such provision would modify the substance of any of the foregoing provisions) may be amended, modified, waived or terminated in a manner that is materially adverse to a Debt Financing Related Party without the prior written consent of the Debt Financing Sources. No course of dealing on the part of any Party, or their respective officers, employees, agents, or representatives, nor any failure by a Party to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such Party at a later time to enforce the performance of such provision. No waiver by any Party of any condition, or any breach of any term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation, or warranty. The rights of the Parties under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

16.15Governing Law; Jurisdiction; Venue; Jury Waiver.

EXCEPT TO THE EXTENT THE MANDATORY PROVISIONS OF THE BANKRUPTCY CODE APPLY, THIS AGREEMENT AND THE LEGAL RELATIONS BETWEEN THE PARTIES SHALL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS EXCLUDING ANY CONFLICTS OF LAW RULE OR PRINCIPLE THAT MIGHT REFER CONSTRUCTION OF SUCH PROVISIONS TO THE LAWS OF ANOTHER JURISDICTION; PROVIDED, THAT ANY MATTER RELATING TO REAL PROPERTY SHALL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE JURISDICTION WHERE SUCH REAL PROPERTY IS LOCATED. WITHOUT LIMITATION OF ANY PARTY’S RIGHT TO APPEAL ANY ORDER OF THE BANKRUPTCY COURT, (I) THE BANKRUPTCY COURT SHALL RETAIN EXCLUSIVE JURISDICTION TO ENFORCE THE TERMS OF THIS AGREEMENT AND ANY OF THE TRANSACTION DOCUMENTS DELIVERED PURSUANT HERETO, AND TO DECIDE ANY CLAIMS OR DISPUTES WHICH MAY ARISE OR RESULT FROM, OR BE CONNECTED WITH, THIS AGREEMENT OR SUCH TRANSACTION DOCUMENTS, OR ANY BREACH OR DEFAULT HEREUNDER OR THEREUNDER, OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY AND (II) ANY AND ALL CLAIMS RELATING TO THE FOREGOING SHALL BE FILED AND MAINTAINED ONLY IN THE BANKRUPTCY COURT, AND THE PARTIES AND HEREBY CONSENT AND SUBMIT TO THE EXCLUSIVE JURISDICTION AND VENUE OF THE BANKRUPTCY COURT AND IRREVOCABLY WAIVE THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF ANY SUCH ACTION OR PROCEEDING; PROVIDED, HOWEVER, THAT, PRIOR TO COMMENCEMENT OF THE CHAPTER 11 CASES OR IF THE CHAPTER 11 CASES ARE CLOSED, EACH PARTY CONSENTS TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE UNITED STATES FEDERAL DISTRICT COURTS LOCATED IN HOUSTON, HARRIS COUNTY, TEXAS (OR IF THE FEDERAL DISTRICT COURTS DO NOT HAVE JURISDICTION, THEN THE STATE COURTS IN HOUSTON, HARRIS COUNTY, TEXAS) FOR ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS, OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY. SUBJECT TO THE FOREGOING PROVISIONS OF THIS SECTION 16.15, ANY SUCH ACTIONS, SUITS OR PROCEEDINGS WITH RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO, OR FROM THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY SHALL BE EXCLUSIVELY LITIGATED IN THE UNITED STATES FEDERAL DISTRICT COURTS HAVING SITES IN HOUSTON, HARRIS COUNTY, TEXAS (AND ALL APPELLATE COURTS HAVING JURISDICTION THEREOVER) OR, IF THE FEDERAL COURTS DO NOT HAVE JURISDICTION, THEN THE STATE COURTS IN HOUSTON, HARRIS COUNTY, TEXAS (AND ALL APPELLATE COURTS HAVING JURISDICTION THEREOVER). EACH PARTY WAIVES ANY OBJECTION TO LAYING VENUE IN ANY SUCH ACTION, SUIT OR PROCEEDING IN SUCH COURTS AND WAIVE ANY OBJECTION THAT SUCH COURTS ARE AN INCONVENIENT FORUM OR DO NOT HAVE JURISDICTION OVER SUCH PARTY. EACH PARTY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY (INCLUDING ANY LEGAL PROCEEDING AGAINST OR INVOLVING ANY DEBT FINANCING RELATED PARTY ARISING OUT OF THIS AGREEMENT OR THE DEBT FINANCING).

NOTWITHSTANDING ANYTHING HEREIN TO THE CONTRARY, (I) EACH PARTY HERETO ACKNOWLEDGES AND IRREVOCABLY AGREES THAT ANY PROCEEDING, WHETHER IN CONTRACT OR TORT, AT LAW OR IN EQUITY OR OTHERWISE, INVOLVING ANY DEBT FINANCING RELATED PARTY ARISING OUT OF, OR RELATING TO, THE TRANSACTIONS CONTEMPLATED HEREBY SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK AND (II) EACH OF THE PARTIES AGREES (I) THAT ANY CLAIM, CROSS-CLAIM, SUIT, ACTION OR PROCEEDING OF ANY KIND OR DESCRIPTION, WHETHER IN LAW OR IN EQUITY, WHETHER IN CONTRACT OR IN TORT OR OTHERWISE, INVOLVING ANY OF THE DEBT FINANCING RELATED PARTIES ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OF THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT, THE TRANSACTIONS CONTEMPLATED BY THE COMMITMENT OR THE PERFORMANCE OF SERVICES THEREUNDER SHALL BE SUBJECT TO THE EXCLUSIVE JURISDICTION OF A STATE OR FEDERAL COURT SITTING IN THE BOROUGH OF MANHATTAN WITHIN THE CITY OF NEW YORK AND THE APPELLATE COURTS THEREOF, (II) NOT TO BRING OR PERMIT ANY OF THEIR AFFILIATES TO BRING OR SUPPORT ANYONE ELSE IN BRINGING ANY SUCH CLAIM, SUIT, ACTION OR PROCEEDING IN ANY OTHER COURTS, OTHER THAN A STATE OR FEDERAL COURT SITTING IN THE BOROUGH OF MANHATTAN WITHIN THE CITY OF NEW YORK, (II) TO WAIVE AND HEREBY WAIVE, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH ANY OF THEM MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF, AND THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF, ANY SUCH ACTION IN ANY SUCH COURT, AND (IV) THAT ANY SUCH CLAIM, CONTROVERSY OR DISPUTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

16.16Severability. If any term or other provision of this Agreement is invalid, illegal, or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any Party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

16.17Removal of Name.As promptly as practicable, but in any case within thirty (30) days after the Closing Date, Buyer shall eliminate the names of Seller and any of its Affiliates and any variants thereof from the Assets acquired pursuant to this Agreement and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Seller or any of its Affiliates.

16.18Counterparts. This Agreement may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission or other electronic transmission shall be deemed an original signature hereto.

16.19Time is of the Essence. With respect to all dates and time periods in this Agreement, time is of the essence. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (or the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

16.20No Recourse.

(a)Notwithstanding anything that may be expressed or implied in this Agreement or any other Transaction Document, Buyer, on behalf of its Affiliates and its and their representatives, covenants, agrees and acknowledges that no Person other than Seller (and its successors or assignees, as applicable) has any obligation hereunder and that, neither Buyer, its Affiliates or its or their representatives have any right of recovery under this Agreement or any other Transaction Document against, and no personal liability under this Agreement or any Transaction Document shall attach to, any of Seller’s former, current or future equity holders, controlling persons, directors, officers, employees, general or limited partners, members, managers, Affiliates or agents, or any former, current or future equity holder, controlling person, director, officer, employee, general or limited partner, member, manager, Affiliate or agent of any of the foregoing (collectively, each of the foregoing but not including Seller, a “Seller Non-Recourse Party”), through Buyer or otherwise, whether by or through attempted piercing of the corporate, limited partnership or limited liability company veil, by or through a claim by or on behalf of Buyer against any Seller Non-Recourse Party, by the enforcement of any assessment or by any legal or equitable proceeding, by virtue of any applicable Law, whether in contract, tort or otherwise.

(b)Notwithstanding anything that may be expressed or implied in this Agreement or any other Transaction Document, Seller, on behalf of its Affiliates and its and their representatives, covenants, agrees and acknowledges that no Person other than Buyer (and its successors or assignees, as applicable), has any obligation hereunder and that, neither Seller, its Affiliates or its or their representatives have any right of recovery under this Agreement or any other Transaction Document against, and no personal liability under this Agreement or any Transaction Document shall attach to, any of Buyer’s former, current or future equity holders, controlling persons, directors, officers, employees, general or limited partners, members, managers, Affiliates or agents, or any former, current or future equity holder, controlling person, director, officer, employee, general or limited partner, member, manager, Affiliate or agent of any of the foregoing (collectively, each of the foregoing but not including Buyer, a “Buyer Non-Recourse Party”), through Seller or otherwise, whether by or through attempted piercing of the corporate, limited partnership or limited liability company veil, by or through a claim by or on behalf of Seller against any Buyer Non-Recourse Party, by the enforcement of any assessment or by any legal or equitable proceeding, by virtue of any applicable Law, whether in contract, tort or otherwise, except to the extent ant Buyer Non-Recourse Party is a direct party to or assignee of any Transaction Document.

16.21No Recourse to Financing Sources. Notwithstanding anything to the contrary contained herein, Seller and its Subsidiaries agree on behalf of themselves and their respective Affiliates that none of the Debt Financing Related Parties shall have any liability or obligation to Seller and its Subsidiaries or any of their respective Affiliates relating to this Agreement or any of the transactions contemplated herein (including the Commitment), in each case whether based on contract, tort or strict liability by the enforcement of any assessment, by any legal or equitable proceeding, by virtue of any statute, regulation or applicable Laws or otherwise and whether by or through attempted piercing of the corporate, limited liability company or partnership veil, by or through a claim by or on behalf of a party hereto or another Person (including a claim to enforce the commitments under the Commitment Documentation) or otherwise. This Section 16.21 is intended to benefit and may be enforced by the Buyer, its Affiliates and the Debt Financing Sources providing the Commitment (and each such Person shall be a third party beneficiary of this Section 16.21) and shall be binding on all the respective successors and permitted assigns of Seller, its controlled Affiliates and each of their respective Affiliates.

[Remainder of page intentionally left blank. Signature pages follow.]

EX-4.10

Exhibit 4.10

Execution Version

AMENDED & RESTATED PURCHASE AND SALE AGREEMENT

by and among

Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp., Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP

as Seller

and

BCE-Mach III LLC

as Buyer
and

Alta Mesa Resources, Inc.,
for the limited purposes set for the in Sections 9.8(b), (c), (f), (g), (i), (j) and (k) hereof

dated January 17, 2020

TABLE OF CONTENTS

Page

ARTICLE I DEFINITIONS AND INTERPRETATION2

1.1 Defined Terms    2

1.2 References and Rules of Construction    22

ARTICLE II ASSET ACQUISITION23

2.1 Asset Acquisition    23

2.2 Excluded Assets    25

2.3 Revenues and Expenses    27

2.4 Assigned Contracts; Cure Costs    27

2.5 Consents for Applicable Contracts    29

ARTICLE III PURCHASE PRICE; DEPOSIT30

3.1 Purchase Price    30

3.2 Deposit    30

3.3 Adjustments to Purchase Price    30

3.4 Closing Settlement Statement; Final Settlement Statement    32

3.5 Disputes    34

3.6 Allocated Values    34

3.7 Allocation for Imbalances    34

3.8 Withholding    35

ARTICLE IV ACCESS / DISCLAIMERS35

i

4.1 Access    35

4.2 Confidentiality    37

4.3 Disclaimers    37

ARTICLE V TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS39

5.1 General Disclaimer of Title Warranties and Representations/Exclusive Remedy    39

5.2 Notice of Title Defects; Title Defect Adjustments    39

5.3 Casualty or Condemnation Loss    44

5.4 Preferential Purchase Rights and Consents to Assign    45

ARTICLE VI ENVIRONMENTAL MATTERS47

6.1 Environmental Defects.    47

6.2 NORM, Wastes and Other Substances.    51

ARTICLE VII REPRESENTATIONS AND WARRANTIES OF SELLER52

7.1 Organization, Existence    52

7.2 Authorization    52

7.3 No Conflicts    52

7.4 Consents    52

7.5 Foreign Person    53

7.6 Claims and Litigation    53

7.7 Material Contracts    53

7.8 No Violation of Laws    54

7.9 Preferential Purchase Rights    54

ii

7.10 Current Commitments    55

7.11 Asset Taxes    55

7.12 Brokers’ Fees    55

7.13 Advance Payments    55

7.14 Bonds and Credit Support    56

7.15 Imbalances    56

7.16 Leases; Suspense Funds    56

7.17 Hedge Contracts    56

7.18 Insurance    56

7.19 Equipment and Personal Property    56

7.20 Wells; Plug and Abandon Notice    56

7.21 Permits    57

7.22 Payouts    57

7.23 Labor and Employment.    57

7.24 Environmental.    57

7.25 Benefit Plans.    57

7.26 No Transfer.    58

ARTICLE VIII BUYER REPRESENTATIONS AND WARRANTIES58

8.1 Organization; Existence    58

8.2 Authorization    58

8.3 No Conflicts    58

8.4 Consents    58

iii

8.5 Bankruptcy    59

8.6 Claims and Litigation    59

8.7 Regulatory    59

8.8 Financing    59

8.9 Independent Evaluation    60

8.10 Brokers’ Fees    60

8.11 Accredited Investor    60

ARTICLE IX CERTAIN AGREEMENTS60

9.1 Conduct of Business    60

9.2 Bonds    63

9.3 Notifications    63

9.4 Financing    64

9.5 Equitable and Other Remedies.    66

9.6 Record Retention.    67

9.7 Successor Operator.    67

9.8 Bankruptcy Court Matters.    67

9.9 Certain Litigation Matters.    70

9.10 Accounting Services.    70

ARTICLE X BUYER’S CONDITIONS TO CLOSING71

10.1 Representations    71

10.2 Performance    71

iv

10.3 No Legal Proceedings    71

10.4 Title Defects, Environmental Defects and Casualty Losses    72

10.5 Certificate    72

10.6 Sale Order    72

10.7 Closing Deliverables    72

10.8 Closing of Transactions under KFM Agreement.    72

ARTICLE XI SELLER’S CONDITIONS TO CLOSING72

11.1 Representations    72

11.2 Performance    73

11.3 No Legal Proceedings    73

11.4 Title Defects, Environmental Defects and Casualty Losses    73

11.5 Certificate    73

11.6 Sale Order    73

11.7 Closing Deliverables    73

11.8 Closing of Transactions under KFM Agreement.    73

ARTICLE XII CLOSING73

12.1 Date of Closing    74

12.2 Place of Closing    74

12.3 Closing Obligations    74

12.4 Records    75

12.5 FCC Filings    75

ARTICLE XIII ASSUMPTION; INDEMNIFICATION; SURVIVAL76

v

13.1 Assumed Obligations; Excluded Obligations    76

13.2 Indemnities of Buyer    78

13.3 Express Negligence    79

13.4 Exclusive Remedy    79

13.5 Indemnification Procedures    80

13.6 Survival    81

13.7 Non-Compensatory Damages    82

13.8 Waiver or Right to Rescission    82

13.9 Insurance    82

13.10 Waiver of Consumer Rights    83

ARTICLE XIV TERMINATION, DEFAULT AND REMEDIES83

14.1 Right of Termination    83

14.2 Effect of Termination    85

14.3 Return of Documentation and Confidentiality    86

ARTICLE XV EMPLOYEES86

15.1 Business Employees    86

15.2 Employee Matters    87

ARTICLE XVI MISCELLANEOUS88

16.1 Exhibits and Schedules    88

16.2 Expenses and Taxes    88

16.3 Value Allocations for Tax Purposes    90

vi

16.4 Assignment; Liquidating Trust    90

16.5 Preparation of Agreement    91

16.6 Publicity    91

16.7 Notices    91

16.8 Further Cooperation    93

16.9 Filings, Notices and Certain Governmental Approvals    93

16.10 Entire Agreement; Conflicts    93

16.11 Successors and Permitted Assigns    94

16.12 Parties in Interest    94

16.13 Amendment    94

16.14 Waiver; Rights Cumulative    94

16.15 Governing Law; Jurisdiction; Venue; Jury Waiver    95

16.16 Severability    97

16.17 Removal of Name    97

16.18 Counterparts    97

16.19 Time is of the Essence    97

16.20 No Recourse    97

16.21 No Recourse to Financing Sources    98

vii

LIST OF EXHIBITS AND SCHEDULES

Exhibits

EXHIBIT A        LEASES; UNITS

EXHIBIT A-1        WELLS

EXHIBIT A-2        OPERATIONS WELLS

EXHIBIT A-3        EASEMENTS

EXHIBIT A-4        RESERVED

EXHIBIT A-5        CERTAIN REAL PROPERTY INTERESTS

EXHIBIT A-6        PUD LOCATIONS

EXHIBIT A-7        SALE AREA

EXHIBIT A-8        VEHICLES

EXHIBIT B-1        FORM OF ASSIGNMENT AND BILL OF SALE

EXHIBIT B-2        FORM OF SURFACE AND MINERAL DEED

EXHIBIT C         EXCLUDED ASSETS

EXHIBIT D        ASSIGNED FCC LICENSES

EXHIBIT E        ACCOUNTING SERVICES

EXHIBIT F        SALE ORDER

EXHIBIT G        FORM OF RELEASE AND EXCULPATION

EXHIBIT H        FORM OF ESCROW AGREEMENT

Schedules

Schedule 1.1        Certain Disclosures

Schedule 2.4        Cure Costs

Schedule 3.3(a)(vi)    Certain AFEs

Schedule 3.6        Allocated Values

Schedule 7.3        No Conflicts

viii

Schedule 7.4        Consents

Schedule 7.6        Litigation

Schedule 7.7(a)     Material Contracts
Schedule 7.7(b)    Material Contract Defaults

Schedule 7.8        Violation of Laws

Schedule 7.9        Preferential Purchase Rights

Schedule 7.10        Current Commitments

Schedule 7.11        Asset Taxes

Schedule 7.14        Bonds and Credit Support

Schedule 7.15        Imbalances

Schedule 7.16        Suspense Funds
Schedule 7.18        Insurance
Schedule 7.20        Wells; Plug and Abandon Notices
Schedule 7.22        Payouts

Schedule 7.24        Environmental

Schedule 7.26        Certain Transfers

Schedule 8.4        Consents

Schedule 9.1        Conduct of Business

Schedule 13.1        Assumed Obligation

Schedule 15.1        Business Employees

ix

AMENDED & RESTATED PURCHASE AND SALE AGREEMENT

This AMENDED & RESTATED PURCHASE AND SALE AGREEMENT (as the same may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is entered into the 17^th day of January, 2020 (the “Execution Date”), by and among Alta Mesa Holdings, LP, a Texas limited partnership (“AMH”), Alta Mesa Holdings GP, LLC, a Texas limited liability company (“AMHGP”), OEM GP, LLC, a Texas limited liability company (“OEMGP”), Alta Mesa Finance Services Corp., a Delaware corporation (“AMFSC”), Alta Mesa Services, LP, a Texas limited partnership (“AMSLP”) and Oklahoma Energy Acquisitions, LP, a Texas limited partnership (“OEA”, and collectively with AMH, AMHGP, OEMGP, AMFSC and AMSLP, “Seller”), BCE-Mach III LLC, a Delaware limited liability company (“Buyer”) and, for the limited purposes set forth in Sections 9.8(b), (c), (f), (g), (i), (j) and (k) of this Agreement, Alta Mesa Resources, Inc., a Delaware corporation (“AMR”). Buyer and Seller may be referred to collectively as the “Parties” or individually as a “Party.”

Recitals

WHEREAS, on September 11, 2019, AMR and Seller filed voluntary petitions for relief, commencing cases under chapter 11 of the Bankruptcy Code (as defined herein) in Bankruptcy Court (as herein defined herein).

WHEREAS, the Parties entered into a purchase and sale agreement on December 31, 2019 (the “Original Execution Date”) for the sale of the Assets pursuant to section 363 of the Bankruptcy Code (the “Original Agreement”) upon the terms and conditions set forth therein, pursuant to which the Parties intended to effectuate the transactions contemplated by the Original Agreement.

WHEREAS, Seller conducted the Auction on January 15, 2020, and Buyer was designated the Successful Bidder for the Assets at the conclusion of the Auction.

WHEREAS, pursuant to Section 16.13 of the Original Agreement, the Parties desire to amend and restate the Original Agreement to incorporate certain amendments to the Original Agreement required by the activities and actions that took place at Auction, and the Parties intend to effectuate the transactions contemplated by this Agreement pursuant to section 363 of the Bankruptcy Code (the “Transaction”).

WHEREAS, the execution and delivery of this Agreement and Seller’s ability to consummate the Transaction are subject to, among other things, the entry of the Sale Order (as hereinafter defined).

WHEREAS, effective as of the Effective Time, Seller desires to sell and convey, and Buyer desires to purchase and pay for, the Assets in accordance with the terms and conditions of this Agreement.

NOW, THEREFORE, for and in consideration of the mutual agreements herein contained, the benefits to be derived by each Party, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1

Article IDEFINITIONS AND INTERPRETATION

1.1Defined Terms. Capitalized terms used herein and not otherwise defined shall have the meanings given such terms as set forth below in this Section 1.1:

“AAA” means the American Arbitration Association.

2“AAA Rules” means the Commercial Arbitration Rules of the AAA.

3“Accounting Arbitrator” has the meaning set forth in Section 3.5.

4“Adjusted Purchase Price” has the meaning set forth in Section 3.3.

5“AFEs” has the meaning set forth in Section 7.10.

6“Affiliate” means, with respect to any Person, any other Person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, such Person. The concept of control, controlling or controlled as used in the aforesaid context means the possession, directly or indirectly, of the power to direct or cause the direction of the management, policies or action of another, whether through the ownership of voting securities, voting trust, by contract, or membership in management or in the group appointing or electing management or otherwise through formal or informal arrangements or business relationships.

7“Aggregate Deductible” means three percent (3%) of the unadjusted Purchase Price.

8“Agreement” has the meaning set forth in the first paragraph herein.

9“Allocable Amount” has the meaning set forth in Section 16.3.

10“Allocated Value” has the meaning set forth in Section 3.6.

11“Allocation Schedule” has the meaning set forth in Section 16.3.

12“AMFSC” has the meaning set forth in the first paragraph herein.

13“AMH” has the meaning set forth in the first paragraph herein.

14“AMHGP” has the meaning set forth in the first paragraph herein.

15“AMR” has the meaning set forth in the first paragraph herein.

16“AMSLP” has the meaning set forth in the first paragraph herein.

17“Applicable Contract Notices” has the meaning set forth in Section 2.4(d).

18“Applicable Contracts” means all Contracts, if any, to which Seller is a party that relate to the Assets, including Contracts to the extent they are used by Seller in the operation or development of the Assets, or any other Contracts by which the Assets are bound and that, subject to the other provisions of this Agreement, will be binding on Buyer after the Closing, including purchase and sale agreements; farmin and farmout agreements; bottomhole agreements; crude oil, condensate, and natural gas purchase and sale, gathering, transportation and marketing agreements;Hydrocarbon storage agreements; acreage contribution agreements; area of mutual interest agreements, operating agreements and balancing agreements; pooling declarations or agreements, including any forced pooling order executed and delivered by the OCC; unitization agreements; processing agreements; surface use agreements; crossing agreements; water supply agreements; saltwater disposal agreements or other waste disposal agreements; facilities or equipment leases; letters of objection; letter agreements; collective bargaining or other Contracts or agreements with any labor union or labor organization (each a “CBA”); and other similar contracts and agreements held by Seller, in each case, to the extent related to Seller’s right, title and interest in the Assets.

19“Applicable Schedule 7.4 Consent” means any Consent set forth on Schedule 7.4 (a) relating to an Applicable Contract for which the counterparty’s consent to assignment would be required for such Applicable Contract to be assumed and assigned to Buyer, after giving effect to sections 365(c)(1) and 365(f)(1) of the Bankruptcy Code, or (b) that burdens a Lease.

20“Asset Credit Support” means any bonds, letters of credit, guarantees or other forms of credit support, if any, posted by Seller or its Affiliates with Governmental Authorities or other Third Parties and relating to the Assets.

21“Asset Taxes” means Property Taxes and Production Taxes, but excluding, for the avoidance of doubt, income, capital gains and franchise Taxes and Transfer Taxes.

22“Assets” has the meaning set forth in Section 2.1.

23“Assigned Contracts” means the Applicable Contracts assumed by Seller and assigned to Buyer pursuant to Section 2.4.

24“Assigned FCC Licenses” has the meaning set forth in Section 2.1(m).

25“Assignment” means the Assignment and Bill of Sale from Seller to Buyer, pertaining to the Assets (other than the Assets covered by the Deed), substantially in the form attached to this Agreement as Exhibit B-1.

26“Assumed Obligations” has the meaning set forth in Section 13.1.

27“Auction” means the auction for the sale of the Assets, if any, to be conducted in accordance with the Bidding Procedures.

28“Avoidance Action” means any claim, right or cause of action of any Seller Party arising under chapter 5 of the Bankruptcy Code and any analogous state or federal statutes and common law relating to the Assets, Assigned Contracts, and Assumed Obligations.

29“Backup Bidder” means the bidder for the Assets with the next-highest or otherwise second-best bid for the Assets as determined in accordance with the Bidding Procedures.

30“Bankruptcy Code” means title 11 of the United States Code.

31“Bankruptcy Court” means the United States Bankruptcy Court for the Southern District of Texas.

32“Benefit Plans” means (a) any bonus, incentive compensation, deferred compensation, pension, profit sharing, retirement, stock purchase, stock option, stock ownership, stock appreciation rights, restricted stock, phantom stock or stock-based, stock or cash award, deferred compensation, leave of absence, layoff, stay, vacation, day or dependent care, legal services, cafeteria, life, health, welfare, post-retirement, accident, disability or other insurance, severance, separation, retention, change of control, employment or other benefit or compensation plan, practice, policy, agreement or arrangement of any kind, whether written or oral, whether for the benefit of a single individual or more than one individual, and whether or not legally enforceable, and (b) any other “employee benefit plan” within the meaning of Section 3(3) of ERISA or any comparable provision of any other applicable Law existing on the Closing Date or prior thereto, in each case, that is established, sponsored, maintained, contributed to or required to be contributed to by Seller or any of its Affiliates, or any predecessor of any of the foregoing, or for which Seller or any of its Affiliates is a party, is subject or may have Liabilities, including with respect to any Business Employee.

33“Bidding Procedures” means the Bidding Procedures attached to the Bidding Procedures Order as Annex 1.

34“Bidding Procedures Order” means the Order Establishing Bidding Procedures Relating to the Sales of All or a Portion of the Debtors’ Assets, entered by the Bankruptcy Court on October 11, 2019 [D.I. 317] approving the Bidding Procedures, as such order may be amended, supplemented or modified from time to time with the consent of Buyer (such consent not to be unreasonably withheld).

35“Burden” means any and all rentals, royalties (including lessors’ royalties and non-participating royalties), overriding royalties, excess royalties, minimum royalties, shut-in royalties, net profits interests, bonuses and other burdens upon, measured by, or payable out of production of Hydrocarbons.

36“Business Day” means any day other than Saturday or Sunday or a day on which banking institutions in Houston, Texas are authorized by Law to close.

37“Business Employee” means each employee of Seller or any of its Affiliates whose primary duties and responsibilities are associated with the operation of the Assets; each of which is set forth on Schedule 15.1.

38“Buyer” has the meaning set forth in the first paragraph herein.

39“BuyerNon-Recourse Party” has the meaning set forth in Section 16.20(b).

40“Buyer Parties” means (a) Bayou City Energy Management LLC; (b) BCE-AMH Holdings, LLC; (c) BCE-AMR Holdings LLC; (d) BCE-MESA Holdings, LLC; (e) William W. McMullen; (f) Mark Stoner; (g) Andrew Koehler; (h) Mach Resources LLC; (i) BCE-Mach LLC; (j) BCE-Mach II LLC; and (k) with respect to each of the foregoing Persons or Entities, such Person or Entities’ respective current and former equity holders, controlled subsidiaries, officers, directors, managers, principals, members, employees, agents, advisory board members, financial advisors, partners, attorneys, accountants, investment bankers, consultants, representatives, and other professionals, each in their capacity as such; provided that under no circumstances shall the Buyer Parties include any Excluded Persons and Entities.

41“Buyer Representatives” has the meaning set forth in Section 4.1(a).

42“Cash Collateral Order” means the order or orders of the Bankruptcy Court (a) authorizing Seller to use the cash collateral of the prepetition lenders and (b) providing the prepetition lenders with adequate protection.

43“Casualty or Condemnation Loss” has the meaning set forth in Section 5.3(b).

44“CBA” has the meaning set forth in the definition of “Applicable Contracts”.

45“Chapter 11 Case” means, collectively, the voluntary cases commenced by Seller in the Bankruptcy Court under Chapter 11 of the Bankruptcy Code on September 11, 2019, jointly administered under the caption In re Alta Mesa Resources Inc., et al., Case No. 19-35133 (MI).

46“Claim Notice” has the meaning set forth in Section 13.5(b).

47“Closing” has the meaning set forth in Section 12.1.

48“Closing Date” has the meaning set forth in Section 12.1.

49“Closing Escrow” means the aggregate amount of funds deposited into the Escrow Account by Buyer at Closing in respect of (a) the Title Disputes, Environmental Disputes, asserted Title Defects that Seller elects at or prior to Closing to cure during the Cure Period, (b) the asserted Environmental Defects that Seller elects at or prior to Closing to cure during the Cure Period, and (c) the amounts to be deposited into the Escrow Account pursuant to Section 3.4(a) (other than, for the avoidance of doubt, amounts described in items (a) and (b) above).

50“ClosingSettlement Statement” has the meaning set forth in Section 3.4(a).

51“COBRA” means the Consolidated Omnibus Budget Reconciliation Act of 1985, Part 6 of Subtitle B of Title I of ERISA, Section 4980B of the Code and any similar state Law.

52“Code” means the Internal Revenue Code of 1986, as amended.

53“Commitment” means the commitment of the Commitment Parties pursuant to the Commitment Documentation.

54“Commitment Documentation” means (i) that certain commitment letter dated January 15, 2020, from Bayou City Energy III, L.P. and BCE-Mach Holdings II, LLC to Buyer with respect to the the AMH Agreement (as amended pursuant to amendments permitted pursuant to the terms thereof), (ii) that certain commitment letter dated January 15, 2020, from Bayou City Energy III, L.P. and BCE-Mach Holdings II, LLC to Buyer with respect to this Agreement (as amended pursuant to amendments permitted pursuant to the terms thereof) and (iii) that certain commitment letter from UBS AG, Stamford Branch and UBS Securities LLC to Buyer with respect to both the KFM Agreement and this Agreement (as amended pursuant to amendments permitted pursuant to the terms thereof), to provide at least the Required Amounts in debt and/or equity financing to Buyer in order to consummate the transactions contemplated by both the KFM Agreement and this Agreement.

55“Commitment Parties” means, collectively, Bayou City Energy III, L.P., BCE-Mach Holdings II, LLC, UBS AG, Stamford Branch and UBS Securities LLC.

56“Confidentiality Agreement” means that certain Confidentiality Agreement dated October 1, 2019 by and between AMR and BCE-Mach LLC.

57“Consent” has the meaning set forth in Section 7.4.

58“Continuing Employee” has the meaning set forth in Section 15.1.

59“Continuing Employee Records” shall mean the following current employment and current personnel information with respect to each Continuing Employee, in each case, to the extent permitted by applicable Law: salary, wage grade, job function, variable compensation targets, performance documentation, and business and personal mailing addresses and telephone numbers, including as applicable, any applicable employment-related agreements, Family and Medical Leave Act (or similar) records and Forms I-9 (Employment Eligibility Verification) related to such Continuing Employee; provided that Continuing Employee Records shall not include any medical records.

60“Contract” means any contract or agreement, but excluding, however, (a) any Lease, easement, right-of-way or other instrument, in each case, creating any oil and gas mineral interests or other real property interests, or (b) any Permit.

61“COPAS” shall mean the Accounting Procedures promulgated by the Council of Petroleum Accountants Societies.

62“Cure Costs” has the meaning set forth in Section 2.4(a).

63“Cure Period” has the meaning set forth in Section 5.2(c).

64“Customary Post Closing Consents” means the consents and approvals from Governmental Authorities for the assignment of the Assets to Buyer, that are customarily and reasonably obtained after the assignment of properties similar to the Assets.

65“Debt Financing Related Parties” means the Debt Financing Sources and other lenders from time to time party to agreements related to the Commitment, their Affiliates and their and their Affiliates’ respective Representatives and their respective successors and permitted assigns.

66“Debt Financing Sources” means the lenders, arrangers and bookrunners (including the lenders) (or any of their Affiliates) party from time to time to the Commitment Documentation.

“Deed” means that Surface and Mineral Deed from Seller to Buyer, pertaining to the fee minerals and surface fee interests included in the Assets, substantially in the form attached to this Agreement as Exhibit B-2.

67“Deloitte” has the meaning set forth in Section 3.5.

68“Defect Claim Date” means on or before 5:00 p.m. (Central Prevailing Time) on the date that is 30 days after the Original Execution Date.

69“Defensible Title” means such right, title and interest of Seller that, although not constituting perfect, merchantable or marketable title, (x) is deducible of record or, (y) if not deducible of record, title evidenced by spacing and forced pooling orders promulgated by the OCC, or by elections made pursuant to joint operating agreements, production sharing agreements, pooling agreements or unitization agreements which, in each case of (x) and (y), as of the Effective Time and the Defect Claim Date, subject to Permitted Encumbrances:

(a)with respect to each Title Well shown in Exhibit A-1, entitles Seller to receive not less than the Net Revenue Interest shown in Exhibit A-1 for such Title Well throughout the productive life of such Title Well, except for (i) decreases in connection with those operations in which Seller may from and after the Original Execution Date elect to be a non-consenting co-owner (to the extent permitted by this Agreement), (ii) decreases resulting from the establishment or amendment from and after the Original Execution Date of pools or units (to the extent permitted by this Agreement), including amendments to forced pooling orders promulgated by the OCC, (iii) decreases resulting from changes in tract or production allocations resulting from elections by Third Parties to participate or not participate in operations after the Original Execution Date, (iv) decreases required to allow other Working Interest owners to make up past underproduction or pipelines to make up past underdeliveries, (v) decreases resulting from actions taken on behalf of or directed by Buyer, (vi) decreases resulting from any reversion of interest to a co-owner with respect to operations in which such co-owner, after the Original Execution Date, elects not to consent and (vii) as otherwise expressly stated in Exhibit A-1;

(b)with respect to each Title Well shown in Exhibit A-1, obligates Seller to bear a percentage of the costs and expenses for the development and maintenance of, and operations relating to, such Title Well of not more than the Working Interest shown in Exhibit A-1 for such Title Well throughout the productive life of such Title Well, except (i) increases resulting from contribution requirements with respect to defaulting co-owners from and after the Original Execution Date under applicable operating agreements, (ii) increases to the extent that such increases are accompanied by a proportionate increase in Seller’s Net Revenue Interest with respect to such Title Well, (iii) increases resulting from changes in tract or production allocations resulting from elections by Third Parties to participate or not participate in operations after the Original Execution Date, (iv) increases resulting from actions taken on behalf of or directed by Buyer, (v) increases resulting from the establishment or amendment from and after the Original Execution Date of pools or units (to the extent permitted by this Agreement), including amendments to forced pooling orders promulgated by the OCC and (vi) as otherwise expressly stated in Exhibit A-1; and

(c)with respect to each Subject Property, is Free and Clear,

in each case, only as to the applicable Target Formation for the applicable Subject Property.

70“Deposit” has the meaning set forth in Section 3.2(a).

71“Designation Deadline” means 5:00 p.m. (Central Time) on the date that is five Business Days prior to the Target Closing Date, or such later date as Buyer and Seller shall mutually agree and, if applicable, as the Bankruptcy Court may authorize.

72“Dispute Notice” has the meaning set forth in Section 3.4(a).

73“Effective Time” means 12:01 a.m. (Central Prevailing Time) on January 1, 2020.

“Encumbrance” means all liens, whether consensual or statutory (including mechanic’s, materialman’s, carrier’s, repairer’s, contractor’s and other similar liens arising under applicable Laws), replacement liens, adequate protection liens or other liens granted under Sections 361, 363 or 364 of the Bankruptcy Code, mortgages, deeds of trust, hypothecations, pledges, security interests, charges, options and transfer restrictions, including without limitation, rights of first refusal or first offer, defect or objection liens, easements, encroachments or servitudes, in each case, that constitutes an “interest” for purposes of Bankruptcy Code § 363(f), including without limitation those charges or interests in property within the meaning of “lien” under Bankruptcy Code § 101(37) or any other limitation, restriction or interest that constitutes an “interest” for the purposes of Bankruptcy Code § 363(f).

“Entity” shall have the meaning set forth in section 101(15) of the Bankruptcy Code.

74“Environmental Arbitrator” has the meaning set forth in Section 6.1(f).

75“Environmental Condition” meansa condition that causes a Property (or Seller with respect to a Property) not to be in compliance with or subject to Liability under an Environmental Law. For the avoidance of doubt, (a) the fact that a Well is no longer capable of producing sufficient quantities of oil or gas to continue to be classified as a “producing well” shall, in each case, not form the basis of an Environmental Condition, (b) the fact that a pipe is temporarily not in use shall not form the basis of an Environmental Condition, and (c) except with respect to Personal Property (i) that causes or has caused contamination of soil, surface water or groundwater or (ii) the use or condition of which is a violation of Environmental Law, the physical condition of any surface or subsurface Personal Property, including water or oil tanks, separators or other ancillary equipment, shall not form the basis of an Environmental Condition.

76“Environmental Defect” means an Environmental Condition existing on the Original Execution Date or the Defect Claim Date with respect to any Property.

77“Environmental Defect Notice” and “Environmental Defect Notices” have the meanings set forth in Section 6.1(a).

78“Environmental Defect Property” has the meaning set forth in Section 6.1(a).

79“Environmental Disputes” has the meaning set forth in Section 6.1(f).

80“Environmental Laws” means any applicable Law relating to public or worker health or safety (regarding Hazardous Materials), pollution or the protection of the environment, including air, water, or land. The term “Environmental Laws” does not include good or desirable operating practices or standards that may be voluntarily employed or adopted by other oil and gas well operators or recommended, but not required, by a Governmental Authority.

81“Environmental Liability” means any Liability (a) resulting from or attributable to the actual or threatened Release of Hazardous Materials into the environment or resulting from or attributable to exposure to Hazardous Materials; (b) resulting from or attributable to the generation, manufacture, processing, distribution, use, treatment, storage, Release or threatened Release, transport or handling of Hazardous Materials; or (c) otherwise arising under or related to Environmental Laws or the violation thereof.

82“ERISA” means the Employee Retirement Income Security Act of 1974.

83“ERISA Affiliate” means any Person that, together with Seller or any of its Affiliates, is (or at any relevant time has been or would be) treated as a single employer under Section 414 of the Code.

84“Escrow Account” means the account maintained by Escrow Agent in connection with the Escrow Agreement.

85“Escrow Agent” means Prime Clerk LLC.

86“Escrow Agreement” means that certain Escrow Agreement to be entered into by and among Buyer, Seller and Escrow Agent at Closing in substantially the form attached hereto as Exhibit H.

87“Excluded Assets” has the meaning set forth in Section 2.2.

88“Excluded Contracts” means all Applicable Contracts, other than Assigned Contracts.

89“Excluded Persons and Entities” means each of (a) KFM Holdco, LLC, (b) High Mesa Inc. and all of its subsidiaries, (c) Alta Mesa Resources, Inc., and its subsidiaries, (d) Riverstone VI Alta Mesa Holdings, L.P. and any of its related Persons or Entities that would otherwise be included in the definition of Representatives (as defined in the Sale Order) of Buyer or the Buyer Parties, in their respective capacities as equity holders or Affiliates of Buyer or any of the Buyer Parties, (e) HPS Investment Partners, LLC and any of its related Persons or Entities that would otherwise be included in the definition of Representatives (as defined in the Sale Order) of Buyer or the Buyer Parties, in their respective capacities as equity holders or Affiliates of Buyer or any of the Buyer Parties.

90 “Execution Date” has the meaning set forth in first paragraph herein.

91“FCC” means the Federal Communications Commission.

92“FCC Licenses” means any licenses, permits, certificates, approvals, franchises, consents, waivers, registrations or other authorizations issued by the FCC.

93“Fee Letters” has the meaning set forth in Section 9.4(a).

94“Final Order” means any award, decision, decree, settlement, order, injunction, ruling, judgment, or consent of or entered, issued, made or rendered by any Governmental Authority as to which the time to file an appeal, a motion for rehearing or reconsideration or a petition for writ of certiorari has expired and no such appeal, motion or petition is pending.

95“Final Settlement Statement” has the meaning set forth in Section 3.4(b).

96“Free and Clear” means free and clear of all claims, Encumbrances or Liabilities other than the Assumed Obligations and Permitted Encumbrances, in each case to the maximum extent permitted by section 363(f) of the Bankruptcy Code.

97“GAAP” means generally accepted accounting principles as used in the United States of America.

98“Gathering Agreements” means, collectively, (a) that certain Crude Oil Gathering Agreement by and between OEA and Kingfisher Midstream, LLC, dated as of August 31, 2015; (b) that certain Gas Gathering and Processing Agreement, by and between OEA and Kingfisher Midstream, LLC, dated as of August 31, 2015; and (c) that certain Water Gathering and Disposal Agreement, by and between OEA and Oklahoma Produced Water Solutions, LLC, dated as of October 1, 2018, in each case, as amended, modified or supplemented from time to time.

99“Governmental Authority” means any federal, state, county, city, local, municipal, tribal, foreign or other government; any governmental, quasi-governmental, regulatory or administrative agency, commission, department, board, bureau, body, official or other authority or instrumentality exercising or entitled to exercise any administrative, executive, judicial, legislative, regulatory or taxing authority or power; and any court, arbitral body (public or private) or other tribunal, including any tribal authority having or asserting jurisdiction with respect to the Properties.

100“Hazardous Materials” means any: (a) pollutants, contaminants, toxic or hazardous or extremely hazardous substances, materials, wastes, constituents, compounds, products or chemicals that are regulated by or included in the definition of “hazardous substance,” “hazardous material,” “hazardous waste,” “restricted hazardous waste,” “extremely hazardous waste,” “solid waste,” “toxic waste,” “extremely hazardous substance,” “chemical substance,” “toxic pollutant,” “contaminant” or “pollutant”, or may form the basis of liability under, any Environmental Laws; (b) Hydrocarbons, petroleum, petrochemical or petroleum products, petroleum substances, natural gas liquid, condensate, natural gas, crude oil or any components, fractionations or derivatives thereof or any mixtures containing any of the foregoing; (c) oil and gas exploration and production wastes, including produced and flow back waters; and (d) asbestos containing materials, mercury, polychlorinated biphenyls, mold, radioactive materials, urea formaldehyde foam insulation, or radon gas.

101“Highest or Best Proposal” shall mean any bona fide proposal or offer to or from a Person other than Buyer or its representatives with respect to (a) any plan of reorganization or liquidation, proposal, offer, dissolution, winding up, liquidation, reorganization, merger, consolidation, business combination, joint venture, partnership, sale of assets or equity interests or restructuring involving the Assets, or (b) any other direct or indirect acquisition involving the Assets, that, in each case, the independent manager of AMHGP has determined in good faith, after consultation with its outside financial advisors and outside legal counsel, would, if consummated, result in the highest or otherwise best transaction for Seller, taking into account all terms thereof, including (x) the likelihood and timing of consummation, and (y) all material legal, financial (including the financing terms of any such proposal), conditionality, regulatory and other aspects of such proposal.

102“Hydrocarbons” means oil, gas and other hydrocarbons (including casinghead gas and condensate) produced or processed in association therewith (whether or not such item is in liquid or gaseous form), including all crude oils, condensates and natural gas liquids at atmospheric pressure and all gaseous hydrocarbons (including wet gas, dry gas and residue gas) or any combination thereof, and sulphur, carbon dioxide and any other minerals extracted from, attributable to or produced in association therewith.

103“Imbalances” means all Well Imbalances and Pipeline Imbalances.

104“Indemnified Party” has the meaning set forth in Section 13.5(a).

105“Indemnifying Party” has the meaning set forth in Section 13.5(a).

106“Individual Environmental Defect Threshold” has the meaning set forth in Section 6.1(e).

107“Individual Title Defect Threshold” has the meaning set forth in Section 5.2(h).

108“Initial Applicable Contract Notice” has the meaning set forth in Section 2.4(d).

109“Instruments of Conveyance” means, collectively, the Assignment and Deed.

110“Interim Period” means the period of time commencing with the Effective Time and ending immediately prior to Closing.

111“KFM Agreement” means the Amended and Restated Purchase and Sale Agreement by and among Kingfisher Midstream, LLC, Oklahoma Produced Water Solutions, LLC, Kingfisher STACK Oil Pipeline, and Cimarron Express Pipeline, LLC (the “KFM Sellers”), and Buyer dated January 17, 2020.

112“KFM Sellers” has the meaning set forth in the definition of “KFM Agreement”.

113“Knowledge” means, (i) with respect to Seller, the actual knowledge (without due investigation or inquiry) of the following Persons: Mark Castiglione, John Regan, John Campbell, David Murrell and Randy Limbacher; and (ii) with respect to Buyer, the actual knowledge (without due investigation or inquiry) of the following Persons: Daniel T. Reineke, Jr. and Kevin White.

114“Law” means any applicable statute, law (including any obligation arising under the common law), rule, statute, act, regulation, ordinance, order, code, ruling, writ, injunction, award, judgment, decree or other official act of or by any Governmental Authority.

115“Leases” has the meaning set forth in Section 2.1(a).

116“Liabilities” means any and all claims, causes of actions, payments, charges, judgments, assessments, losses, monetary damages, penalties, fines, fees, Taxes, interest obligations, deficiencies, debts, obligations, costs and expenses and other liabilities (whether absolute, accrued, contingent, fixed or otherwise, or whether known or unknown, or due or to become due or otherwise), including any amounts paid in settlement, interest, court costs, costs of investigators, attorneys’ fees, legal or other expenses incurred in connection therewith.

117“Liquidating Trust” means a liquidating or similar trust as may be established with respect to Seller’s estate in conjunction with the Chapter 11 Cases.

118“Liquidating Trustee” means the trustees or other representative of the Liquidating Trust.

119“Material Adverse Effect” means, with respect to Seller, any change, inaccuracy, effect, event, result, occurrence, condition or fact (for the purposes of this definition, each, an event) (whether foreseeable or not and whether covered by insurance or not) that, individually or in the aggregate, has resulted or could reasonably be expected to result in, (x) a material adverse effect upon the ability of Seller to consummate the transactions contemplated by this Agreement, or to perform its obligations hereunder, or (y) a material adverse effect on the ownership, operation, financial condition or value of the Assets, taken as a whole, as currently owned and operated as of the Original Execution Date; provided, however, that Material Adverse Effect shall not include such material adverse effects resulting from: (a) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (b) changes in general market, economic, financial or political conditions (including changes in commodity prices, fuel supply or transportation markets, interest or rates, or general market prices in the Hydrocarbon exploration, production, development, processing, gathering or transportation industry generally) in the area in which the Assets are located, the United States or worldwide; (c) changes in conditions or developments generally applicable to the oil and gas industry in the area where the Assets are located; (d) acts of God, including hurricanes, storms or other naturally occurring events; (e) acts or failures to act of Governmental Authorities, except as a result of the action or inaction of Seller or its Affiliates; (f) civil unrest, any outbreak of disease or hostilities, terrorist activities or war or any similar disorder; (g) any actions taken or omitted to be taken by or at the written request or with the prior written consent of Buyer or required by the terms of this Agreement; (h) matters that are cured or no longer exist by the earlier of Closing and the termination of this Agreement, including matters to the extent a downward purchase price adjustment is provided for under this Agreement; (i) any change in Laws or in GAAP and any interpretations thereof from and after the Original Execution Date; (j) Casualty or Condemnation Losses; (k) any reclassification or recalculation of reserves; (l) natural declines in well performance; (m) the commencement or pendency of the Chapter 11 Case; (n) any objections in the Bankruptcy Court to (i) this Agreement and the other Transaction Documents and the transactions contemplated hereby and thereby, (ii) the reorganization of Seller and any related plan of reorganization or disclosure statement, (iii) the Bidding Procedures or the sale motion, or (iv) the assumption or rejection of any Material Contract; (o) any order of the Bankruptcy Court (except any such order that would preclude or prohibit Seller from consummating the transactions contemplated by this Agreement) or any actions or omissions of Seller in compliance therewith; and (p) any of the matters disclosed on any Exhibit or Schedule to this Agreement.

120“Material Contracts” has the meaning set forth in Section 7.7.

121“Net Revenue Interest” means, with respect to any Title Well, the interest in and to all Hydrocarbons produced, saved and sold from or allocated to such Title Well, after giving effect to all Burdens.

122“New Commitment” has the meaning set forth in Section 9.4(b)(iv).

123“NORM” means naturally occurring radioactive material.

124“OCC” means the Oklahoma Corporation Commission.

125“OEA” has the meaning set forth in the first paragraph herein.

126“OEMGP” has the meaning set forth in the first paragraph herein.

“Offered Employees” has the meaning set forth in Section 15.1.

“OneOk” means Oneok Gas Transportation, LLC.

“OneOk Contracts” means, collectively, the Applicable Contracts between Seller and OneOk or any Affiliate of OneOk, and “OneOk” means any of them.

127“Operating Expenses” means all (a) operating expenses (including costs of insurance) and capital expenditures paid or payable to Third Parties incurred in the ownership and operation of the Assets in the ordinary course of business and, where applicable, under and pursuant to the relevant operating or unit agreement or forced pooling order, if any and (b) all Third Party overhead costs charged to the Assets under the relevant operating or unit agreement or forced pooling order (in each case, to the extent the same is an Assigned Contract), if any; but excluding (in all cases) Liabilities attributable to (i) personal injury or death, property damage, torts, breach of contract or violation of any Law, (ii) obligations relating to the abandonment or plugging of Wells, dismantling or decommissioning facilities, closing pits and restoring the surface around such Wells, facilities and pits, (iii) Environmental Liabilities, (iv) obligations with respect to Imbalances, (v) obligations to pay Burdens or other interest owners revenues or proceeds attributable to sales of Hydrocarbons relating to the Assets, including Suspense Funds, (vi) obligations with respect to hedging Contracts, (vii) obligations with respect to Taxes, (viii) any costs or expenses incurred to cure or remediate (or to attempt to cure or remediate) any Title Defects or Environmental Defects (including any Title Defect Amounts or Remediation Amounts), (ix) amounts (if any) incurred to obtain any Required Consent, (x) any amounts incurred to cure or attempt to cure any breaches of this Agreement or any Casualty or Condemnation Loss, (xi) any Cure Costs, (xii) any costs to maintain Asset Credit Support and (xiii) claims for indemnification or reimbursement from any Third Party with respect to costs of the types described in the preceding clauses (i) through (xii), whether such claims are made pursuant to contract or otherwise.

128“Operations Wells” has the meaning set forth in Section 2.1(b).

129“Original Agreement” has the meaning set forth in the Recitals.

130“Original Execution Date” has the meaning set forth in the Recitals.

131“Original Deposit” has the meaning set forth in Section 3.2(a).

132“Outside Termination Date” means April 15, 2020.

133“Party” and “Parties” have the meanings set forth in the first paragraph herein.

134“Permit” has the meaning set forth in Section 2.1(d).

135“Permitted Encumbrances” means:

(a)the terms and conditions of all Applicable Contracts, Leases and Burdens if the net cumulative effect of such Applicable Contracts, Leases and Burdens does not: (i) materially interfere with the operation or use of the Assets as currently operated and used; (ii) decrease the Net Revenue Interest with respect to any Title Well to an amount less than the Net Revenue Interest set forth in Exhibit A-1 for such Title Well; or (iii) obligate Seller to bear a Working Interest with respect to any Title Well in an amount greater than the Working Interest set forth in Exhibit A-1 for such Title Well (unless the Net Revenue Interest for such Title Well is greater than the Net Revenue Interest set forth in Exhibit A-1 in the same proportion as any increase in such Working Interest);

(b)Preferential Purchase Rights;

(c)liens for Taxes or assessments (A) (i) not yet due or delinquent; (ii) the nonpayment of which is permitted or required by the Bankruptcy Code; or (iii) that if delinquent, that are being contested in good faith by appropriate proceedings by or on behalf of Seller, (B) are set forth on Schedule 1.1, and (C) that are permanently and fully extinguished with respect to the Assets pursuant to the Sale Order;

(d)any Consents (including Customary Post Closing Consents), and any required notices to, or filings with, Governmental Authorities in connection with the consummation of the transactions contemplated by this Agreement;

(e)excepting circumstances where such rights have already been triggered, conventional rights of reassignment upon final intention to abandon or release the Assets, or any of them;

(f)such Title Defects as Buyer has waived or is deemed to have been waived pursuant to the terms of this Agreement;

(g)all applicable Laws and all rights reserved to or vested in any Governmental Authority: (i) to control or regulate any Asset in any manner; (ii) by the terms of any right, power, franchise, grant, license or permit, or by any provision of Law, to terminate such right, power, franchise grant, license or permit or to purchase, condemn, expropriate or recapture or to designate a purchaser of any Asset; (iii) to use such property in a manner which does not materially impair the use of such property for the purposes for which it is currently owned and operated; or (iv) to enforce any obligations or duties affecting the Asset to any Governmental Authority with respect to any franchise, grant, license or permit;

(h)rights of a common owner of any interest in rights-of-way, permits or easements held by Seller and such common owner as tenants in common or through common ownership, in each case, to the extent the same does not: (i) materially interfere with the operation or use of the Assets as currently operated and used; (ii) decrease the Net Revenue Interest with respect to any Title Well to an amount less than the Net Revenue Interest set forth in Exhibit A-1 for such Title Well; or (iii) obligate Seller to bear a Working Interest with respect to any Title Well in an amount greater than the Working Interest set forth in Exhibit A-1 for such Title Well (unless the Net Revenue Interest for such Title Well is greater than the Net Revenue Interest set forth in Exhibit A-1 in the same proportion as any increase in such Working Interest);

(i)easements, conditions, covenants, restrictions, servitudes, permits, rights-of-way, surface leases and other similar rights for the purpose of surface or other operations, facilities, pipelines, transmission lines, transportation lines, distribution lines, power lines, telephone lines and other like purposes, or for the joint or common use of the lands, rights-of-way, facilities and equipment, in each case, to the extent the same does not: (i) materially interfere with the operation or use of the Assets as currently operated and used; (ii) decrease the Net Revenue Interest with respect to any Title Well to an amount less than the Net Revenue Interest set forth in Exhibit A-1 for such Title Well; or (iii) obligate Seller to bear a Working Interest with respect to any Title Well in an amount greater than the Working Interest set forth in Exhibit A-1 for such Title Well (unless the Net Revenue Interest for such Title Well is greater than the Net Revenue Interest set forth in Exhibit A-1 in the same proportion as any increase in such Working Interest);

(j)vendor’s, carrier’s, warehousemen’s, repairmen’s, mechanic’s, workmen’s, materialmen’s, construction or other like liens arising by operation of Law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations (i) which are not yet due or (ii) if delinquent, that are being contested in good faith by appropriate proceedings by or on behalf of Seller and are set forth on Schedule 1.1 and, in each case of (i) and (ii), that will be permanently and fully extinguished with respect to the Assets pursuant to the Sale Order;

(k)liens created under Leases, Permits, easements, rights-of-way or Applicable Contracts, or by operation of Law in respect of obligations which (i) are not yet due or (ii), if delinquent, which are being contested in good faith by appropriate proceedings by or on behalf of Seller and are set forth on Schedule 1.1and, in each case of (i) and (ii), that will be permanently and fully extinguished with respect to the Assets pursuant to the Sale Order;

(l)any Encumbrance affecting the Assets that is permanently and fully discharged by Seller at or prior to Closing;

(m)any matters set forth in Exhibit A or Exhibit A-1, all litigation and claims set forth on Schedule 7.6 and all Imbalances set forth on Schedule 7.15;

(n)limitations (including drilling and operating limitations) imposed on the Assets by reason of the rights of subsurface owners or operators in a common property (including the rights of coal, utility and timber owners), in each case, to the extent the same does not prevent or materially impair the operation or use of the Assets subject thereto as currently operated and used and are set forth on Schedule 1.1;

(o)all depth restrictions or limitations applicable to any Asset set forth in Exhibit A or Exhibit A-1;

(p)any matter that would not constitute a Title Defect under the terms of this Agreement; and

(q)all other Encumbrances, instruments, obligations, defects and irregularities affecting the Assets that individually or in the aggregate that do not: (i) materially interfere with the ownership, operation or use of the Assets as currently operated and used; (ii) decrease the Net Revenue Interest with respect to any Title Well to an amount less than the Net Revenue Interest set forth in Exhibit A-1 for such Title Well; or (iii) obligate Seller to bear a Working Interest with respect to any Title Well in an amount greater than the Working Interest set forth in Exhibit A-1 for such Title Well (unless the Net Revenue Interest for such Title Well is greater than the Net Revenue Interest set forth in Exhibit A-1 in the same proportion as any increase in such Working Interest).

136“Person” means any individual, firm, corporation, company, partnership, joint venture, limited partnership, limited liability company, association, trust, estate, labor union, organization, Governmental Authority or any other entity.

137“Personal Property” has the meaning set forth in Section 2.1(c).

138“Pipeline Imbalance” means any marketing imbalance between the quantity of Hydrocarbons attributable to the Assets required to be delivered by Seller under any Contract relating to the gathering, transportation, marketing, storage or processing (including any production handling and processing at a separation facility) and the quantity of Hydrocarbons attributable to the Assets actually delivered by Seller pursuant to the relevant Contract, together with any appurtenant rights and obligations concerning production balancing at the delivery point into the relevant sale, gathering, transportation, storage or processing facility, including corresponding cash settlement obligations.

139“Preferential Purchase Right” has the meaning set forth in Section 7.9.

140“Production Taxes” has the meaning set forth in Section 16.2(d).

141“Property” and “Properties” has the meaning set forth in Section 2.1(b).

142“Property Taxes” has the meaning set forth in Section 16.2(c).

143“PUD Location” means the interest in Hydrocarbons that would be produced from or attributable to a hypothetical well (or recompletion of a Well) as identified on Exhibit A-6.

144“Purchase Price” has the meaning set forth in Section 3.1.

145“Push-Out Election” has the meaning set forth in Section 16.2(g).

146“Records” has the meaning set forth in Section 2.1(i).

147“Release” means any presence, releasing, depositing, spilling, leaking, pumping, pouring, placing, emitting, discarding, abandoning, emptying, discharging, migrating, injecting, escaping, leaching, dumping, or disposing into the environment.

148“Remediation” means, with respect to any Environmental Condition, the implementation and completion of any remedial, removal, response, construction, closure, disposal or other corrective actions required or necessary under Environmental Laws to fully correct or remove such Environmental Condition.

149“Remediation Amount” means, with respect to any Environmental Condition asserted in relation to an Environmental Defect Notice, the cost (net to Seller’s interest in the Assets) of the lowest cost Remediation of such Environmental Condition that is effective and reasonably available and in full compliance with Environmental Laws; provided, however, that “Remediation Amount” shall not include (a) the costs of Buyer’s or its Affiliates’ employees, or, if Seller is conducting the Remediation, Buyer’s project manager(s) or attorneys, (b) expenses for matters that are ordinary costs of doing business regardless of the presence of an Environmental Condition (e.g., those costs that would ordinarily be incurred in the day-to-day operations of the Assets or in connection with Permit renewal/amendment activities), (c) overhead costs of Buyer or its Affiliates, or (d) any costs or expenses relating to the assessment, remediation, removal, abatement, transportation and disposal of any asbestos, asbestos-containing materials or NORM unless resulting in a violation of Environmental Laws. The lowest cost Remediation may include taking no action, leaving the condition unaddressed, periodic monitoring or the recording of notices in lieu of Remediation, to the extent such responses are permitted and allowed under Environmental Laws.

150“Required Consent”has the meaning set forth in Section 5.4(b)(i).

151“Required Amounts” has the meaning set forth in Section 9.4(a).

152“Sale Area” means that area set forth on Exhibit A-7.

153“Sale Order” means an order of the Bankruptcy Court substantially in the form attached hereto as Exhibit F authorizing and approving, inter alia, the sale of the Assets to Buyer on the terms and conditions set forth herein, Free and Clear, the releases set forth therein, and authorizing and approving the assumption and assignment of the Assigned Contracts to Buyer.

154“Section 754 Election” has the meaning set forth in Section 16.2(g).

155“Seller” has the meaning set forth in the first paragraph herein.

156“Seller Indemnified Parties” has the meaning set forth in Section 13.2.

157“SellerNon-Recourse Party” has the meaning set forth in Section 16.20(a).

158“Seller Party” means each of AMH, AMHGP, OEMGP, AMFSC, AMSLP and OEA, individually.

159“Seller Representatives” means each Seller Party and its respective members, partners or shareholders, as the case may be, and its Affiliates and its and their respective successors and assigns, and the officers, board of directors or managers, employees, agents, advisors and representatives of all of the foregoing Persons.

160“Seller Taxes” means any (a) income, capital gains, franchise or similar Taxes of Seller or its Affiliates, (b) Asset Taxes allocated to Seller pursuant to Section 16.2 taking into account, and without duplication of, such Asset Taxes effectively borne by Seller as a result of the adjustments to the Purchase Price made pursuant to Section 3.3 or 3.4, as applicable, (c) Taxes attributable to the Excluded Assets and (d) Taxes (other than Taxes described in clause (a), (b) or (c)) attributable to the Assets for periods (or portions thereof) before the Effective Time.

161“Subject Property” means any Title Well.

162“Successful Bid” has the meaning set forth in the Bidding Procedures Order.

163“Successful Bidder” means the bidder for the Assets with the highest or otherwise best bid for the Assets as determined in accordance with the Bidding Procedures.

164“Supplemental Applicable Contract Notice” has the meaning set forth in Section 2.4(d).

165“Supplemental Deposit” has the meaning set forth in Section 3.2(a).

166“Suspense Funds” means funds held in suspense (including funds held in suspense for unleased interests and penalties and interest) that are attributable to the Assets or any interests pooled, unitized or communitized therewith.

167“TargetClosing Date” has the meaning set forth in Section 12.1.

168“Target Formation” means, as to any Well, the formation from which such Title Well is producing on the Original Execution Date, and as to any PUD Location, the formation set forth on Exhibit A‑6 for such PUD Location.

169“Tax” or “Taxes” means all (a) taxes, assessments, duties, levies, imposts, unclaimed property and escheat obligations or other similar charges imposed by a Governmental Authority, including all income, franchise, profits, capital gains, capital stock, transfer, gross receipts, sales, use, transfer, service, occupation, ad valorem, property, excise, severance, windfall profit, premium, stamp, license, payroll, employment, social security, unemployment, disability, environmental, add-on, value-added, withholding (including backup withholding) and other taxes, assessments, duties, levies, imposts or other similar charges of any kind (whether payable directly or by withholding and whether or not requiring the filing of a Tax Return), and all estimated taxes, deficiency assessments, additions to tax, additional amounts imposed by any Governmental Authority, penalties and interest and (b) any liability in respect of any items described in clause (a) above that arises by reason of a Contract, transferee or successor liability or operation of Law (including by reason of participation in a consolidated, combined or unitary Tax Return) or otherwise.

170“Tax Partnership” has the meaning set forth in Section 7.11.

171“Tax Return” means any return, declaration, report or information return (including any related or supporting estimates, elections, schedules, statements, or information) filed or required to be filed in connection with the determination, assessment, or collection of any Tax.

172“Third Party” means any Person other than a Party to this Agreement or an Affiliate of a Party to this Agreement.

173“Third PartyClaim” has the meaning set forth in Section 13.5(b).

174“Title Arbitrator” has the meaning set forth in Section 5.2(i).

175“Title Benefit” means any right, circumstance or condition that operates to (a) increase the Net Revenue Interest for any Title Well such that the actual Net Revenue Interest for such Title Well is greater than the Net Revenue Interest shown in Exhibit A-1 for such Title Well to the extent the same does not cause a greater than proportionate increase in Seller’s Working Interest therein, or (b) decrease the Working Interest for any Title Well such that the actual Working Interest for such Well is less than the Working Interest shown in Exhibit A-1 for such Title Well to the extent the same does not cause any decrease in the Net Revenue Interest for such Title Well shown in Exhibit A-1 for such Title Well.

176“Title Benefit Amount” means, with respect to any Title Benefit Property, the amount equal to the increase in the Allocated Value for such Title Benefit Property as determined pursuant to Section 5.2(g) or Section 5.2(i).

177“Title Benefit Notice” has the meaning set forth in Section 5.2(b).

178“Title Benefit Property” has the meaning set forth in Section 5.2(b).

179“Title Defect” means any title failure, loss of title or Encumbrance that causes Seller not to have Defensible Title in and to any Subject Property; provided that the following shall not be considered Title Defects:

(a)defects in the chain of title consisting of the failure to recite marital status in a document or the omissions of (i) affidavits or similar instruments reflecting heirship or (ii) estate proceedings, unless Buyer provides evidence that such failure would result in another Person’s superior claim of title to the relevant Subject Property;

(b)defects arising out of lack of survey, unless a survey is expressly required by applicable Laws;

(c)defects arising out of lack of corporate or other entity authorization in the public records, unless Buyer provides evidence that such corporate or other entity action would result in another Person’s superior claim of title to the relevant Subject Property;

(d)defects based on a gap in Seller’s chain of title to any Subject Property in the applicable federal, state or county records, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain or runsheet, which documents shall be included in a Title Defect Notice;

(e)defects based upon the failure to record (i) any state or federal Leases or right-of-way included in the Assets or any assignments of interests in such Leases or rights-of-way included in the Assets or (ii) any forced pooling order executed and delivered by the OCC, in each case, in any applicable county records, unless such failure would result in another Person’s superior claim of title to the relevant Subject Property; and the Parties acknowledge that in the event of any defects, discrepancies or irregularities in the Working Interests or Net Revenue Interests in the Assets as evidenced in the chain of title records in any applicable county as compared to any forced pooling order subsequently executed and delivered by the OCC, the Working Interests and Net Revenue Interests as evidenced in such forced pooling order shall control for all purposes of this Agreement;

(f)defects based upon the exercise of any Preferential Purchase Right after the Original Execution Date;

(g)defects based solely on the failure of any of the Leases to have pooling provisions;

(h)any Encumbrance or loss of title resulting from Seller’s conduct of business after the Original Execution Date pursuant to actions specifically required of Seller pursuant to this Agreement or otherwise in compliance with this Agreement;

(i)defects arising from any change in Laws after the Original Execution Date, including changes that would raise the minimum landowner royalty;

(j)defects that affect only which Person has the right to receive Burden payments (rather than the amount of the proper payment of such Burden payment) and that do not affect the validity of the underlying Lease, in each case, to the extent the same does not operate to: (i) materially interfere with the operation or use of the Assets as currently operated and used; (ii) decrease the Net Revenue Interest with respect to any Title Well to an amount less than the Net Revenue Interest set forth in Exhibit A-1 for such Title Well; or (iii) obligate Seller to bear a Working Interest with respect to any Title Well in an amount greater than the Working Interest set forth in Exhibit A-1 for such Title Well (unless the Net Revenue Interest for such Title Well is greater than the Net Revenue Interest set forth in Exhibit A-1 in the same proportion as any increase in such Working Interest);

(k)defects arising from any Encumbrance created under deeds of trust, mortgages and similar instruments by the lessor under a Lease, which Encumbrance has not been subordinated to the lessee’s interest and for which a reasonably prudent lessee would not customarily seek a subordination of such Encumbrance to the oil and gas leasehold estate prior to conducting drilling activities on the applicable Lease and, in each case, excluding any such Encumbrance if a complaint of foreclosure has been duly filed or any similar action taken by the mortgagee or trustee thereunder;

(l)defects arising from any Encumbrance created by a mineral owner which has not been subordinated to the lessee’s interest, unless a complaint of foreclosure has been duly filed or any similar action taken by the mortgagee thereunder, and in such case such mortgage has not been subordinated to the Lease applicable to such Asset;

(m)defects based solely on: (i) lack of information in Seller’s files, (ii) references to an unrecorded document to which neither Seller nor any Affiliate of Seller is a party, if such document is not in Seller’s files, or (iii) any Tax assessment, Tax payment or similar records or the absence of such activities or records;

(n)defects arising from any prior oil and gas lease relating to the lands covered by the Leases or Units not being surrendered of record, unless Buyer provides affirmative evidence that such prior oil and gas lease is still in effect and would result in another Person’s actual and superior claim of title to the relevant Lease or Title Well;

(o)all defects or irregularities resulting from the failure to record releases, Encumbrances or production payments that have expired on their own terms; and

(p)any maintenance of uniform interest provision in any Assigned Contract.

180“Title Defect Amount” has the meaning set forth in Section 5.2(d)(i).

181“Title Defect Notice” has the meaning set forth in Section 5.2(a).

182“Title Defect Property” has the meaning set forth in Section 5.2(a).

183“Title Disputes” has the meaning set forth in Section 5.2(i).

184“Title Well” means a Well or PUD Location, as applicable.

185“Transaction” has the meaning set forth in the recitals of this Agreement.

186“Transaction Documents” means those documents executed or delivered pursuant to or in connection with this Agreement on the Closing Date.

187“Transfer Taxes” means any sales, use, excise, real property transfer, registration, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees incurred and imposed upon, or with respect to, the property transfers to Buyer contemplated by this Agreement as well as any interest, penalty or addition thereto whether disputed or not.

188“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of amended, succeeding, similar, substitute, proposed or final Treasury Regulations.

189“Units” has the meaning set forth in Section 2.1(a).

190“Well Imbalance” means any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well and allocable to the interests of Seller therein and the share of production from the relevant Well to which Seller is entitled, together with any appurtenant rights and obligations concerning future in kind or cash balancing at the wellhead.

191“Wells” has the meaning set forth in Section 2.1(b).

192“Willful Breach” means, with respect to any Party, that such Party knowingly does one or more of the following: (a) such Party willfully and intentionally breaches in any material respect (by refusing to perform or taking an action prohibited) any material pre-Closing covenant, obligation or agreement applicable to such Party, or (b) such Party willfully and intentionally causes any of its representations or warranties under this Agreement to not be true and correct in all material respects after the Original Execution Date and prior to the Closing Date. For clarity, if a Party is obligated hereunder to use its commercially reasonable efforts to perform an action or to achieve a result, the failure to use such commercially reasonable efforts would constitute a willful and intentional breach of this Agreement.

193“Working Interest” means, with respect to any Lease or Title Well, the interest in and to such Lease or Title Well that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such Lease or Title Well, but without regard to the effect of any Burdens.

1.2References and Rules of Construction. All references in this Agreement to Exhibits, Schedules, Articles, Sections, subsections and other subdivisions refer to the corresponding Exhibits, Schedules, Articles, Sections, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Articles, Sections, subsections and other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language hereof. The words “this Agreement,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular Article, Section, subsection or other subdivision unless expressly so limited. The word “including” (in its various forms) means including without limitation. Unless expressly provided to the contrary, the word “or” is not exclusive. All references to “$” or “dollars” shall be deemed references to United States dollars. Each accounting term not defined herein, and each accounting term partly defined herein to the extent not defined, will have the meaning given to it under GAAP as in effect from time to time. Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Except as expressly provided otherwise in this Agreement, references to any Law or agreement means such Law or agreement as it may be amended from time to time. References to any date shall mean such date in Houston, Texas and for purposes of calculating the time period in which any notice or action is to be given or undertaken hereunder, such period shall be deemed to begin at 12:01 a.m. on the applicable date in Houston, Texas. The word “extent” in the phrase “to the extent” shall mean the degree or proportion to which a subject or other thing extends, and such phrase shall not mean simply “if.” If a date specified herein for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

ARTICLE IIASSET ACQUISITION

2.1Asset Acquisition. Upon the terms and subject to the conditions of this Agreement, and for the consideration specified in Section 3.1, Seller agrees to sell, assign, transfer and convey, and Buyer agrees to purchase and pay for, all of Seller’s right, title and interest in and to the following assets (less and except for the Excluded Assets, such interest of Seller in such assets, collectively, the “Assets”):

(a)all Hydrocarbon leases (and all leasehold estates created thereby), subleases, mineral fee interests, working interests, overriding royalties, production payments, net profits interests, non-participating royalty interests, non-participating mineral interests, carried interests, options, rights to Hydrocarbons in place, and all other oil and gas interests of any kind or character derived therefrom, in each case, located within the Sale Area, including all such interests described in Exhibit A (Seller’s interest in such leases and other interests, the “Leases”), together with all rights, privileges, benefits and powers conferred upon Seller as the holder of the Leases with respect to the use and occupation of the surface of the lands covered thereby, and together with any and all rights, titles and interests of Seller in and to any units or pooling arrangements (including statutory forced pooling orders) wherein all or any part of the Leases are pooled or unitized, including the units and pooling arrangements set forth in Exhibit A (Seller’s interest in such units or pools, the “Units”), and including all interests of Seller derived from the Leases in production of Hydrocarbons from any such Unit, whether such Unit production of Hydrocarbons comes from Wells located on or off of a Lease;

(b)(i) each of the Hydrocarbon wells located on or under the Leases or the Units (whether or not completed), including the wells set forth on Exhibit A-1, whether such wells are producing, shut-in or abandoned (Seller’s interest in such wells, the “Wells”), and (ii) each of the fresh water wells, injection wells, salt water disposal wells and other wells of every nature and kind located on the Leases or Units, including the wells set forth on Exhibit A-2, whether such wells are currently in use or temporarily shut in or abandoned (the “Operations Wells”, and collectively with the Leases, Units and Wells, the “Properties”, and each individually a “Property”);

(c)all equipment, gathering systems, pipelines, flow lines, water lines, machinery, fixtures, improvements and other real, personal and mixed property, operational or nonoperational that is located on the lands within the Sale Area or otherwise used in connection with the Properties or the other Assets, including well equipment, casing, tubing, pumps, motors, machinery, rods, tanks, tank batteries, pipes, compressors, meters, separators, heaters, treaters, boilers, fixtures, structures, materials and other items and appurtenances relating to or used in connection with the ownership or operation of the Properties or the other Assets (Seller’s interest in such properties, collectively, the “Personal Property”);

(d)to the extent assignable (provided that Seller will use commercially reasonable efforts to obtain any necessary consent to assignment, without any obligation to incur any out-of-pocket cost or expense or provide any other consideration), any permit, license, registration, consent, order, approval, variance, exemption, waiver, franchise, right or other authorization (in each case) of any Governmental Authority (the “Permits”) relating to the ownership or operation of the Properties, but excluding FCC Licenses;

(e)to the extent assignable (provided that Seller will use commercially reasonable efforts to obtain any necessary consent to assignment, without any obligation to incur any out-of-pocket cost or expense or provide any other consideration), all of the easements, rights-of-way, surface fee interests, surface leases, surface use agreements and other surface usage rights existing as of the Closing Date to the extent used in connection with the ownership or operation of the Properties or other Assets, including those set forth on Exhibit A-3 - Part 2;

(f)all Assigned Contracts;

(g)subject to the approval of the transfer of any applicable Assigned FCC Licenses (but without limiting Section 12.5), all radio and communication towers, personal computers, SCADA systems and wellhead communications systems and other equipment and automation systems and related telemetry on wells, any central SCADA server and all software associated with any SCADA system (including any network equipment and associated peripherals), all radio and telephone equipment and all licenses relating thereto, in each case that are used in connection with the operation of the Properties or other Assets;

(h)all offices, warehouses, laydown yards and other similar assets located in the Sale Area (including any owned or leased real or personal property relating thereto), including those described on Exhibit A-5;

(i)all books, records and files, reports, Asset Tax and accounting records, in each case to the extent relating to the Assets, including: (i) land and title records (including lease files, division order files, Third Party brokerage information, run sheets, mineral ownership reports, abstracts of title, surveys, maps, elections, well files, title opinions and title curative documents); (ii) contract files; (iii) correspondence; (iv) facility files (including construction records); (v) well files, proprietary seismic data and information, production records, electric logs, core data, pressure data, and all related matters; (vi) all licensed geological, geophysical and seismic data and information which is transferable without payment of any Third Party fee (or for which Buyer has agreed in writing to pay such Third Party fee); (vii) the Continuing Employee Records; and (viii) environmental, regulatory, accounting and Asset Tax records; but excluding any of the foregoing items to the extent comprising or otherwise attributable to the Excluded Assets (the foregoing, subject to such exclusion, the “Records”);

(j)all trucks, cars and vehicles, including those listed on Exhibit A-8;

(k)all Hydrocarbons produced from or allocated to the Properties on and after the Effective Time and all production proceeds attributable thereto;

(l)all rights, claims and causes of action (including all audit rights, rights of indemnity, set-off or refunds and any and all rights and interests of Seller under any policy or agreement of insurance) of Seller to the extent (and only to the extent) such rights, claims or causes of action relate to any of the Assumed Obligations (other than (i) Avoidance Actions which shall be addressed solely by Section 2.1(n) and (ii) any rights, claims and causes of action against any Excluded Persons and Entities);

(m)those FCC Licenses that are held by Seller or an Affiliate of Seller and described on ExhibitD (the “Assigned FCC Licenses”); and

(n)except (i) as otherwise released pursuant to the Sale Order and (ii) for any Avoidance Actions against any Excluded Persons and Entities, all Avoidance Actions.

2.2Excluded Assets. Seller shall reserve and retain, on its own behalf or on behalf of certain of its Affiliates, all of the following assets (the “Excluded Assets”):

(a)all of Seller’s corporate minute books and corporate Tax or financial records that relate to Seller’s business generally (including the ownership and operation of the Assets);

(b)except to the extent related to any Assumed Obligations, all trade credits, all accounts receivable, if any, and all other proceeds, income or revenues attributable to the Assets with respect to any period of time prior to the Effective Time;

(c)except to the extent related to any Assumed Obligations, all claims, causes of action, manufacturers’ and contractors’ warranties and other rights of Seller arising under or with respect to (i) any Assets that are attributable to periods of time prior to the Effective Time including claims for adjustments or refunds, and (ii) any other Excluded Assets;

(d)subject to Section 5.3(b), all rights and interests of Seller (i) under any policy or agreement of insurance or (except to the extent related to any Assumed Obligations) indemnity, (ii) under any bond or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property, and in each of clauses (i) and (iii), except to the extent related to any Assumed Obligations;

(e)all Hydrocarbons produced from the Properties with respect to all periods prior to the Effective Time (including all production proceeds attributable thereto) other than those Hydrocarbons produced from or allocated to the Assets and in storage or existing in stock tanks, pipelines or plants (including inventory) as of the Effective Time;

(f)all claims of Seller for refunds of or loss carry forwards with respect to Seller Taxes;

(g)all of Seller’s proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property;

(h)all documents and instruments and other data or information of Seller that may be protected by an attorney-client privilege (other than title opinions, Third Party-authored environmental reports or evaluations, and any documents and instruments that relate to or cover any Assumed Obligations);

(i)all documents and instruments and other data or information that cannot be disclosed to Buyer as a result of confidentiality arrangements under agreements with Third Parties (provided that Seller shall use commercially reasonable efforts to obtain waivers of any such confidentiality arrangements or permit Buyer to execute a joinder agreement with respect thereto, without any obligation to incur any out-of-pocket cost or expense or provide any other consideration);

(j)except to the extent related to any Assumed Obligations, all audit rights arising under any of the Applicable Contracts or otherwise with respect to (i) any period prior to the Effective Time, with respect to the Assets or (ii) any of the Excluded Assets;

(k)documents prepared or received by Seller or its Affiliates with respect to (i) lists of prospective purchasers for such transactions compiled by Seller or its Affiliates, (ii) bids submitted by other prospective purchasers of the Assets or any other interest in the Assets, (iii) analyses by Seller or its Affiliates of any bids submitted by any prospective purchaser, (iv) correspondence between or among Seller or its Affiliates or their respective representatives, and any prospective purchaser other than Buyer, and (v) correspondence between Seller or its Affiliates or any of their respective representatives with respect to any of the bids, the prospective purchasers or the transactions contemplated in this Agreement;

(l)Seller’s reserve studies, estimates and evaluations, estimates and valuations of assets or unliquidated liabilities, pilot studies, engineering, production, financial or economic studies, reports or forecasts, and any and all similar forward-looking economic, evaluative, or financial information relating to the Assets, and all licensed geological, geophysical or seismic data which data is non-transferable or which transfer requires the payment of a Third Party fee (unless Buyer agrees in writing to pay such fee);

(m)any Assets described in Section 2.1(e) or Section 2.1(f) that are not assignable (provided that Seller will use commercially reasonable efforts to obtain any necessary consents to assignment with respect thereto without any obligation to incur any out-of-pocket cost or expense or provide any other consideration);

(n)the sponsorship of, and all assets attributable to, the Benefit Plans and any other benefit or compensation plan, program, policy, or arrangement of any kind at any time sponsored, maintained, contributed to or required to be contributed to by Seller or any of its Affiliates or under or with respect to which Seller or any of its Affiliates has (or has had) any Liability;

(o)all drilling rigs and all other properties and assets specifically identified on Exhibit C;

(p)all master services agreements and similar Contracts and all Excluded Contracts;

(q)all engagements and similar letters and agreements with Seller’s legal advisors, it being agreed that Buyer shall have no right to claim, own or waive any attorney-client or similar privilege in favor of Seller or any of its Affiliates with respect to the ownership or operation of the Assets; and

(r)any assets or properties otherwise expressly identified as Excluded Assets under this Agreement.

2.3Revenues and Expenses. For purposes of determining the amount of the adjustment to the Purchase Price provided for in Section 3.3, the principles set forth in this Section 2.3 shall apply except as expressly provided otherwise in this Agreement. Subject to the preceding sentence: (i) Seller shall remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds, if any) and shall remain responsible for all Operating Expenses, in each case attributable to the Assets for the period of time prior to the Effective Time, (ii) and subject to the occurrence of the Closing, Buyer shall be entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) attributable to the Assets for the period of time from and after the Effective Time, and shall be responsible for all Operating Expenses attributable to the Assets for the period of time from and after the Effective Time. Such amounts that are received or paid prior to Closing shall be accounted for in the Closing Settlement Statement or Final Settlement Statement, as applicable. Such amounts that are received or paid after Closing but prior to the date of the Final Settlement Statement shall be accounted for in the Final Settlement Statement. For the avoidance of doubt, the date an item or work is ordered is not the date of a transaction for settlement purposes in the Closing Settlement Statement or Final Settlement Statement, as applicable, but rather the date on which the item ordered is delivered to the job site, or the date on which the work ordered is performed, is the relevant date (i.e., on an accrual basis). “Earned” and “incurred”, as used in this Agreement, shall be interpreted in accordance with GAAP and COPAS standards, as applied by Seller in the ordinary course of business consistent with past practice, subject to the other provisions of this Section 2.3. For purposes of allocating production (and accounts receivable with respect thereto), under this Section 2.3, (a) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Wells when they pass through the pipeline connecting into the storage facilities into which they are transported from the lands covered by the applicable Well, or if there are no storage facilities, when they pass through the LACT meter or similar meter at the entry point into the pipelines through which they are transported from such lands and (b) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Wells when they pass through the delivery point sales meters or similar meters at the entry point into the pipelines through which they are transported from such lands. Seller shall utilize reasonable interpolative procedures to arrive at an allocation of production when exact meter readings (including gas production meters or sales meters) or gauging and strapping data is not available.

2.4Assigned Contracts; Cure Costs.

(a)At the Closing, Buyer shall pay, pursuant to Section 365 of the Bankruptcy Code, Section 1123(b)(2) of the Bankruptcy Code, and the Sale Order, any and all costs or expenses that are required to be paid under sections 365(b)(1)(A), 365(b)(1)(B), and 1123(b)(2) of the Bankruptcy Code, as applicable, to cure any defaults in connection with the assumption and assignment of the Assigned Contracts (such costs or expenses required to be paid by Buyer, the “Cure Costs”). For the avoidance of doubt, (i) Buyer shall pay all Cure Costs in cash at such time as is provided in the preceding sentence, and (ii) neither Buyer nor any Buyer Affiliates shall be required to make any payment of Cure Costs for, and neither Buyer nor any Buyer Affiliates shall assume or have any obligation for any Liabilities with respect to, any Excluded Contract.

(b)Schedule 2.4 sets forth each Applicable Contract and Seller’s good faith estimate of the amount of the Cure Costs payable in respect of each such Applicable Contract (and if no Cure Cost is estimated to be payable in respect of any Applicable Contract, the amount of such Cure Cost designated for such Applicable Contract shall be “$0.00”). Seller shall use its reasonable best efforts to provide, and to cause the Seller Representatives to provide, financial and other pertinent information regarding the Applicable Contracts, as is reasonably requested by Buyer, including using Seller’s reasonable best efforts to furnish Buyer’s financing sources with such financial and other pertinent information regarding such Applicable Contracts as may be reasonably requested. Seller shall amend or supplement Schedule 2.4 from time to time promptly, and shall provide Buyer written notice thereof, upon its determination that any Seller Party is party to an Applicable Contract that is not then set forth on Schedule 2.4.

(c)Prior to the Execution Date,and subject to Buyer’s rights under Section 2.4(e) below to subsequently amend such designations, Buyer delivered to Seller schedules of the Applicable Contracts to be assumed by Seller and assigned to Buyer (as Assigned Contracts) at the Closing. Seller shall commence appropriate proceedings before the Bankruptcy Court and otherwise take all reasonably necessary actions in order to determine Cure Costs with respect to any Assigned Contracts including providing sufficient notice in accordance with the Bidding Procedures Order to all counterparties to the Assigned Contracts of their assumption or rejection and, with respect to the Assigned Contracts to be assumed, providing a schedule of Cure Costs. Any Applicable Contracts that are not set forth on such list of Applicable Contracts to be assumed shall be Excluded Contracts and deemed rejected, and shall be an Excluded Asset for all purposes hereof.

(d)Buyer acknowledges that, prior to the Execution Date, Seller delivered written notices in a form reasonably acceptable to Buyer (the “Initial Applicable Contract Notices”) of the potential assignments of the Applicable Contracts then known to Seller and the proposed Cure Costs for each such Applicable Contract (consistent with Seller’s good faith estimates of such Cure Costs at the times such Initial Applicable Contract Notices were delivered) to all non-debtor parties to such Applicable Contracts, which notice provided notice to each non-debtor party to such Applicable Contract of (i) the proposed Cure Cost for such Applicable Contract and (ii) an objection deadline for such non-debtor party to object to the proposed Cure Cost. To the extent Schedule 2.4 is supplemented from time to time to include additional Applicable Contracts in accordance with Section 2.4(b) above, Seller shall, as promptly as is practicable, deliver written notice (each, a “Supplemental Applicable Contract Notice” and, together with the Initial Applicable Contract Notice, the “Contract Notices”) to the counterparties to such Applicable Contracts of the potential assignment of such Applicable Contracts and the proposed Cure Costs for such Applicable Contracts (consistent with Seller’s good faith estimates set forth in Schedule 2.4), in substantially the same form as the Initial Applicable Contract Notice. To the extent that any objections are received from such non-debtor parties in response to such Contract Notices, Seller shall take all reasonably necessary actions (excluding providing any payment of Cure Costs unless funded by Buyer) to resolve such disputes with the applicable non-debtor party, and all such resolutions with respect to any Assigned Contract shall be acceptable to Buyer in its sole discretion.

(e)At any time prior to the Designation Deadline, Buyer shall have the right, which may be exercised in Buyer’s sole discretion, to provide written notice to Seller of Buyer’s election to designate any Applicable Contract (including any Contract that is an Assigned Contract immediately before such designation) (i) as an Excluded Contract and upon such designation such Contract shall constitute an Excluded Contract and, if applicable, shall cease to constitute an Assigned Contract or (ii) to the extent not already rejected, as an Assigned Contract and upon such designation such Contract shall constitute an Assigned Contract and shall cease to constitute an Excluded Contract. If an Applicable Contract is subject to a cure dispute or other dispute as to the assumption or assignment of such Applicable Contract that has not been resolved to the mutual satisfaction of Buyer and Seller prior to the Designation Deadline, then the Designation Deadline shall be extended (but only with respect to such Applicable Contract) to no later than the earliest of (A) the date on which such dispute has been resolved to the mutual satisfaction of Buyer and Seller, (B) the date on which such Applicable Contract is deemed rejected by operation of Sections 365(d)(4) or 1123(b)(2) of the Bankruptcy Code, as applicable, or (C) the date required by the Bankruptcy Court and set forth in the Sale Order. The election form executed and delivered pursuant to Section 2.4(d) shall be deemed automatically amended to reflect changes made pursuant to this Section 2.4(e).

(f)If Buyer exercises its rights in Section 2.4(e) above to designate an Applicable Contract (including an Applicable Contract that was an Assigned Contract immediately before such designation) as an Excluded Contract, there shall be no change in the Purchase Price as a result of such designation or change in designation.

(g)Notwithstanding anything in this Agreement to the contrary, Seller shall not reject any Applicable Contracts without the prior written consent of Buyer in its sole discretion; provided that, after the Designation Deadline, Seller may reject Excluded Contracts without the consent of Buyer so long as such Applicable Contracts were identified to Buyer in writing prior to the Designation Deadline. In the event that Seller identifies (whether before or after the Designation Deadline) any additional Applicable Contracts capable of being assumed or rejected that were not previously identified as such, Seller shall promptly notify Buyer of (i) such Applicable Contracts and (ii) Seller’s good faith estimate of the amount of the Cure Costs payable in respect of each such Applicable Contract by supplementing Schedule 2.4 as required by Section 2.1(b). For the avoidance of doubt, Buyer may designate each such additional Applicable Contract described in the immediately preceding sentence as an Assigned Contract or Excluded Contract pursuant to this Section 2.4, notwithstanding the passage of the Designation Deadline. The election form executed and delivered pursuant to Section 2.4(c) shall be deemed automatically amended to reflect changes made pursuant to this Section 2.4(g).

(h)Notwithstanding anything in this Agreement to the contrary, including Section 2.4(e) above, the Gathering Agreements shall at all times constitute Assigned Contracts and shall be assigned to Buyer at the Closing.

2.5Consents for Applicable Contracts. For all purposes of this Agreement (including all representations and warranties of Seller contained herein), Seller shall be deemed to have obtained all required consents (including all Required Consents) in respect of the assumption and assignment of any Applicable Contract if, and only to the extent that, (i) Seller has properly served under the Bankruptcy Code notice of assumption and/or assignment on the counterparty to such Applicable Contract, (ii) any objections to assumption and/or assignment filed by such counterparty have been withdrawn or overruled (including pursuant to the Sale Order or other order of the Bankruptcy Court), and (iii) pursuant to the Sale Order, Seller is authorized to assume and assign such Applicable Contract to Buyer pursuant to section 365 of the Bankruptcy Code or otherwise and any applicable Cure Costs have been satisfied by Buyer as provided in this Agreement.

ARTICLE IIIPURCHASE PRICE; DEPOSIT

3.1Purchase Price. The consideration for the transfer of the Assets and the transactions contemplated hereby shall be (a) the assumption of the Assumed Obligations and (b) an amount equal to $232,000,000.00to be paid in cash by Buyer to Seller, by wire transfer in same day funds at Closing as provided for in this Agreement (the “Purchase Price”).

3.2Deposit.

(a)On January 2, 2020, Buyer deposited into an account maintained by Escrow Agent in respect of the Chapter 11 Case, by wire transfer in same day funds, the sum of $22,475,000.00, which represented ten percent of the unadjusted Purchase Price under the Original Agreement (such amount, together with any interest earned thereon, the “Original Deposit”). On or before 5:00 p.m. (Central Prevailing Time) on January 20, 2020, Buyer shall deposit into an account maintained by Escrow Agent in respect of the Chapter 11 Case, by wire transfer in same day funds, an additional $725,000.00 (such amount, together with any interest earned thereon, the “Supplemental Deposit”, and the Supplemental Deposit together with the Original Deposit, the “Deposit”). If the Closing occurs, the Deposit shall be applied toward the Adjusted Purchase Price at Closing pursuant to Section 12.3.

(b)If this Agreement is terminated in accordance with Section 14.1, the provisions of Section 14.2 shall be applicable and the Deposit shall be handled in accordance therewith.

3.3Adjustments to Purchase Price. The Purchase Price shall be adjusted as follows, determined on an accrual basis in conjunction with Section 2.3 and otherwise in accordance with GAAP and COPAS, as applicable (and the resulting amount shall be herein called the “Adjusted Purchase Price”):

(a)The Purchase Price shall be adjusted upward by the following amounts (without duplication):

(i)to the extent the proceeds for such volumes have not been received by Seller or its Affiliates, an amount equal to the value of all Hydrocarbons attributable to the Assets in storage or existing in stock tanks, pipelines or plants (including inventory, but excluding tank bottoms (which volumes of tank bottoms shall be estimated in good faith by Seller), the value to be based upon a gross price of $55.00/Bbl; in each case, net of (A) amounts payable as Burdens on such production and (B) reasonable and documented expenses (other than Operating Expenses) directly incurred by Seller to Third Parties in earning or receiving such proceeds;

(ii)an amount equal to all non-reimbursed Operating Expenses paid (whether prepaid or otherwise) by Seller that are allocable to Buyer pursuant to Section 2.3;

(iii)the amount of all Asset Taxes prorated to Buyer in accordance with Section 16.2 but paid or payable by Seller;

(iv)to the extent that Seller is underproduced as of the Effective Time as shown with respect to the net Well Imbalances set forth in Schedule 7.15, the product of (X) the underproduced volumes of liquid Hydrocarbons, multiplied by (Y) $55.00/Bbl (provided that as of the Original Execution Date, such amount was estimated to be zero, but is subject to further adjustment as provided in Section 3.7);

(v)to the extent that Seller has overdelivered any Hydrocarbons as of the Effective Time as shown with respect to the net Pipeline Imbalances set forth in Schedule 7.15, the product of (X) the overdelivered volumes of liquid Hydrocarbons, multiplied by (Y) $55.00/Bbl (provided that as of the Original Execution Date, such amount was estimated to be zero, but is subject to further adjustment as provided in Section 3.7);

(vi)the aggregate amount associated with the AFEs identified on Schedule 3.3(a)(vi);

(vii)an amount equal to $2,175,000, to account for Seller’s general and administrative costs and expenses related to the ownership and management of the Assets during the period between the Effective Time and Closing;

(viii)any other amount provided for elsewhere in this Agreement or otherwise agreed in writing by Seller and Buyer.

(b)The Purchase Price shall be adjusted downward by the following amounts (without duplication):

(i)an amount equal to all proceeds received by Seller attributable to the sale of Hydrocarbons produced from or allocable to the Assets during the Interim Period, net of (A) amounts payable as Burdens on such production and (B) expenses (other than Operating Expenses) directly incurred by Seller in earning or receiving such proceeds and any fees payable or incurred in connection therewith not reimbursed to Seller by a Third Party purchaser;

(ii)subject to Section 5.2(h), any reductions to the Purchase Price on account of Title Defects in accordance with Section 5.2(c) or Section 5.2(d) (taking into account any applicable Title Benefit Amounts in accordance with Section 5.2(e));

(iii)subject to Section 6.1(e), any reduction to the Purchase Price on account of Environmental Defects in accordance with Section 6.1(b);

(iv)the Allocated Value of any Assets excluded from the transactions contemplated by this Agreement pursuant to Section 4.1(b), Section 5.2(d)(ii), Section 5.4(a)(i), Section 5.4(b)(i) orSection 6.1(c)(ii);

(v)the amount of all Asset Taxes prorated to Seller in accordance with Section 16.2 but paid or payable by Buyer;

(vi)to the extent that Seller is overproduced as of the Effective Time as shown with respect to the net Well Imbalances set forth in Schedule 7.15 (but subject to further adjustment as provided in Section 3.7), the product of (X) the overproduced volumes of liquid Hydrocarbons, multiplied by (Y) $55.00/Bbl (provided that as of the Original Execution Date, such amount was estimated to be zero, but is subject to further adjustment as provided in Section 3.7);

(vii)to the extent that Seller has underdelivered any Hydrocarbons as of the Effective Time as shown with respect to the net Pipeline Imbalances set forth in Schedule 7.15 , the product of (X) the underdelivered volumes of liquid Hydrocarbons, multiplied by (Y) $55.00/Bbl (provided that as of the Original Execution Date, such amount was estimated to be zero, but is subject to further adjustment as provided in Section 3.7);

(viii)all Suspense Funds that are held in suspense by Seller as of the Closing Date, if any;

(ix)an amount equal to all non-reimbursed Operating Expenses paid (whether prepaid or otherwise) by Buyer that are allocable to Seller pursuant to Section 2.3; and

(x)any other amount provided for elsewhere in this Agreement or otherwise agreed in writing by Seller and Buyer.

3.4Closing Settlement Statement; Final Settlement Statement.

(a)Not less than five Business Days prior to the Closing, Seller shall prepare and submit to Buyer for review a draft settlement statement (the “Closing Settlement Statement”) that shall set forth Seller’s good faith estimate of the Adjusted Purchase Price, reflecting each proposed adjustment to be made in accordance with this Agreement as of the date of preparation of such Closing Settlement Statement and the calculation of the adjustments used to determine such amount (provided that, to the extent actual amounts are not available for any particular adjustment as of the date of preparation, such adjustment shall reflect Seller’s good faith estimate based on all information reasonably available to Seller at the time, including estimated Operating Expenses and Hydrocarbon revenues attributable to the Assets for the period between the Effective Time and the month the Closing occurs), together with the designation of Seller’s accounts for the wire transfers of funds as set forth in Section 12.3(d). Within three Business Days after receipt of the Closing Settlement Statement, Buyer will deliver to Seller a written report prepared in good faith containing all changes that Buyer proposes to be made to the Closing Settlement Statement, if any (including proposed changes to Seller’s good faith estimates, where applicable), together with a brief explanation of such changes (a “Dispute Notice”). The Closing Settlement Statement, as agreed upon by the Parties, will be used to adjust the Purchase Price at Closing; provided that, if the Parties cannot agree on any adjustment in the Closing Settlement Statement prior to the Closing (including with respect to any estimated adjustment), Buyer shall deposit into the Escrow Account a portion of the Purchase Price equal to the positive difference between Seller’s proposed adjustment and Buyer’s proposed adjustment (as set forth in the Dispute Notice) for such disputed adjustments (adjusted for any amounts therein actually agreed by the Parties prior to Closing), and such amounts shall be credited towards the Adjusted Purchase Price at Closing, subject to resolution as between the Parties prior to the Final Settlement Date or, if applicable, as provided in Section 3.5.

(b)On or before the date that is 90 days following the Closing Date (or, if later, 10 days following the resolution of all disputed matters related to Title Defects and Environmental Defects in accordance with Section 5.2(i) and Section 6.1(f), as applicable), a final settlement statement (the “Final Settlement Statement”) will be prepared by Seller, based on actual revenues and expenses and that takes into account all final adjustments made to the Purchase Price and shows the resulting final Adjusted Purchase Price. The Final Settlement Statement shall set forth the actual allocation of the amounts required by this Agreement. Seller shall supply reasonable documentation in the possession of Seller or any of its Affiliates to support the items for which adjustments are proposed or made in the Final Settlement Statement and a brief explanation of any such adjustments and the reasons therefor. As soon as practicable, and in any event within 15 daysafter receipt of the Final Settlement Statement, Buyer will deliver to Seller a Dispute Notice containing any proposed changes to the Final Settlement Statement and a brief explanation of such changes. Any changes not included in a Dispute Notice (including any Dispute Notice delivered pursuant to Section 3.4(a) above) shall be deemed waived, and Seller’s determinations with respect to all such elements of the Final Settlement Statement that are not addressed in the Dispute Notice (including any Dispute Notice delivered pursuant to Section 3.4(a) above) shall prevail. If the final Adjusted Purchase Price set forth in the Final Settlement Statement is mutually agreed upon by Seller and Buyer, the Final Settlement Statement and the final Adjusted Purchase Price, shall be final and binding on the Parties. If the final Adjusted Purchase Price is (a) more than the Adjusted Purchase Price used at Closing pursuant to Section 3.4(a), Seller shall be entitled to receive from Buyer the amount of such difference, or (b) less than the Adjusted Purchase Price used at Closing pursuant to Section 3.4(a), Buyer shall be entitled to receive from Seller the amount of such difference. To that end, within two Business Days after the final resolution by the Parties of the final Adjusted Purchase Price, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to each Party the funds in the Escrow Account to which such Party is entitled in accordance with the terms hereof; provided that, if Seller is owed amounts in excess of the amounts in the Escrow Account, then Buyer shall promptly (and in any event within five Business Days following the final resolution by the Parties of the final Adjusted Purchase Price) pay to Seller via wire transfer to the account designated by Seller, the amount of any such difference. Notwithstanding anything to the contrary herein, in no event shall Seller be liable to Buyer for any amounts pursuant to this Section 3.4(b) for amounts other than amounts in the Escrow Account. The Parties shall use commercially reasonable efforts to resolve any disputes related to the final Adjusted Purchase Price; provided that, if the Parties are unable to resolve any such disputes (to the extent set forth in a timely delivered Dispute Notice) within 120 days after the Closing Date (the “Final Settlement Date”), then the final Adjusted Purchase Price shall be determined in accordance with Section 3.5.

3.5Disputes. If Seller and Buyer are unable to resolve the matters addressed in a Dispute Notice (if any) by the Final Settlement Date, each of Buyer and Seller shall within 14 Business Days thereafter, summarize its position with regard to such dispute in a written document of ten pages or less and submit such summaries to the Houston, Texas office of Deloitte Touche Tohmatsu Limited (“Deloitte”) (or if Deloitte is unable or unwilling to serve as arbitrator within 20 days after receipt of a written request from the Parties to serve and absent agreement by the Parties as to a replacement for such arbitrator within ten Business Days after notification that Deloitte is unable or unwilling to serve, the arbitrator shall be selected by the Houston, Texas office of the AAA) (the “Accounting Arbitrator”), together with the Dispute Notice and any other documentation such Party may desire to submit. The Accounting Arbitrator shall also be furnished with a copy of this Agreement. The Parties shall instruct the Accounting Arbitrator that, within 20 Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision choosing either Seller’s position or Buyer’s position with respect to each matter addressed in any Dispute Notice,whichever complies more closely to the terms of the Agreement and the materials described above. The costs of such Accounting Arbitrator shall be borne one-half by Seller and one-half by Buyer. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Seller and Buyer and will be enforceable against each of the Parties in any court of competent jurisdiction. The final Adjusted Purchase Price determined by the Accounting Arbitrator pursuant to this Section 3.5 shall be final and binding on the Parties, without right of appeal and enforceable by either party in any court of competent jurisdiction. The Accounting Arbitrator shall be authorized to resolve only the specific disputed aspects of the Final Settlement Statement submitted by the Parties as provided above and may not award damages, interest or penalties to any Party with respect to any matter, notwithstanding any AAA Rules to the contrary.Within two Business Days after the final resolution by the Accounting Arbitrator of the matters addressed in the Dispute Notice, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to each Party the funds in the Escrow Account to which such Party is entitled in accordance with the terms of such final resolution; provided that, if Seller is owed amounts in excess of the amounts in the Escrow Account, then Buyer shall promptly (and in any event within five Business Days following the final resolution by the Parties of the final Adjusted Purchase Price) pay to Seller via wire transfer to the account designated by Buyer, the amount of any such difference; provided that, notwithstanding anything to the contrary herein, in no event shall Seller be liable to Buyer for any amounts pursuant to this Section 3.5 for amounts other than amounts in the Escrow Account.

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3.6Allocated Values. Subject to adjustment as set forth herein, the “Allocated Value” for each Title Well included in the Assets shall equal the amount set forth for such Title Well on Schedule 3.6, and such Allocated Values shall be used in calculating adjustments to the Purchase Price as provided herein.

3.7Allocation for Imbalances.Notwithstanding anything to the contrary in this Agreement, if, prior to Closing, either Party discovers an error in the Imbalances set forth in Schedule 7.15, then the Purchase Price shall be further adjusted at Closing pursuant to Section 3.3(a)(iv), Section 3.3(a)(v),Section 3.3(b)(vi)or Section 3.3(b)(vii), as applicable (but there shall be no deemed adjustment to Schedule 7.15 for purposes of determining whether the condition to Closing in Section 10.1 has been satisfied).

3.8Withholding. Buyer shall be entitled to deduct and withhold from any consideration otherwise payable or deliverable to Seller pursuant to this Agreement such amounts as may be required to be deducted or withheld therefrom under any Law. The Parties shall cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such deduction or withholding. To the extent such amounts are so deducted or withheld, and remitted to the applicable Governmental Authority in accordance with applicable Law, such amounts shall be treated for all purposes as having been paid to the Person to whom such amounts would otherwise have been paid absent such deduction or withholding.

ARTICLE IVACCESS / DISCLAIMERS

4.1Access.

(a)From and after the Original Execution Date and up to and including the Closing Date (or earlier termination of this Agreement) but subject to (i) the other provisions of this Section 4.1, and (ii) obtaining any consents or waivers from Third Parties that are required pursuant to the terms of the Leases, easements and Applicable Contracts (including any restrictions therein related to access during hunting seasons), including Third Party operators of the Assets (with respect to which such consents or waivers Seller shall use commercially reasonable efforts to obtain without any obligation to incur any out-of-pocket cost or expense or provide any other consideration), Seller shall afford to Buyer and its Affiliates and their respective officers, employees, agents, accountants, attorneys, investment bankers, consultants and other authorized representatives (the “Buyer Representatives”), upon prior reasonable notice, reasonable access, during normal business hours, to the Assets, reasonably appropriate Seller personnel and all Records and other documents in Seller’s or its Affiliates’ possession, in each case, to the extent relating to the Assets. Without limiting the forgoing, immediately upon the execution of this Agreement, Seller shall provide, in electronic format, Buyer with all title opinions, abstracts of title, elections, division order files, Third Party brokerage information, title runsheets, reports, records, well files and other similar data and information in Seller’s files as may be reasonably necessary in connection with Buyer’s and the Buyer Representatives’ title due diligence activities with respect to the Assets.

(b)From and after the Original Execution Date to the Closing Date (or earlier termination of this Agreement), subject to (i) the other provisions of this Section 4.1, and (ii) obtaining any consents or waivers from Third Parties that are required pursuant to the terms of the Leases, easements and Applicable Contracts (including any restrictions therein related to access during hunting seasons), including Third Party operators of the Assets (with respect to which such consents or waivers Seller shall use commercially reasonable efforts to obtain without any obligation to incur any out-of-pocket cost or expense or provide any other consideration), Buyer and the Buyer Representatives shall have inspection rights with respect to the Environmental Condition of the Assets but such inspection rights shall be limited to conducting a Phase I Environmental Site Assessment (as defined in the applicable ASTM International Standards) and limited environmental compliance review of the Assets and Buyer and the Buyer Representatives shall not conduct any Phase II Environmental Site Assessment (as defined in the applicable ASTM International Standards) or operate any equipment or conduct any testing, boring, sampling, drilling or other invasive investigation activities (in each case) on or with respect to any of the Assets without the prior written consent of Seller, which consent may be withheld in Seller’s sole discretion. Notwithstanding anything herein to the contrary, neither Buyer nor any of the Buyer Representatives shall have access to, and shall not be permitted to conduct, any on-site environmental due diligence (including any Phase I Environmental Site Assessment, as defined in the applicable ASTM International Standards) with respect to any Assets where Seller does not have the authority to grant access for such due diligence; provided that Seller shall use commercially reasonable efforts to obtain such access without any obligation to incur any out-of-pocket cost or expense or provide any other consideration. In the event a Phase II Environmental Site Assessment is reasonably necessary to determine (A) whether an Environmental Condition exists or (B) the Remediation Amount associated with an asserted Environmental Condition, in either case, on a Property operated by Seller, Buyer may request the right to conduct a Phase II Environmental Site Assessment on the affected Property. If Seller denies such a request, Buyer shall have the right to cause Seller to retain the entirety of the affected Property, and reduce the Purchase Price by an amount equal to the Allocated Value of such Property.

(c)All investigations and due diligence conducted by Buyer or any Buyer Representative pursuant to Section 4.1(a) or (b), above, shall be conducted at Buyer’s sole cost, risk and expense, and any conclusions made from any examination done by Buyer or any Buyer Representative shall result from Buyer’s or Buyer Representatives’ own independent review and judgment. Buyer shall coordinate its access rights and physical inspections of the Assets with Seller so as not to unreasonably interfere with the conduct of business by Seller or its Affiliates, and Seller shall have the right to accompany Buyer and any Buyer Representative in connection with any physical inspection of the Assets at Seller’s sole cost and expense. Buyer shall, and shall cause all Buyer Representatives to, abide by all Laws and all of Seller’s and any Third Party operator’s safety rules, regulations, and operating policies while conducting Buyer’s due diligence evaluation of the Assets (provided that Buyer is provided an advance copy or otherwise informed of any such rules, regulations and policies), including any environmental or other inspection or assessment of the Assets, and to the extent required by any Third Party operator, execute and deliver any access agreement required by such Third Party operator.

(d)Buyer hereby releases, indemnifies, defends and holds harmless each Seller Indemnified Party from and against any and all Liabilities (including any personal injury, death or loss or damage of property), in each case, to the extent arising out of, resulting from or relating to any office visit, field visit or environmental property assessment conducted by Buyer or any Buyer Representative with respect to the Assets, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES, EXCEPTING ONLY LIABILITIES TO THE EXTENT ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY SELLER INDEMNIFIED PARTY, OR THE MERE DISCOVERY OF A PRE-EXISTING CONDITION BY BUYER OR BUYER’S REPRESENTATIVE SO LONG AS SUCH DISCOVERY DOES NOT IN AND OF ITSELF EXACERBATE OR ADVERSELY CONTRIBUTE TO ANY SUCH PRE-EXISTING CONDITION.

(e)Buyer agrees to promptly provide Seller, but in any event no later than three Business Days after receipt or creation of such reports or test results, copies of all final environmental reports and test results prepared by Buyer or any Buyer Representative, to the extent related to any Environmental Defect that Buyer reasonably expects to assert and which contain data collected or generated from Buyer’s (or the Buyer Representatives’) environmental due diligence with respect to the Assets, including any data generated in association with any Phase I Environmental Site Assessment conducted in accordance with Section 4.1(b). Seller shall not be deemed by its receipt of said documents or otherwise to have made any representation or warranty, express, implied or statutory, as to the condition of the Assets or to the accuracy of said documents or the information contained therein.

(f)Upon completion of Buyer’s due diligence, Buyer shall remove all equipment, tools or other property brought onto the Assets in connection with Buyer’s (or any Buyer Representative’s) due diligence investigation and to the extent there exists after such due diligence investigation any damage upon the Assets, Seller shall (i) repair all damage done to the Assets (including the real property and other assets associated therewith) in connection with Buyer’s (or any Buyer Representative’s) due diligence investigation, and (ii) restore the Assets (including the real property and other assets associated therewith) to the approximate same condition that they were prior to commencement of Buyer’s (or any Buyer Representative’s) due diligence investigation at Buyer’s sole cost and expense and without any Third Party cost or expense to Seller or its Affiliates. Seller shall provide an invoice to Buyer following any such work and Buyer shall remit payment to Seller for all reasonable and documented out-of-pocket costs and expenses paid or incurred by Seller in respect of such repair or restoration within 10 days after receipt of such invoice.

(g)During all periods that Buyer or any of the Buyer Representatives are on the Assets or any lands underlying such Assets, Buyer shall maintain, at its sole expense, policies of insurance of types and in amounts customary for such review of Buyer under Section 4.1(a) and Section 4.1(b). Upon request by Seller, Buyer shall provide evidence of such insurance to Seller prior to entering the Assets or any lands underlying such Assets.

4.2Confidentiality. Buyer acknowledges that, pursuant to its right of access to the Records and the Assets, Buyer will become privy to confidential and other information of Seller and its Affiliates and the Assets and that such confidential information shall be held confidential by Buyer and Buyer Representatives in accordance with the terms of the Confidentiality Agreement. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including the Confidentiality Agreement, shall terminate (except as to the Excluded Assets); provided that such termination of the Confidentiality Agreement shall not relieve any party thereto from any liability thereunder for the breach of such agreement prior to the Original Execution Date.

4.3Disclaimers.

(a)EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII, THE CERTIFICATE DELIVERED BY SELLER AT CLOSING OR WITH RESPECT TO THE LIMITED SPECIAL WARRANTY OF DEFENSIBLE TITLE SET FORTH IN THE INSTRUMENTS OF CONVEYANCE, (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO BUYER OR ANY BUYER REPRESENTATIVE (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER BY A MEMBER OF THE SELLER INDEMNIFIED PARTIES), AND BUYER ACKNOWLEDGES THAT IT HAS NOT RELIED ON ANY SUCH REPRESENTATION OR WARRANTY.

(b)EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII, THE CERTIFICATE DELIVERED BY SELLER AT CLOSING OR WITH RESPECT TO THE LIMITED SPECIAL WARRANTY OF DEFENSIBLE TITLE SET FORTH IN THE INSTRUMENTS OF CONVEYANCE, SELLER EXPRESSLY DISCLAIMS, AND BUYER ACKNOWLEDGES THAT IT HAS NOT RELIED UPON, ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED BY ANY MEMBER OF SELLER INDEMNIFIED PARTIES, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY OR ON BEHALF OF SELLER OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ANY BUYER REPRESENTATIVE IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII, THE CERTIFICATE DELIVERED BY SELLER AT CLOSING OR WITH RESPECT TO THE LIMITED SPECIAL WARRANTY OF DEFENSIBLE TITLE SET FORTH IN THE INSTRUMENTS OF CONVEYANCE, SELLER FURTHER DISCLAIMS, AND BUYER ACKNOWLEDGES THAT IT HAS NOT RELIED UPON, ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE OR CONSIDERATION, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT, BUYER SHALL BE DEEMED TO BE ACQUIRING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(c)EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII AND THE CERTIFICATE DELIVERED BY SELLER AT CLOSING, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF HAZARDOUS MATERIALS OR OTHER MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND BUYER ACKNOWLEDGES THAT IT HAS NOT RELIED UPON ANY SUCH REPRESENTATION OR WARRANTY, AND BUYER SHALL BE DEEMED TO BE ACQUIRING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(d)Seller and Buyer agree that, to the extent required by applicable Law to be effective, the disclaimers of certain representations and warranties contained in this Section 4.3 are conspicuous disclaimers for the purpose of any applicable Law.

ARTICLE VTITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS

5.1General Disclaimer of Title Warranties and Representations/Exclusive Remedy. Except for the limited special warranty of Defensible Title contained in the Instruments of Conveyance and without limiting Buyer’s remedies for Title Defects set forth in this Article V (or Buyer’s remedies for Seller’s failure to obtain Consents or waivers of Preferential Purchase Rights as set forth in Section 5.4) or Buyer’s conditions to Closing set forth in Article X (including as set forth in Section 10.4), Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets. Buyer hereby acknowledges and agrees that (subject to and without limiting Buyer’s conditions to Closing set forth in Article X, including as set forth in Section 10.4) Buyer’s sole and exclusive remedy for (a) any failure by Seller to obtain Consents or waivers of Preferential Purchase Rights as contemplated by Section 5.4 shall be as set forth in Section 5.4, and(b)any defect in title or any other title matter (including any Title Defect with respect to any of the Assets or otherwise) (i) before the Defect Claim Date shall be as set forth in Section 5.2, but subject to the provisions of Section 5.2, including Section 5.2(h) and (ii) after the Defect Claim Date shall be pursuant to the limited special warranty of Defensible Title contained in the Instruments of Conveyance.

5.2Notice of Title Defects; Title Defect Adjustments.

(a)Title Defect Notices. On or before the Defect Claim Date, Buyer may deliver claim notices to Seller meeting the requirements of this Section 5.2(a) (collectively, the “Title Defect Notices,” and each individually, a “Title Defect Notice”) setting forth any matters that, in Buyer’s reasonable opinion, constitute Title Defects and that Buyer intends to assert as a Title Defect pursuant to this Article V. For all purposes of this Agreement and notwithstanding anything herein to the contrary (but without limiting the special warranty of Defensible Title contained in the Instruments of Conveyance), Buyer shall be deemed to have waived, and Seller shall have no liability for, any Title Defect or other title matter that Buyer fails to assert as a Title Defect by a Title Defect Notice received by Seller on or before the Defect Claim Date. To be effective, each Title Defect Notice shall be in writing and shall include: (i) a description of the alleged Title Defect, (ii) identification of the Subject Property affected by the Title Defect (such Subject Property, each, as applicable, a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) supporting documents available to Buyer reasonably necessary for Seller to identify the existence of the alleged Title Defect, and (v) the amount by which Buyer reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect and the computations (with reasonable supporting detail) upon which Buyer’s belief is based. To give Seller an opportunity to commence reviewing and curing Title Defects, Buyer agrees to use its reasonable efforts to give Seller weekly written notice of all Title Defects discovered by Buyer (together with any Title Benefits discovered by Buyer) during the preceding period after the Original Execution Date and prior to delivery of such notice, which notice may be preliminary in nature and may be supplemented on or prior to the Defect Claim Date; provided that failure of Buyer to deliver a preliminary notice of any such Title Defect shall not be deemed to waive or otherwise prejudice Buyer’s right to assert any Title Defect on or before the Defect Claim Date. Buyer shall also promptly furnish Seller with written notice of any Title Benefit that is discovered by any Buyer Representative prior to the Defect Claim Date.

(b)Title Benefit Notices. In addition to Title Benefits reported by Buyer pursuant to Section 5.2(a), Seller shall have the right, but not the obligation, to deliver to Buyer on or before the Defect Claim Date a notice meeting the requirements of this Section 5.2(b) (collectively, the “Title Benefit Notices”, and each individually, a “Title Benefit Notice”) setting forth any additional matters that, in Seller’s reasonable opinion, constitute Title Benefits and that Seller intends to assert as a Title Benefit pursuant to this Article V. To be effective, each Title Benefit Notice shall be in writing and shall include: (i) a description of the alleged Title Benefit, (ii) the Subject Property affected by the Title Benefit (each, as applicable, a “Title Benefit Property”), (iii) the Allocated Value of the Title Benefit Property, (iv) supporting documents available to Seller reasonably necessary for Buyer to identify the existence of the alleged Title Benefit, and (v) the amount by which Seller reasonably believes the Allocated Value of each Title Benefit Property should be increased by the alleged Title Benefit and the computations (with reasonable supporting detail) upon which Seller’s belief is based. Except for Title Benefits that Buyer is required to report to Seller pursuant to Section 5.2(a), Seller shall be deemed to have waived, and Buyer shall not have any liability for, any Title Benefit that Seller fails to assert as a Title Benefit by a Title Benefit Notice received by Buyer on or before the Defect Claim Date.

(c)Seller’s Right to Cure. Notwithstanding anything to the contrary herein, Seller shall have the right, but not the obligation, by giving written notice of such election to Buyer on or before the Closing Date, to attempt, at its sole cost, to cure, at any time prior to the expiration of 90 daysfollowing the Closing (the “Cure Period”), any Title Defects of which it has timely received a Title Defect Notice from Buyer. In the event Seller elects prior to Closing to cure an asserted Title Defect that is not cured at Closing, Seller shall so notify Buyer, and at Closing, (i) the applicable Title Defect Property shall be included in the Assets conveyed to Buyer at Closing, (ii) the unadjusted Purchase Price shall be reduced by an amount equal to the Title Defect Amount for such asserted Title Defect, and (iii) Buyer shall deposit the Title Defect Amount of the asserted Title Defect into the Escrow Account. Notwithstanding the foregoing, in the event that (A) the rejection of a Contract would cure any Title Defect and (B) Buyer, in its sole discretion, elects to reject such Contract pursuant to this Agreement, then such Title Defect shall be deemed to have been cured for all purposes hereunder. In the event that the asserted Title Defect is completely cured during the Cure Period, within two Business Days after the day upon which such asserted Title Defect is cured, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to Seller an amount equal to the Title Defect Amount for the applicable Title Defect from the Escrow Account. In the event that the asserted Title Defect is not completely cured during the Cure Period, on the later to occur of (i) the day that is two Business Days after the expiration of the Cure Period, and (ii) the day that is two Business Days after the final resolution of any Title Dispute regarding such asserted Title Defect, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to each Party the funds in the Escrow Account to which such Party is entitled in respect of the applicable Title Defect. The foregoing provisions of this Section 5.2(c) shall be subject to the provisions of Section 5.2(i) with respect to any valid Title Dispute (including with respect to the Title Defect Amount or the extent of curative with respect to the applicable Title Defect).

(d)Remedies for Title Defects. Subject to (v) Seller’s continuing right to dispute the existence of a Title Defect and the Title Defect Amount asserted with respect thereto, (w) the rights of Seller pursuant to Section 14.1(c), (x) the Individual Title Defect Threshold, (y) the Aggregate Deductible and (z) Seller’s ongoing right to cure any Title Defect under Section 5.2(c), if any Title Defect timely asserted by Buyer in accordance with Section 5.2(a) is not waived in writing by Buyer or cured by Closing, then in connection with the Closing (unless, as of the Closing, the Parties are in disagreement with respect to the existence of such Title Defect or any associated Title Defect Amount, in each of which case the applicable Title Dispute shall, unless otherwise agreed by the Parties, be addressed pursuant to Section 5.2(i)), Seller shall, at its sole option and discretion, elect one or more of the following remedies for such Title Defect:

(i)Seller will convey the entirety of the Title Defect Property that is subject to such Title Defect to Buyer, together with all associated Assets, at Closing, and make an accompanying reduction to the Purchase Price in an amount determined pursuant to Section 5.2(f) or Section 5.2(i) as being the value of such Title Defect to the extent affecting the applicable Title Defect Property (the “Title Defect Amount”); or

(ii)if and only if the aggregate Title Defect Amount for a Title Defect Property equals or exceeds the Allocated Value thereof, Seller may retain the entirety of the Title Defect Property that is subject to such Title Defect, together with all associated Assets (in which case, such Assets shall become Excluded Assets hereunder), and reduce the Purchase Price by an amount equal to the Allocated Value of such Title Defect Property.

(e)Remedies for Title Benefits. Subject to Buyer’s right to dispute any Title Benefit or associated Title Benefit Amount, if any Title Benefits for which the Title Benefit Amount exceeds the Individual Title Defect Threshold are identified by Buyer pursuant to Section 5.2(a) or are timely asserted by Seller in accordance with Section 5.2(b) then, as Seller’s sole and exclusive remedy for any such Title Benefits, the aggregate amount of all such Title Benefit Amounts (solely to the extent such Title Benefit Amounts exceed the Individual Title Defect Threshold) shall be applied as to offset the aggregate Title Defect Amounts. For the avoidance of doubt, Title Benefit Amounts shall in no event increase the Purchase Price and shall, instead, solely offset Title Defect Amounts.

(f)Title Defect Amount. The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of the affected Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following terms and conditions:

(i)if Seller and Buyer agree on the Title Defect Amount, then that amount shall be the Title Defect Amount;

(ii)if the Title Defect is an obligation, Encumbrance or burden that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to permanently and fully discharge the Title Defect from the Title Defect Property;

(iii)if the Title Defect Property is a Title Well and the Title Defect represents a decrease in the Net Revenue Interest for such Title Defect Property such that the actual Net Revenue Interest for such Title Defect Property is less than the Net Revenue Interest set forth in Exhibit A-1 for such Title Defect Property, and the Working Interest for such Title Well is reduced proportionately, then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property, multiplied by a fraction, the numerator of which is the amount of such Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest set forth for such Title Defect Property in Exhibit A-1; provided that, if the Title Defect does not affect the Title Defect Property throughout the entire life of such Title Defect Property, then the Title Defect Amount determined under this Section 5.2(f)(iii) shall be reduced to take into account the applicable time period only;

(iv)if the Title Defect represents an obligation or Encumbrance upon or other defect in title affecting the Title Defect Property of a type not described above, the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property and such other reasonable factors as are necessary to make a proper evaluation;

(v)the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder; and

(vi)notwithstanding anything to the contrary in this Article V, except with respect to any Title Defect for which the Title Defect Amount is determined pursuant to Section 5.2(f)(ii), the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property (whether related to an adjustment to the Purchase Price or any other remedy provided by Seller hereunder) shall not exceed the Allocated Value of such Title Defect Property.

(g)Title Benefit Amount. The Title Benefit Amount resulting from a Title Benefit shall be determined in accordance with the following methodology, terms and conditions:

(i)if Buyer and Seller agree on the Title Benefit Amount, then that amount shall be the Title Benefit Amount;

(ii)if the Title Benefit Property is a Title Well and the Title Benefit represents an increase in the Net Revenue Interest for such Title Benefit Property such that the actual Net Revenue Interest for such Title Benefit Property is greater than the Net Revenue Interest stated in Exhibit A-1 for such Title Benefit Property,and the Working Interest is increased proportionately,then the Title Benefit Amount shall be the product of the Allocated Value of such Title Benefit Property, multiplied by a fraction, the numerator of which is the value of such Net Revenue Interest increase and the denominator of which is the Net Revenue Interest set forth for such Title Benefit Property in Exhibit A-1, provided that, if the increased Net Revenue Interest does not affect the Title Benefit Property throughout the entire life of such Title Benefit Property, then the Title Benefit Amount determined under this Section 5.2(g)(ii) shall be reduced to take into account the applicable time period only; and

(iii)if the Title Benefit is of a type not described above, then the Title Benefit Amounts shall be determined by taking into account the Allocated Value of the Title Benefit Property, the portion of such Title Benefit Property affected by such Title Benefit, the legal effect of the Title Benefit, the potential economic effect of the Title Benefit over the life of such Title Benefit Property and such other reasonable factors as are necessary to make a proper evaluation.

(h)Title Threshold and Deductible. Notwithstanding anything herein to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or any other remedy provided by Seller hereunder for any individual Title Defect for which the Title Defect Amount applicable thereto does not exceed $50,000(the “Individual Title Defect Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price for any Title Defect for which the Title Defect Amount applicable thereto exceeds the Individual Title Defect Threshold unless and until (A) the sum of (1) the Title Defect Amounts of all such Title Defects that exceed the Individual Title Defect Threshold, in the aggregate (excluding any Title Defect Amounts attributable to (v) Title Defects cured by Seller, and (w) Title Defect Properties retained by Seller pursuant to Section 5.2(d)(ii)), net of any offsetting Title Benefit Amounts in accordance with Section 5.2(e), plus (2) the Remediation Amounts of all Environmental Defects that exceed the Individual Environmental Defect Threshold, in the aggregate (excluding any Remediation Amounts attributable to (x) Environmental Defects cured or Remediated by Seller, and (y) Environmental Defect Properties that are retained by Seller pursuant to Section 6.1(c)(ii)), exceeds (B) the Aggregate Deductible, in which case Buyer shall be entitled to remedies for such Title Defects to the extent, but only to the extent, that the Title Defect Amounts with respect thereto are in excess of such Aggregate Deductible.

(i)Title Dispute Resolution. Seller and Buyer shall attempt in good faith to agree on all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts (any dispute with respect to the foregoing matters, including the existence, extent of or any cure of any Title Defect, collectively “Title Disputes”) prior to the Closing, or, if the applicable Title Dispute relates to any Title Defect Property for which Seller has attempted to cure the alleged Title Defect(s) following Closing and prior to the expiration of the Cure Period, then prior to the date that is ten Business Days following the expiration of the Cure Period. If Seller and Buyer are unable to agree within the above applicable time period, the Title Disputes arbitrated shall be exclusively and finally resolved pursuant to this Section 5.2(i). Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section 5.2(i) with respect to any Title Defect properly asserted by Buyer or any Title Benefit properly asserted by Seller prior to the Defect Claim Date, and to the extent any adjustments are not agreed upon by the Parties as of the Closing, unless Seller has elected to retain the applicable Title Defect Property pursuant to Section 5.2(d)(ii), the affected Title Defect Property shall be assigned to Buyer at Closing and the Purchase Price shall be reduced by an amount equal to the Title Defect Amount applicable for such Title Defect, which amount (including any disputed amounts) shall be paid into the Escrow Account at Closing and remain therein until such dispute is resolved pursuant to this Section 5.2(i). Any Title Disputes shall be submitted to an arbitrator with at least ten years’ experience in oil and gas titles including properties in the regional area in which the Subject Properties are located (the “Title Arbitrator”). If the Parties are unable to agree on the selection of the Title Arbitrator within tenBusiness Days of the Parties agreeing to submit a Title Dispute to the Title Arbitrator for determination or, in the case where the Parties have not so agreed, within tenBusiness Days of the non-submitting Party receiving written notice from the submitting Party stating that such Party has elected to submit a Title Dispute to arbitration in accordance with this Section 5.2(i), the AAA shall make the necessary appointment (which Title Arbitrator shall not have worked as an employee, outside counsel or as a consultant for any Party or its Affiliates during the five year period preceding the arbitration or have any financial interest in the dispute). The place of arbitration shall be Houston, Texas, and the arbitration shall be conducted in accordance with the AAA Rules, to the extent such rules do not conflict with the terms of this Section 5.2. The Parties, within ten days after the Title Arbitrator is appointed, shall submit written summaries of their positions regarding each Title Dispute. The Parties shall instruct the Title Arbitrator to make a determination, choosing either Seller’s position or Buyer’s position with respect to each Title Dispute, whichever the Title Arbitrator determines complies more closely to the terms of this Agreement, within 20 Business Days after the submission of the Parties’ summaries of the Title Disputes to the Title Arbitrator, and such determination shall be final and binding upon both Parties, without right of appeal. The costs of the Title Arbitrator shall be borne one-half by Seller and one-half by Buyer. In making its determination, the Title Arbitrator shall be bound by the terms of this Article V and, subject to the foregoing, may consider such other matters as in the opinion of the Title Arbitrators are necessary to make a proper determination. The Title Arbitrator shall act for the limited purpose of determining the specific Title Disputes submitted by either Party and may not award damages, interest or penalties to either Party with respect to any Title Dispute. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case to the Title Arbitrator. Within two Business Days after the Title Arbitrator delivers written notice to Buyer and Seller of its award with respect to a Title Dispute, and subject to Section 5.2(h), the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to each Party the funds in the Escrow Account to which such Party is entitled in respect of the applicable Title Dispute.

5.3Casualty or Condemnation Loss.

(a)Notwithstanding anything herein to the contrary, from and after the Effective Time if Closing occurs, with respect to the Assets, Buyer shall assume all risk of loss, including with respect to (i) production of Hydrocarbons through normal depletion (including watering out of any Well, collapsed casing or sand infiltration of any Well) and (ii) the depreciation of any Asset due to ordinary wear and tear, and, in each case, Buyer shall not assert such matters as any Casualty or Condemnation Loss or Title Defect hereunder.

(b)If, after the Original Execution Date but prior to the Closing Date, any portion of the Assets is damaged or destroyed or otherwise impaired by fire, explosion, tornado, hurricane, earthquake, earth movement, flood, water damage or other similar casualty or is taken in condemnation or under right of eminent domain (in each case, a “Casualty or Condemnation Loss”) then Buyer shall nevertheless be required to close the transactions contemplated by the Agreement without any change to the Purchase Price and Seller shall pay to Buyer all sums paid to Seller by Third Parties by reason of such Casualty or Condemnation Loss insofar as with respect to the Assets and shall assign, transfer and set over to Buyer or subrogate Buyer to all of Seller’s and its Affiliates’ right, title and interest (if any) in insurance claims, unpaid awards and other rights against Third Parties (excluding any Liabilities, other than insurance claims, of or against any Seller Indemnified Parties) arising out of such Casualty or Condemnation Loss insofar as with respect to the Assets; provided, however, that Seller shall reserve and retain (and Buyer shall assign to Seller) all rights, title, interests and claims against Third Parties for the recovery of Seller’s costs and expenses incurred prior to the Closing in pursuing or asserting any such insurance claims or other rights against Third Parties with respect to any such Casualty or Condemnation Loss. Except as expressly set forth hereinabove, Seller shall retain all rights to insurance, condemnation awards and other claims against Third Parties with respect to the casualty or taking except to the extent the Parties otherwise agree in writing.

5.4Preferential Purchase Rights and Consents to Assign.

(a)With respect to each Preferential Purchase Right set forth on Schedule 7.9, within five Business Daysafter the Execution Date, Seller shall send to the holder of each such Preferential Purchase Right a notice in compliance with the contractual provisions applicable to such Preferential Purchase Right requesting a waiver of such right. With respect to each Preferential Purchase Right that is not set forth on Schedule 7.9 but is discovered by Seller prior to Closing, Seller shall send to the holder of each such Preferential Purchase Right a notice in compliance with the contractual provisions applicable to such Preferential Purchase Right requesting a waiver of such right as soon as reasonably practicable (but in no event later than two Business Days after discovery of any such Preferential Purchase Right). Any Preferential Purchase Right must be exercised subject to all terms and conditions set forth in this Agreement, and the consideration payable under this Agreement for the purposes of all Preferential Purchase Right notices shall be the Allocated Value of the applicable Asset (as adjusted herein).

(i)If, prior to Closing, any holder of a Preferential Purchase Right notifies Seller that it intends to consummate the acquisition of the Assets to which its Preferential Purchase Right applies or if the time for exercising such Preferential Purchase Right has not expired (and the holder of such right has not waived such right), then the Assets subject to such Preferential Purchase Right shall be excluded from the Assets to be assigned to Buyer at Closing (and shall be considered Excluded Assets hereunder, but only to the extent of the portions of such Assets affected by the Preferential Purchase Right), and the Purchase Price shall be reduced by the Allocated Value of such Assets (or portions thereof) so excluded. Seller shall be entitled to all consideration given by any Person exercising a Preferential Purchase Right prior to Closing. If such holder of such Preferential Purchase Right thereafter fails to consummate the acquisition of the Assets (or portions thereof) covered by such Preferential Purchase Right on or before 120 daysfollowing the Closing Date or the time for exercising such Preferential Purchase Right expires without exercise by the holder thereof, (A) Seller shall so notify Buyer and (B) Seller shall assign, on the tenth Business Day following termination of such right without consummation or exercise, such Assets (or portions thereof) that were so excluded to Buyer pursuant to an instrument in substantially the same form as the Assignment or Deed, as applicable (and such Assets (or portions thereof) shall no longer be considered Excluded Assets), and Buyer, contemporaneously with said assignment, shall pay by wire transfer in same day funds to Seller, to an account designated by Seller, the amount by which the Purchase Price was reduced at Closing with respect to such excluded Assets (or portions thereof), subject to any adjustment in the allocable portion of the Purchase Price affecting such Asset (or portions thereof) pursuant to Section 3.3.

(ii)All Assets for which any applicable Preferential Purchase Right has been waived, or as to which the period to exercise the applicable Preferential Purchase Right has expired (and such Preferential Purchase Right has not been exercised), in each case, prior to Closing, shall be sold to Buyer at Closing pursuant to the provisions of this Agreement and Buyer shall be deemed to have assumed any and all Liabilities with respect to such Preferential Purchase Right as part of the Assumed Obligations hereunder and Buyer shall have no claim against, and hereby releases and indemnifies the Seller Indemnified Parties from any Liability with respect to such Preferential Purchase Right.

(b)Within five Business Days after the Original Execution Date, Seller shall send to the holder of each Applicable Schedule 7.4 Consent a notice incompliance with the contractual provisions applicable to such Applicable Schedule 7.4 Consent seeking such holder’s consent to the transactions contemplated hereby. With respect to each Consent (A) relating to an Applicable Contract for which the counterparty’s consent to assignment would be required for such Applicable Contract to be assumed and assigned to Buyer, after giving effect to sections 365(c)(1) and 365(f)(1) of the Bankruptcy Code or (B) that burdens a Lease, but which Consent is not set forth on Schedule 7.4 and is discovered by Seller (including, if applicable, any such Consent that is identified by Buyer) prior to Closing, all such Consents shall thereafter be Applicable Schedule 7.4 Consents hereunder and Seller shall send to the holder of each such Consent a notice incompliance with the contractual provisions applicable to such Consent seeking such holder’s consent to the transactions contemplated hereby as soon as reasonably practicable (but in no event later than two Business Days after discovery of any such Consent).

(i)If Seller fails to obtain a Applicable Schedule 7.4 Consent prior to Closing and (1) the failure to obtain such Applicable Schedule 7.4 Consent would cause the assignment of the Assets affected thereby to Buyer to be void or voidable, (2) the failure to obtain such Applicable Schedule 7.4 Consent could reasonably result in the termination of a Lease or Assigned Contract under the express terms thereof or (3) a Party holding such Applicable Schedule 7.4 Consent right has objected to the assignment of the affected Asset in accordance with the terms of the relevant Applicable Schedule 7.4 Consent right and the assignment of the affected Asset would not be permitted under the Bankruptcy Code (each Applicable Schedule 7.4 Consent meeting the requirements of either clause (1), clause (2) or clause (3) above, a “Required Consent”), then, unless the Bankruptcy Court has entered an order approving (or in the case of clause (3), such objection is resolved to permit) the sale and assignment of the affected Asset to Buyer pursuant to this Agreement without obtaining such Required Consent, the Assets (or portions thereof) affected by such un-obtained Required Consent shall be excluded from the Assets to be assigned to Buyer at Closing (and shall be considered Excluded Assets hereunder) and the Purchase Price shall be reduced by the Allocated Value(s) of such Assets (or portions thereof) so excluded. In the event that any such Required Consent with respect to any such excluded Asset (or portion thereof) is obtained within 120 days after the Closing (or if during such 120-day period the Bankruptcy Court enters an order providing that such Required Consent is not required to consummate the sale of the affected Assets to Buyer), then, (A) Seller shall so notify Buyer and (B) on the tenth Business Day after the date such Consent is obtained Seller shall assign the Assets (or portions thereof) that were so excluded as a result of such previously un-obtained Consent to Buyer pursuant to an instrument in substantially the same form as the Assignment or Deed, as applicable (and such Assets (or portions thereof) shall no longer be considered Excluded Assets hereunder) and, contemporaneously with said assignment, Buyer shall pay by wire transfer in same day funds to Seller, to an account designated by Seller, the amount by which the Purchase Price was reduced at Closing with respect to such excluded Assets (or portions thereof), subject to any adjustment in the allocable portion of the Purchase Price affecting such Asset (or portions thereof) pursuant to Section 3.3.

(ii)If Seller fails to obtain a Consent prior to Closing and such Consent is not a Required Consent (or if prior to Closing the Bankruptcy Court enters an order providing that a Required Consent is not required to consummate the sale of the affected Assets to Buyer), then the Assets (or portions thereof) subject to such un-obtained Consent shall nevertheless be assigned by Seller to Buyer at Closing as part of the Assets and Buyer shall be deemed to have assumed any and all Liabilities for the failure to obtain any such Consent as part of the Assumed Obligations hereunder and Buyer shall have no claim against the Seller Indemnified Parties from any Liability for, the failure to obtain such Consent.

(iii)Prior to Closing and during the 120-day period after Closing with respect to any unobtained Required Consents with respect to which the Bankruptcy Court shall not have entered an order approving the sale and assignment of the affected Assets to Buyer pursuant to this Agreement without obtaining such Required Consent, Seller shall use its commercially reasonable efforts to obtain all Consents; provided, however, that Seller shall not be required to incur any Liability, pay any money or provide any other consideration in order to obtain any such Consent. Buyer shall use its commercially reasonable efforts (without any obligation to incur any Liability, pay money or provide any other consideration) to assist and cooperate with Seller in furtherance of Seller’s efforts pursuant to this Section 5.4(b)(iii).

ARTICLE VIENVIRONMENTAL MATTERS

6.1Environmental Defects.

(a)Assertions of Environmental Defects. On or before the Defect Claim Date, Buyer may deliver claim notices to Seller meeting the requirements of this Section 6.1(a) (collectively, the “Environmental Defect Notices,” and each individually, an “Environmental Defect Notice”) setting forth any matters that, in Buyer’s reasonable opinion, constitute Environmental Defects and that Buyer intends to assert as Environmental Defects pursuant to this Section 6.1. Notwithstanding anything to the contrary herein, Buyer shall not be entitled to deliver Environmental Defect Notices in respect of any matters disclosed on Schedule 7.24, and no such matters shall be Environmental Defects for purposes of this Agreement. For all purposes of this Agreement and notwithstanding anything herein to the contrary, but subject to Seller’s representations and warranties in Section 7.20 and in the certificate delivered by Seller at Closing, and without limiting Buyer’s conditions to Closing set forth in Article X (including as set forth in Section 10.4), the provisions of Section 6.1(c) shall be the exclusive right and remedy of Buyer with respect to any Environmental Defect and Buyer shall be deemed to have waived, and Seller shall have no liability for, any Environmental Defect that Buyer fails to assert as an Environmental Defect by an Environmental Defect Notice received by Seller on or before the Defect Claim Date. To be effective, each Environmental Defect Notice shall be in writing, and shall include (i) a description of the alleged Environmental Defect (including the applicable Environmental Law(s) violated or implicated thereby), (ii) identification of the Property affected by the alleged Environmental Defect (each such Property, as applicable, an “Environmental Defect Property”), (iii) if applicable, the Allocated Value of each Environmental Defect Property, (iv) supporting documents available to Buyer reasonably necessary for Seller to identify the existence of the alleged Environmental Defect, and (v) a calculation (with reasonable supporting detail) of the Remediation Amount that Buyer asserts is attributable to the alleged Environmental Defect. To give Seller an opportunity to commence reviewing and curing Environmental Defects, Buyer agrees to use its reasonable efforts to give Seller weekly written notice of all Environmental Defects discovered by Buyer during the preceding period after the Original Execution Date and prior to delivery of such notice, which notice may be preliminary in nature and may be supplemented on or prior to the Defect Claim Date; provided that failure of Buyer to deliver a preliminary notice of any such Environmental Defect shall not be deemed to waive or otherwise prejudice Buyer’s right to assert any Environmental Defect on or before the Defect Claim Date. Buyer’s calculation of the Remediation Amount included in the Environmental Defect Notice must describe in reasonable detail the Remediation proposed for the Environmental Condition that gives rise to the asserted Environmental Defect and identify all assumptions used by Buyer in calculating the Remediation Amount, including the standards that Buyer asserts must be met to comply with Environmental Laws.

(b)Seller’s Right to Cure. Notwithstanding anything to the contrary herein, Seller shall have the right, but not the obligation, to attempt, at its sole cost, to Remediate, at any time during the Cure Period, any Environmental Defects of which it has timely received an Environmental Defect Notice from Buyer. In the event Seller elects prior to Closing to cure an asserted Environmental Defect that is not cured at Closing, Seller shall so notify Buyer, and at Closing, Buyer shall deposit the Environmental Defect amount of the asserted Environmental Defect into the Escrow Account at Closing. In the event that the asserted Environmental Defect is completely Remediated during the Cure Period, within two Business Days after the day upon which such asserted Environmental Defect is completely Remediated, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to Seller an amount equal to the Environmental Defect amount for the applicable Environmental Defect from the Escrow Account. In the event that the asserted Environmental Defect is not completely Remediated during the Cure Period, on the later to occur of (i) the day that is two Business Days after the expiration of the Cure Period, and (ii) the day that is two Business Days after the final resolution of any Environmental Dispute regarding such asserted Environmental Defect, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to each Party the funds in the Escrow Account to which such Party is entitled in respect of the applicable Environmental Defect.

(c)Remedies for Environmental Defects. Subject to (v) Seller’s continuing right to dispute the existence of an Environmental Defect and the Remediation Amount asserted with respect thereto, (w) the rights of Seller pursuant to Section 14.1(c), (x) the Individual Environmental Defect Threshold, (y) the Aggregate Deductible, and (z) Seller’s ongoing right to Remediate any Environmental Defect under Section 6.1(b), if any Environmental Defect timely asserted by Buyer in accordance with Section 6.1(a) is not waived in writing by Buyer or Remediated, then in connection with the Closing (unless, as of the Closing, the Parties are in disagreement with respect to the existence of such Environmental Defect or any associated Remediation Amount, in each of which case the applicable Environmental Dispute shall, unless otherwise agreed by the Parties, be addressed pursuant to Section 6.1(f)) Seller shall, at its sole option and discretion, elect one or more of the following remedies for such Environmental Defect:

(i)Seller will convey the entirety of the Environmental Defect Property that is subject to such Environmental Defect, together with all associated Assets, at Closing, to Buyer and make an accompanying reduction to the Purchase Price by the Remediation Amount for such Environmental Defect agreed to by the Parties or otherwise determined pursuant to Section 6.1(f); or

(ii)if the Remediation Amount of the Environmental Defect Property equals or exceeds the Allocated Value of the applicable Environmental Defect Property, Seller will retain the entirety of the Environmental Defect Property that is subject to such Environmental Defect, together with all associated Assets (in which case, such Assets shall become Excluded Assets hereunder), and reduce the Purchase Price by an amount equal to the Allocated Value of such Environmental Defect Property and such associated Assets.

If the option set forth in clause (i) above is selected, subject always to Seller’s right to Remediate any Environmental Defect under Section 6.1(b), (1) Buyer shall be deemed to have assumed responsibility for all costs and expenses attributable to the Remediation of the applicable Environmental Defect and all Liabilities (net to the Assets) with respect thereto, and (2) Buyer’s obligations with respect to the foregoing shall be deemed to constitute Assumed Obligations. If Seller elects to attempt to Remediate any Environmental Defect pursuant to Section 6.1(b), Seller shall use commercially reasonable efforts to complete such Remediation in a manner which is in compliance with the requirements of Environmental Laws in a timely fashion for the type of Remediation that Seller elects to undertake and at the Closing the Parties shall execute and deliver a mutually agreeable site access and indemnity agreement affording Seller with reasonable access to the relevant Assets to conduct such Remediation. Seller will be deemed to have adequately completed the Remediation required in the immediately preceding sentence (A) upon receipt of a certificate or approval from the applicable Governmental Authority that the Remediation has been implemented to the extent necessary to cure the Environmental Defect and comply with existing Laws or (B) subject to Buyer’s reasonable agreement, upon receipt of a certificate from a licensed professional engineer that the Remediation has been implemented to the extent necessary to cure the Environmental Defect and comply with existing Laws.

(d)Exclusive Remedy. Subject to Seller’s representations and warranties in Section 7.20 and in the certificate delivered by Seller at Closing, and without limiting Buyer’s conditions to Closing set forth in Article X (including as set forth in Section 10.4), the provisions of Section 6.1(c) shall be the exclusive right and remedy of Buyer with respect to any Environmental Defect or other environmental matter.

(e)Environmental Threshold and Deductible. Notwithstanding anything herein to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or any other remedy provided by Seller hereunder for any individual Environmental Defect for which the Remediation Amount applicable thereto does not exceed $50,000(the “Individual Environmental Defect Threshold”) and (ii) in no event shall there be any adjustments to the Purchase Price or any other remedy provided by Seller hereunder for any Environmental Defect for which the Remediation Amount applicable thereto exceeds the Individual Environmental Defect Threshold unless and until (A) the sum of (1) the Remediation Amounts of all such Environmental Defects that exceed the Individual Environmental Defect Threshold, in the aggregate (excluding any Remediation Amounts attributable to (v) Environmental Defects Remediated by Seller, and (w) Environmental Defect Properties that are retained by Seller pursuant to Section 6.1(c)(ii)), plus (2) the Title Defect Amounts (net of any offsetting Title Benefit Amounts in accordance with Section 5.2(e)) of all Title Defects that exceed the Individual Title Defect Threshold, in the aggregate (excluding any Title Defect Amounts attributable to (x) Title Defects cured by Seller, and (y) Title Defect Properties retained by Seller pursuant to Section 5.2(d)(ii)), exceeds (B) the Aggregate Deductible, in which case Buyer shall be entitled to remedies for such Environmental Defects only to the extent that the Remediation Amounts with respect thereto are in excess of such Aggregate Deductible.

(f)Environmental Dispute Resolution. Seller and Buyer shall attempt in good faith to agree on all Environmental Defects and Remediation Amounts (any dispute with respect to the foregoing matters, collectively “Environmental Disputes”) prior to the Closing or, if the applicable Environmental Dispute relates to any Environmental Defect Property for which Seller has attempted to Remediate the alleged Environmental Defect(s) following Closing and prior to the expiration of the Cure Period, then prior to the date that is ten Business Days following the expiration of the Cure Period. If Seller and Buyer are unable to agree within the above applicable time period, the Environmental Disputes shall be exclusively and finally resolved pursuant to this Section 6.1(f). Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section 6.1(f) with respect to any Environmental Defect properly asserted by Buyer prior to the Defect Claim Date, and to the extent any adjustments are not agreed upon by the Parties as of the Closing, unless Seller has elected to retain the applicable Environmental Defect Property pursuant to (and subject to the limitations in) Section 6.1(c)(ii), the affected Environmental Defect Property shall be assigned to Buyer at Closing and the Purchase Price shall be reduced by an amount equal to the Remediation Amount applicable for such Environmental Defect, which amount (including any disputed amounts) shall be paid into the Escrow Account at Closing and remain therein until such dispute is resolved pursuant to this Section 6.1(f). Any Environmental Disputes shall be submitted to an arbitrator, with at least ten years’ experience in environmental matters involving oil and gas properties including properties in the regional area in which the Subject Properties are located (the “Environmental Arbitrator”). If the Parties are unable to agree on the selection of the Environmental Arbitrator within ten Business Days of the Parties agreeing to submit an Environmental Dispute to the Environmental Arbitrator for determination or, in the case where the Parties have not so agreed, within ten Business Days of the non-submitting Party receiving written notice from the submitting Party stating that such Party has elected to submit an Environmental Dispute to arbitration in accordance with this Section 6.1(f), the AAA shall make the necessary appointment (which Environmental Arbitrator shall not have worked as an employee, outside counsel or as a consultant for any Party or its Affiliates during the five year period preceding the arbitration or have any financial interest in the dispute). The place of arbitration shall be Houston, Texas, and the arbitration shall be conducted in accordance with the AAA Rules, to the extent such rules do not conflict with the terms of this Section 6.1. The Parties, within ten days after the Environmental Arbitrator is appointed, shall submit written summaries of their positions regarding each Environmental Dispute. The Parties shall instruct the Environmental Arbitrator to make a determination, choosing either Seller’s position or Buyer’s position with respect to each Environmental Dispute, whichever the Environmental Arbitrator determines complies more closely to the terms of this Agreement, within 20 Business Days after the submission of the Parties’ summaries of the Environmental Disputes to the Environmental Arbitrator, and such determination shall be final and binding upon both Parties, without right of appeal. The costs of the Environmental Arbitrator shall be borne one-half by Seller and one-half by Buyer. In making its determination, the Environmental Arbitrator shall be bound by the terms of this Article VI and, subject to the foregoing, may consider such other matters as in the opinion of the Environmental Arbitrators are necessary to make a proper determination. The Environmental Arbitrator shall act for the limited purpose of determining the specific Environmental Disputes submitted by either Party and may not award damages, interest or penalties to either Party with respect to any Environmental Dispute. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case to the Environmental Arbitrator. Within two Business Days after the Environmental Arbitrator delivers written notice to Buyer and Seller of its award with respect to an Environmental Dispute, and subject to Section 6.1(e), Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse to each Party the funds in the Escrow Account to which such Party is entitled in respect of the applicable Environmental Dispute.

6.2NORM, Wastes and Other Substances. Buyer acknowledges that the Assets have been used for exploration, development and production of oil and gas and that there may be petroleum, produced water, wastes or other substances or materials located in, on or under the Assets or associated with the Assets. Equipment and sites included in the Assets may contain asbestos, NORM or other Hazardous Materials. NORM may affix or attach itself to the inside of wells, materials and equipment as scale, or in other forms. The Wells, materials and equipment located on the Assets or included in the Assets may contain NORM and other wastes or Hazardous Materials. NORM containing material or other wastes or Hazardous Materials may have come in contact with various environmental media, including water, soils or sediment. Special procedures may be required for the assessment, Remediation, removal, transportation or disposal of environmental media, wastes, asbestos, NORM and other Hazardous Materials from the Assets. Notwithstanding anything herein to the contrary, Buyer shall not be permitted to claim any Environmental Defect on the account of the presence of NORM on the Assets and the properties underlying the Assets.

ARTICLE VIIREPRESENTATIONS AND WARRANTIES OF SELLER

Seller represents and warrants to Buyer as of the Original Execution Date and as of the Closing Date the following:

7.1Organization, Existence. Each of AMH, AMSLP and OEA is a limited partnership duly formed and validly existing under the Laws of the State of Texas. Each of AMHGP and OEMGP is a limited liability company duly formed and validly existing under the Laws of the State of Texas. Each of AMFSC and AMR is a corporation duly formed and validly existing under the Laws of the State of Delaware. Seller has all requisite power and authority to own and operate its property (including the Assets) and to carry on its business as now conducted. Seller is duly licensed or qualified to do business as a foreign entity in the State of Texas, except where the failure to be so qualified would not reasonably be expected to have a Material Adverse Effect.

7.2Authorization. Seller has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by Seller of this Agreement have been, and each Transaction Document to which it is or will be a party will be, duly and validly authorized and approved by all necessary limited partnership, limited liability company or corporate action, as applicable, on the part of Seller. This Agreement is, and each Transaction Document to which Seller is or will be a party when executed and delivered by Seller will be, the valid and binding obligation of Seller and enforceable against Seller in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar Laws affecting the rights of creditors generally.

7.3No Conflicts. Except as set forth on Schedule 7.3, and assuming the receipt of all consents (including any Consent) and the waiver of all Preferential Purchase Rights (in each case) applicable to the transactions contemplated hereby, if applicable, the execution, delivery and performance by Seller of this Agreement and each Transaction Document to which it is or will be a Party and the consummation of the transactions contemplated herein and therein do not and will not in any material respect (a) conflict with or result in a breach of any provisions of the organizational documents or other governing documents of Seller or (b) result in a default or give rise to any right of termination, cancellation or acceleration or, except for Permitted Encumbrances, result in the creation of any Encumbrance under any of the terms, conditions or provisions of any Lease, Applicable Contract, note, bond, mortgage or indenture to which Seller is a party or by which Seller or any of the Assets may be subject or bound or (c) violate any Law applicable to Seller or any of the Assets, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a Material Adverse Effect.

7.4Consents. To Seller’s Knowledge, except (a) as set forth in Schedule 7.4, (b) for Preferential Purchase Rights, (c) under Contracts that are terminable without cost upon not greater than 60 days’ notice and (d) for Customary Post Closing Consents, there are no consents to assignment, prohibitions on assignments or requirements to obtain consents from any Third Party (in each case) that are required in connection with the consummation of the transactions contemplated by this Agreement (and the Instruments of Conveyance) by Seller or any of its Affiliates (each, a “Consent”).

7.5Foreign Person. Seller (or, if Seller is an entity disregarded as separate from any other Person within the meaning of Section 301.7701-3(a) of the Treasury Regulations, Seller’s regarded owner) is not a “foreign person” within the meaning of either Section 1445 or Section 1446(f) of the Code.

7.6Claims and Litigation. Except as set forth on Schedule 7.6, as of the Original Execution Date, there is no lawsuit, action, administrative or arbitration proceeding or litigation by any Person by or before any Governmental Authority or arbitrator, pending or, to Seller’s Knowledge, threatened in writing against Seller with respect to the Assets or which questions the validity of this Agreement or which could reasonably be likely to materially impair the ability of Seller to consummate the transactions contemplated hereby. For purposes of this Section 7.6, “threatened” shall mean that a Third Party has stated in writing the intention to pursue legal recourse against Seller.

7.7Material Contracts.

(a)To Seller’s Knowledge, Schedule 7.7(a) sets forth all Applicable Contracts of the type described below as of the Original Execution Date (collectively, the “Material Contracts”):

(i)any Applicable Contract that is a Hydrocarbon purchase and sale, transportation, gathering, treating, processing, compression or similar Contract that is not terminable without penalty on 30 days’ or less notice, including any such Applicable Contract providing for volumetric or monetary commitments or indemnification therefor or for dedication of future production;

(ii)any Applicable Contract that constitutes a lease under which Seller is the lessor or the lessee of real or personal property (other than any Lease) that (A) cannot be terminated by Seller without penalty upon 30 days’ or less notice and (B) involves an annual base rental of more than $25,000;

(iii)any Applicable Contract that is an indenture, mortgage, loan, credit agreement, sale-leaseback, guaranty of any obligation, bond, letter of credit or similar financial Contract;

(iv)any Applicable Contract that is a farmout or farmin agreement, joint venture agreement, term assignment, participation agreement, exploration agreement, development agreement, joint operating agreement, unit operating agreement, operating agreement, unit agreement, pooling agreement or similar Contract;

(v)any Applicable Contract for the sale, lease or exchange, of Seller’s interest in the Assets;

(vi)any Applicable Contract that contains any calls on, or options to purchase, material quantities of Hydrocarbon production, other than pursuant to currently effective Hydrocarbon purchase and sale contracts to which the Assets will be subject after Closing;

(vii)any Applicable Contract that can reasonably be expected to result in (A) aggregate payments by or on behalf of Seller or (B) aggregate revenues paid to Seller, in each case, of more than $100,000 during the current or any subsequent fiscal year or $250,000 in the aggregate over the term of such Applicable Contract (in each case, based solely on the terms thereof);

(viii)any Applicable Contract between Seller and any Affiliate of Seller that will be binding on Buyer after the Effective Time;

(ix)any existing Applicable Contract that is a seismic or other geophysical acquisition or sharing agreement or license for which Buyer will be liable;

(x)any Applicable Contract, the primary purpose of which is to provide indemnity rights;

(xi)any Applicable Contract that (A) contains or constitutes an existing area of mutual interest agreement or (B) includes non-competition restrictions, non-solicitation or no-hire obligations;

(xii)any Applicable Contract that is a drilling contract, rig contract or fracturing services contracts;

(xiii)any Applicable Contract that constitutes a partnership agreement or similar Contract (in each case, excluding any Tax partnership agreements); and

(xiv)any Applicable Contract that is a CBA.

(b)Except as set forth on Schedule 7.7(b), there exist no material defaults under the Material Contracts by Seller or, to Seller’s Knowledge, by any other Person that is a party to such Material Contracts. To Seller’s Knowledge, except for the agreements set forth on Schedule 7.7(b), there are no Material Contracts that contain mandatory drilling requirements with respect to the Assets (excluding any continuous drilling provisions included in a Lease or sublease required to hold all or any portion of the lands covered by such Lease or sublease), which obligations have not yet been fulfilled as of the Original Execution Date. On or before the day that is five Business Days after the Original Execution Date, Seller made available (electronically or otherwise) to Buyer all Material Contracts, including any and all amendments and supplements thereto.

7.8No Violation of Laws. Except as set forth on Schedule 7.8 neither Seller nor, to Seller’s Knowledge, any Third Party operator, is in material non-compliance with or in material violation of any applicable Laws (other than Environmental Laws), including with respect to the ownership and operation of the Assets.

7.9Preferential Purchase Rights. Except as set forth on Schedule 7.9, there are no preferential purchase rights, rights of first refusal, drag-along rights, tag-along rights or other similar rights that are applicable to the transfer of the Assets in connection with the transactions contemplated hereby (each a “Preferential Purchase Right”).

7.10Current Commitments. Schedule 7.10 sets forth, as of the Original Execution Date, all outstanding authorities for expenditures or other written capital proposals proposed by Seller to any Third Party or proposed by any Third Party to Seller, to conduct operations (“AFEs”) relating to the Assets that are in excess of $25,000 (net to Seller’s interest) and for which all of the activities anticipated in such AFEs have not been (or that are not reasonably expected to be) completed on or before the Effective Time.

7.11Asset Taxes. To Seller’s Knowledge, except as set forth on Schedule 7.11, (a) all Tax Returns relating to or prepared in connection with material Asset Taxes that are required to be filed by Seller have been timely filed and all such Tax Returns are correct and complete in all material respects, (b) all material Asset Taxes that are or have become due have been timely paid in full, and Seller is not delinquent in the payment of any such Taxes, or, in either case, such Taxes are currently being contested in good faith by Seller, (c) there is not currently in effect any extension or waiver of any statute of limitations of any jurisdiction regarding the assessment or collection of any material Asset Taxes, (d) there are no administrative or judicial proceedings by any taxing authority pending or in progress relating to or in connection with any material amounts of Asset Taxes, (e) all Asset Tax withholding and deposit requirements imposed by applicable Laws with respect to any of the Assets have been satisfied in all material respects, (f) no claim has been made by a Governmental Authority in a jurisdiction where Seller does not file Tax Returns with respect to Asset Taxes that Seller is or may be subject to taxation by that jurisdiction with respect to Asset Taxes (g) no Asset is subject to any tax partnership agreement or provisions requiring a partnership income tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute, and (h) each agreement or arrangement described on Schedule 7.11 with respect to clause (g) above (each a “Tax Partnership”) (A) to Seller’s Knowledge, has nothing that would prevent the Tax Partnership from making a valid election under Section 754 of the Code for its taxable year that includes the Closing Date, (B) has timely filed all U.S. federal income and other material Tax Returns required to be filed by the Tax Partnership and all such Tax Returns are correct and complete in all material respects and (C) has timely paid all U.S. federal income and other material Taxes required to be paid by the Tax Partnership.

7.12Brokers’ Fees. Seller has incurred no responsibility, liability or expense, contingent or otherwise, for brokers’ fees or finders’ fees, agent’s commissions or other similar forms of compensation relating to the transactions contemplated by this Agreement or the Transaction Documents for which Buyer or any Affiliate of Buyer shall have any responsibility.

7.13Advance Payments. Except for (a) the rights of any lessor to take free gas under the terms of the relevant Lease for its use on the lands covered by such Lease, (b) any throughput deficiencies and gas balancing arrangements attributable to or arising out of any Applicable Contract, (c) any Burdens and (d) any Imbalances, Seller is not obligated by virtue of any take-or-pay payment, advance payment or other similar payment, to deliver Hydrocarbons attributable to the Assets, or proceeds from the sale thereof, attributable to the Assets at some future time without receiving payment therefor at or after the time of delivery.

7.14Bonds and Credit Support. Schedule 7.14 lists all Asset Credit Support.

7.15Imbalances. To Seller’s Knowledge, Schedule 7.15 sets forth all material Imbalances associated with the Wells as of the date set forth on such Schedule.

7.16Leases; Suspense Funds.Except as set forth on Schedule 7.16, during the period of Seller’s ownership of the Assets, Seller has properly paid, or caused to be paid, all Burdens in all material respects due by Seller with respect to the Assets in accordance with Law and the applicable Lease. All such Burdens have been timely paid in all material respects, except to the extent that title opinions required in order to establish pay decks for the applicable well could not be delivered prior to the date first royalty payments for such well are required by applicable Law, notwithstanding the commercially reasonable efforts of Seller to do so (which amounts are reflected on Schedule 7.16). Except as set forth on Schedule 7.16, to Seller’s Knowledge, none of the Leases are being maintained in full force and effect by the payment of shut-in royalties or other payments in lieu of operations or production. Schedule 7.16 sets forth, as of the date set forth on such Schedule, all material Third Party Suspense Funds held by Seller.

7.17Hedge Contracts. Neither Seller nor any of its Affiliates has entered into any swap, forward, future or derivatives transaction or option or other similar hedge Contract (each a “Hedge Contract”) pursuant to which any production of Hydrocarbons from any of the Assets is dedicated or committed to as of or after the Effective Time.

7.18Insurance. Seller maintains with respect to the Assets the insurance coverage described on Schedule 7.18.

7.19Equipment and Personal Property. Except as disclosed on Section 7.19, to Seller’s Knowledge, Seller and all Third Party operators of the Assets have all easements, rights of way, licenses and authorizations, including those from Governmental Authorities necessary to access, construct, operate, maintain and repair the Wells and equipment included in the Assets consistent with current practices. To Seller’s Knowledge, all equipment used or held for use in connection with the Assets, has been maintained in working order and operating condition in all material respects and is adequate for normal operation of the Assets in all material respects consistent with current practices, ordinary wear and tear excepted.

7.20Wells; Plug and Abandon Notice. As of the Original Execution Date, except as set forth on Schedule 7.20, there are no Wells (a) in respect of which Seller or any of its Affiliates has received a written order from any Governmental Authority or a written demand from any Third Party (in each case) requiring that such Wells be plugged and abandoned and (b) to Seller’s Knowledge, in use for purposes of production or injection or suspended or temporarily abandoned in accordance with applicable Laws that (i) are required to be plugged and abandoned in accordance with applicable Laws or any Lease and (ii) have not been or are not in the process of being plugged and abandoned. To Seller’s Knowledge, all Wells that have been drilled, completed and operated by Seller within the five-year period prior to the Original Execution Date have been drilled and completed within the limits permitted by all applicable Leases, the Applicable Contracts and pooling or unit orders. To Seller’s Knowledge, no Well operated by Seller is subject to penalties or allowables after the Effective Time because of overproduction.

7.21Permits. To Seller’s Knowledge, (a) all necessary Permits with respect to the ownership or operation of all Wells that have been drilled, completed and equipped (or permanently plugged and abandoned) and operated by Seller within the five-year period prior to the Original Execution Date have been obtained and maintained and (b) there exists no material uncured violation of the terms and provisions of any such Permits. Neither Seller nor its Affiliates has received any written notice of from a Governmental Authority claiming the lack of a Permit or default under any Permit with respect to any Asset operated by Seller or its Affiliate.

7.22Payouts. Schedule 7.22 contains a complete and accurate list of the status of any “payout” balance, as of the date indicated on such Schedule, for the Wells that are subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

7.23Labor and Employment.

(a)Seller (with respect to the Assets and the Business Employees) is neither party to, nor bound by, any CBA; there are no CBAs or any other labor-related agreements or arrangements that pertain to any Business Employees; and no Business Employees are represented by any labor union or other labor organization with respect to their employment with Seller. To Seller’s Knowledge, in the past three years, there have been no labor organizing activities with respect to any Business Employees or relating to or affecting the Assets. In the past three years, there has been no actual or, to Seller’s Knowledge, threatened unfair labor practice charges, material grievances, labor-related grievances or arbitrations, strikes, lockouts, work stoppages, slowdowns, picketing, hand billing or other material labor disputes against or affecting Seller (with respect to the Assets or Business Employees).

(b)Seller (with respect to the Assets and the Business Employees) is, and for the last three years has been, in compliance in all material respects with all applicable Laws respecting labor, employment and employment practices.

7.24Environmental. Other than any Permits, except as set forth on Schedule 7.24, to Seller’s Knowledge, Seller has not entered into any agreements or consents with any environmental Governmental Authority and is not subject to any order, decree or judgment issued against Seller or any of its Affiliates by an environmental Governmental Authority, in each case, in existence as of the Original Execution Date and based on any Environmental Laws that relate to the future use of any of the Assets or that presently require any Remediation.

7.25Benefit Plans. Neither Seller nor any of its Affiliates has any, or is reasonably expected to have any, current or contingent liability or obligation: (i) under Title IV of ERISA; or (ii) on account of at any time being considered a single employer under Section 414 of the Code with any other Person. No Liability under Section 302 or Title IV of ERISA has, during the immediately preceding six years, been incurred by any of Seller, its Affiliates or any of their respective ERISA Affiliates or their respective predecessors that has not been satisfied in full, and no condition exists that presents a risk to any of Seller, its Affiliates or any such ERISA Affiliate of incurring any such Liability.

7.26No Transfer.Except as set forth on Schedule 7.26 and subject to the Permitted Encumbrances, to Seller’s Knowledge, Seller has not transferred, sold, mortgaged, or pledged any material portion of the Properties covering any depths other than the applicable Target Formation(s) to (i) any Affiliate (except for any Assets that such Affiliate is conveying to Buyer under this Agreement) or (ii) any Third Party, in either case, within the one-year period prior to the Original Execution Date.

ARTICLE VIIIBUYER REPRESENTATIONS AND WARRANTIES

Buyer represents and warrants to Seller as of the Original Execution Date and as of the Closing Date the following:

8.1Organization; Existence. Buyer is a limited liability company, duly formed, validly existing and in good standing under the Laws of the State of Delaware and has all requisite power and authority to own and operate its property and to carry on its business as now conducted. Buyer is duly licensed or qualified to do business as a foreign limited liability company in Texas.

8.2Authorization. Buyer has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery, and performance by Buyer of this Agreement have been, and of each Transaction Document to which it is or will be a party will be, duly and validly authorized and approved by all necessary limited liability company action on the part of Buyer. This Agreement is, and each Transaction Document to which Buyer is or will be a party when executed and delivered by Buyer will be, the valid and binding obligation of Buyer and enforceable against Buyer in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws affecting the rights of creditors generally.

8.3No Conflicts. The execution, delivery, and performance by Buyer of this Agreement and each Transaction Document to which it is or will be a Party and the consummation of the transactions contemplated herein and therein will not in any material respect (a) conflict with or result in a breach of any provisions of the organizational or other governing documents of Buyer or (b) result in a default or give rise to any right of termination, cancellation or acceleration or result in the creation of any Encumbrance under any of the terms, conditions or provisions of any note, bond, mortgage or indenture to which Buyer is a party or by which Buyer or any of its property may be subject or bound or (c) violate any Law applicable to Buyer or any of its property, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement or the Transaction Documents to which it is or will be a Party or perform its obligations hereunder or thereunder.

8.4Consents. Except (a) as set forth in Schedule 8.4 and (b) for Customary Post Closing Consents, there are no consents, approvals, authorizations or other restrictions on assignment, including requirements for consents from Third Parties to any assignment, that are required or would be applicable in connection with the consummation of the transactions contemplated by this Agreement or any Transaction Document by Buyer.

8.5Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s Knowledge, threatened against Buyer or any Affiliate of Buyer, and Buyer is not insolvent or generally not paying its debts when they become due.

8.6Claims and Litigation. There is no lawsuit, action, administrative or arbitration proceeding or litigation by any Person by or before any Governmental Authority or arbitrator, pending, or to Buyer’s Knowledge, threatened in writing against Buyer or any of its Affiliates that would have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement. For purposes of this Section 8.6, “threatened” shall mean that a Third Party has stated in writing the intention to pursue legal recourse against Buyer or any of its Affiliates.

8.7Regulatory. As of the Closing Date, Buyer (or, if applicable, Buyer’s operating Affiliate) shall be qualified under all applicable Laws to own, operate and hold the Assets, and the consummation of the transactions contemplated in this Agreement will not cause Buyer (or, if applicable, Buyer’s operating Affiliate) to be disqualified as such an owner, operator or lessee. To the extent required by any applicable Laws, as of the Closing Date, Buyer (or, if applicable, Buyer’s operating Affiliate) (a) will have lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, all applicable Laws governing the ownership of the Assets, including those set forth on Schedule 7.14 and (b) will have filed any and all required reports necessary for such ownership or lease with all Governmental Authorities having jurisdiction over such ownership or lease, in each case of (a) and (b), except where the failure to do so would not have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement.

8.8Financing.

(a)Buyer shall have as of the Closing Date, sufficient cash with which to pay the Purchase Price; and Buyer has, or will have, sufficient cash to pay on a timely basis all costs required to be paid by Buyer under this Agreement, the Leases and the Applicable Contracts as and when due from and after the Closing. Each Commitment, when delivered to Seller pursuant to Section 9.4, will be a legal, valid and binding obligation of Buyer and, to the Knowledge of Buyer, the other parties thereto, in full force and effect, and enforceable against the parties thereto in accordance with its terms, subject to the effect of bankruptcy, insolvency, reorganization, moratorium and similar Laws affecting the rights of creditors generally.

(b)On January 17, 2020, Buyer furnished to Seller an accurate and complete copy of the Commitment Documentation as amended on the Execution Date in an amount equal to at least $315,000,000 in the aggregate (the “Required Amounts”). The obligations of the Commitment Parties to fund the financing contemplated by the Commitment are not subject to any conditions or other contingencies related to the funding of the full Required Amounts other than as set forth in the Commitment Documentation. The Commitment Documentation constitutes the entire and complete agreement between the Commitment Parties and Buyer with respect to the Commitment. Notwithstanding the foregoing, Buyer’s ability to consummate the transactions contemplated hereby is not contingent upon its ability to secure any financing (including the financing contemplated by the Commitment) or to complete any public or private placement of securities prior to or upon Closing.

8.9Independent Evaluation. Buyer is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and the Transaction Documents to which it is or will be a Party and to consummate the transaction contemplated hereby and thereby, except to the extent of Seller’s express representations and warranties in Article VII and the limited special warranty of Defensible Title in the Instruments of Conveyance, Buyer has relied or shall rely on its own independent investigation and evaluation of the Assets, which investigation and evaluation was done by Buyer and its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors. In entering into this Agreement, Buyer acknowledges that it has relied solely upon the aforementioned investigation and evaluation and not on any factual representations or opinions of Seller or any representatives or consultants or advisors engaged by or otherwise purporting to represent Seller or any Affiliate of Seller (except the specific representations and warranties of Seller set forth in Article VII and the limited special warranty of Defensible Title in the Assignment). Buyer hereby acknowledges that, other than the representations and warranties made in Article VII and the limited special warranty of Defensible Title in the Instruments of Conveyance, neither Seller nor any representatives, consultants or advisors of Seller or its Affiliates make or have made any representation or warranty, express or implied, at Law or in equity, with respect to the Assets.

8.10Brokers’ Fees. Buyer has incurred no responsibility, liability or expense, contingent or otherwise, for brokers’ fees or finders’ fees, agent’s commissions or other similar forms of compensation relating to the transactions contemplated by this Agreement or the Transaction Documents for which Seller or Seller’s Affiliates shall have any responsibility.

8.11Accredited Investor. Buyer is an accredited investor, as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Assets for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws.

ARTICLE IXCERTAIN AGREEMENTS

9.1Conduct of Business. Except (v) for renewal of expiring insurance coverage in the ordinary course of business, (w) as set forth on Schedule 9.1, (x) as required to comply with applicable Laws, (y) for emergency operations, and (z) as expressly contemplated by this Agreement or expressly consented to in writing by Buyer:

(a)Seller agrees that from and after the Original Execution Date until Closing, Seller will:

(i)subject to any interruptions resulting from force majeure, mechanical breakdown and planned maintenance,maintain or cause its Affiliates to maintain the Assets in the usual, regular and ordinary manner consistent with past practice (except for any Asset that terminates in accordance with its terms or the termination or relinquishment of any Asset due to Seller’s failure to drill a well or conduct any other activity for the exploration for, or development or production of, Hydrocarbons within a certain time period, including or pursuant to any continuous drilling obligation provisions in the Leases or any Applicable Contract);

(ii)maintain or cause its Affiliates to maintain the books of account and Records relating to the Assets in the usual, regular and ordinary manner, in accordance with its usual accounting practices;

(iii)give written notice to Buyer as soon as is practicable of any material damage or casualty to or destruction or condemnation of any of the Assets of which Seller has Knowledge;

(iv)use commercially reasonable efforts to pay or cause to be paid all Burdens, Asset Taxes that are due and payable prior to the Closing and Operating Expenses, and other payments incurred with respect to the Assets consistent with past practice;

(v)maintain insurance coverage on the Assets in the amounts and types described in Schedule 7.18;

(vi)notify Buyer of any election that Seller or its or their Affiliates is required or has the right to make under any joint operating agreement, marketing or purchase contract, area of mutual interest agreement or farmout agreement, specifying the nature and time period associated with such election; and

(vii)give prompt notice (and in any event within one Business Day of receipt of written notice from any Third Party) to Buyer of any emergency requiring immediate action, or any emergency action taken, in the face of serious risk to life, property or the environment (including prevention of environmental contamination).

(b)Seller agrees that from and after the Original Execution Date until Closing, Seller will not:

(i)except for operations undertaken to avoid (or as a result of) any order of a Governmental Authority, propose any operations with respect to the Assets or agree to participate in any operations with respect to the Assets, in each case, that (1) is reasonably expected to result in expenditures greater than $50,000 with respect to Seller’s interest in such Assets or (2) has been approved by the Bankruptcy Court prior to the Original Execution Date; provided that, if a Third Party proposes any operation with respect to any Asset pursuant to any AFE received by Seller, then Seller shall forward such AFE to Buyer as soon as is reasonably practicable (and no later than one Business Day) and thereafter Buyer shall have the lesser of (x) five Business Days following its receipt of such AFE and (y) the date that is two Business Days prior to the date that a response to such AFE is due from Seller to the applicable Third Party, to elect, by written notice to Seller, whether to participate or not participate in such operation; and provided, further, that in the event that Buyer’s election is contrary to the election that Seller desires to make with respect to such operation, then (A) if Seller wants to participate in the operation and Buyer does not, the Assets affected thereby shall be excluded from the transactions contemplated hereby and be considered Excluded Assets, and the Purchase Price shall be reduced by the Allocated Values of the Assets so excluded, and (B) if Seller does not want to participate in the operation and Buyer does so, then Buyer shall be obligated to advance the funds required in connection with such operation (and Seller shall consent to participate in such operation to the applicable Third Party operator), and if this Agreement is terminated prior to Closing, Seller shall, within one Business Day after such termination, convey to Buyer all of Seller’s interest in and to the Assets covered by such operation (on a form of conveyance substantially similar to the Assignment, with appropriate modifications to reflect the Assets so conveyed), and then only to the extent of such Assets that are covered by such operations;

(ii)except as consented to by Buyer in accordance with Section 9.1(b)(i), become a non-consenting party to any operation proposed by a Third Party;

(iii)enter into any Lease or any Applicable Contract that if entered into on or prior to the Original Execution Date, would be required to be listed on Schedule 7.7(a);

(iv)terminate (unless such instrument terminates pursuant to its express terms) or materially amend the terms of any Lease, Permit or Assigned Contract (or any Material Contract that could become an Assigned Contract);

(v)transfer, sell, mortgage or pledge any of the Assets, other than the sale or disposal of Hydrocarbons in the ordinary course of business and sales of obsolete equipment that is no longer necessary in the operation of the Assets or for which replacement equipment has been obtained (and other than the termination or relinquishment of any Asset due to Seller’s failure to drill a well or conduct any other activity for the exploration for, and/or development and/or production of, Hydrocarbons within a certain time period, including pursuant to any continuous drilling obligation provisions in the Leases or any Applicable Contract);

(vi)settle any suit or litigation or waive any material claims, in each case, attributable to the Assets and affecting the period after the Effective Time;

(vii)grant or create any right to Consent to the disposition of, or Preferential Purchase Rights with respect to, any of the Assets;

(viii)unless required by Law, (A) enter into, amend, extend or terminate any CBA or (B) recognize or certify any labor union, labor organization or group of employees as the bargaining representative for any Business Employees;

(ix) hire or terminate (other than for cause) any Business Employee or reassign the duties of (A) a Business Employee such that he or she is no longer a Business Employee or (B) any other employee of Seller such that he or she would be a Business Employee;

(x)[RESERVED]

(xi)authorize, agree or commit to do any of the foregoing.

For the avoidance of doubt, the pendency of the Chapter 11 Case and any actions required to be taken by Seller pursuant to an order of the Bankruptcy Court in connection with the Chapter 11 Case shall in no way be deemed a breach of this Section 9.1(b).

(c)Without expanding any obligations which Seller may have to Buyer, it is expressly agreed that Seller shall never have any liability to Buyer with respect to any breach or failure of Section 9.1(a)(i) greater than that which it might have as the operator to a non-operator under the applicable operating agreement (or, in the absence of such an agreement, under the AAPL 610 (1989 Revision) form Operating Agreement), IT BEING RECOGNIZED THAT, UNDER SUCH AGREEMENTS AND SUCH FORM, THE OPERATOR IS NOT RESPONSIBLE FOR ITS OWN NEGLIGENCE, AND HAS NO RESPONSIBILITY OTHER THAN FOR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

(d)Buyer acknowledges that Seller owns undivided interests in certain of the Assets with respect to which it is not the operator, and Buyer agrees that the acts or omissions of the other working interest owners (including the operators) who are not Seller or any Affiliates of Seller shall not constitute a breach of the provisions of this Section 9.1, nor shall any action required by a vote of working interest owners constitute such a breach so long as Seller has voted its interest in a manner that complies with the provisions of this Section 9.1.

9.2Bonds. Buyer acknowledges that none of Asset Credit Support will be transferred to Buyer. At or prior to Closing, Buyer shall obtain, or cause to be obtained in the name of Buyer (or, if applicable, Buyer’s operating Affiliate), replacements for such Asset Credit Support (in each case, insofar and only to the extent necessary under an Assigned Contract or as required under applicable Law) to the extent such replacements are necessary (i) to consummate the transactions contemplated by this Agreement and (ii) to permit the cancellation of such Asset Credit Support posted by Seller or any of its Affiliates. In addition, at or prior to Closing, Buyer shall deliver to Seller evidence of Buyer’s posting of bonds or other security necessary to replace the Asset Credit Support listed on Schedule 7.14, in each case, insofar as and only to the extent necessary under an Assigned Contract or as required under applicable Law. At or prior to Closing, Buyer shall use commercially reasonable efforts to cooperate with Seller and cause the cancellation of such Asset Credit Support, including discussions with OneOk to ensure the return of Asset Credit Support provided by or on behalf of Seller or its Affiliates under any OneOk Contract. Notwithstanding anything to the contrary herein, in no event shall the OneOk Contract be an Assigned Contract unless any Asset Credit Support provided by or on behalf of any Seller or Affiliate of Seller in connection with such Applicable Contract is returned to Seller at or prior to Closing.

9.3Notifications. If, prior to Closing, either Seller or Buyer obtains Knowledge that the other Party has breached a representation, warranty, covenant, obligation or other agreement under this Agreement, then Seller or Buyer, as applicable, shall promptly inform such other Party of such breach so that such other Party may attempt to remedy or cure such breach prior to Closing; provided that, such notice shall not be deemed and shall not constitute a waiver of any claim or recourse against the other Party or its Affiliates (including any claim for indemnity) with respect to any breach by such other Party of such other Party’s representations, warranties, covenants, obligations or other agreements, and shall not in any way preclude the right of any Party to rely on the representations and warranties of the other Party given in this Agreement or in the certificates delivered by such Party at Closing pursuant to this Agreement.

9.4Financing.

(a)From and after the Execution Date until the Closing:

(i)Buyer shall use its reasonable best efforts to obtain the financing under the Commitment required to effect the transactions contemplated by this Agreement as promptly as practicable, including, without limitation, (1) using reasonable best efforts to (A) maintain in effect the Commitment Documentation, (B) satisfy on a timely basis all terms, covenants and conditions set forth in the Commitment, (C) enter into definitive agreements with respect thereto on the terms and conditions contemplated by the Commitment Documentation and (D) consummate such financing at or prior to Closing and (2) seeking to enforce its rights under the Commitment.

(ii)Upon Seller’s reasonable request, Buyer shall keep Seller reasonably informed with respect to all material activity concerning the status of the financing contemplated by the Commitment and shall give Seller prompt notice of any adverse change with respect to such financing. Without limiting the foregoing, Buyer agrees to notify Seller promptly, if at any time prior to the Closing Date (1) any Commitment shall expire or be terminated for any reason, (2) any financing source that is a party to any Commitment notifies Buyer that such source no longer intends to provide financing to Buyer on the terms set forth therein, or (3) for any reason Buyer no longer believes in good faith that it will be able to obtain all or any portion of the financing contemplated by the Commitment on the terms described therein.

(iii)Buyer shall not permit any amendment, supplement or modification to be made to, or any waiver of any provision under, the Commitment Documentation if such amendment, supplement, modification or waiver, (A) reduces (or could reasonably be expected to have the effect of reducing) the aggregate amount of the financing, or (B) imposes new or additional conditions or otherwise expands, amends or modifies any of the conditions to the Commitment, or imposes new or additional conditions or otherwise expands, amends or modifies any other provision of the Commitment Documentation, in the case of clause (B), in a manner that would (x) reasonably be expected to prevent or make less likely the funding of the Commitment in an amount necessary to fund the Required Amounts on the Closing Date or (y) adversely impact the ability of Buyer to enforce its rights against other parties to the Commitment Documentation with respect thereto (provided that, subject to compliance with the other provisions of this Section 9.4, Buyer may amend the Commitment Documentation to add additional lenders, arrangers, bookrunners and agents). Buyer shall promptly deliver to Seller copies of any amendment, supplement, waiver, consent, modification or replacement in respect of the Commitment Documentation (other than an amendment to add additional lenders, arrangers, bookrunners and agents). Buyershall not agree to the withdrawal, termination, repudiation, reduction or rescission of any commitment in respect of the Commitment, and shall not release or consent to the termination of the obligations of the financing sources under the Commitment, in each case, without the prior written consent of Seller, to the extent such withdrawal, termination, repudiation, reduction or rescission is in an amount such that the net proceeds of the Commitment would not be in an amount sufficient to fund the Required Amounts at Closing after giving effect thereto. Buyer shall promptly deliver to Seller copies of any such amendment, modification or replacement. For purposes of this Agreement, (i) references to “Commitment” and “Commitment Documentation” shall include the financing contemplated by the Commitment Documentation as permitted to be amended, modified, supplemented or replaced by this Section 9.4.

(iv)If any portion of the financing becomes unavailable in the amount contemplated in any Commitment or any Commitment shall be terminated or modified in a manner materially adverse to Buyer for any reason, Buyer shall use its reasonable best efforts to obtain alternative financing from alternative sources in an amount sufficient to enable Buyer to perform its obligations under, and to consummate the transactions contemplated by, this Agreement and to obtain, and, if obtained, will provide Seller with a copy of, a new financing commitment that provides for at least the same amount of financing as the Commitment as originally issued, to the extent needed to fund the Required Amounts, and on terms and conditions (including termination rights and funding conditions) not materially less favorable to Buyer than those included in the Commitment (the “New Commitment”). To the extent applicable, Buyer shall use reasonable best efforts to obtain the alternative financing as set forth in the New Commitment as promptly as practicable, including, without limitation, (1) using reasonable best efforts to (A) satisfy on a timely basis all terms, covenants and conditions set forth in the New Commitment, (B) enter into definitive agreements with respect thereto on the terms and conditions contemplated by the New Commitment and (C) consummate such financing at or prior to Closing and (2) seeking to enforce its rights under the New Commitment (including through litigation). In the event alternative financing is obtained and a New Commitment is entered into, references in this Agreement to the Commitment shall be deemed to refer to the New Commitment, and references in this Agreement to the financing under the Commitment shall be deemed to refer to the alternative financing under the New Commitment, in each case as applicable.

(b)Prior to the Closing Date, Seller shall use, and shall cause each of its controlled Affiliates to use, and shall use reasonable best efforts to have each of its and its controlled Affiliates’ respective directors, officers and advisors to use, in each case, their respective reasonable best efforts to provide to Buyer, all cooperation reasonably necessary and customary in connection with the arrangement of the Commitment (provided that such requested cooperation does not unreasonably interfere with the ongoing operations of Seller or its controlled Affiliates), which reasonable best efforts shall include (i) upon reasonable notice, and at reasonable times and locations to be mutually agreed, causing the management teams of Seller and its controlled Affiliates with appropriate seniority and expertise and external auditors to participate in a reasonable number of meetings, drafting sessions, presentations, road shows, and rating agency and due diligence sessions, (ii) assisting with the preparation of (A) offering documents, private placement memoranda, bank information memoranda, prospectuses and similar documents reasonably necessary in connection with the Commitment and (B) materials for rating agency presentations, (iii) executing customary authorization letters or management representation letters, as applicable, (iv) furnishing Buyer with the financial statements which are necessary to satisfy the conditions set forth in the Commitment Documentation promptly after such financial statements become available, (v) assisting with the preparation of any pledge and security documents, guarantees, other definitive financing documents, or other related certificates or documents as may be reasonably requested by Buyer and otherwise facilitating the pledging of collateral to the extent required at Closing by the Commitment Documentation (including cooperation in connection with the pay-off at Closing of existing Indebtedness and the release, following such repayment, of related Liens and termination, following such repayment, of security interests (including delivering prepayment or termination notices as required), and (vi) to the extent requested at least ten Business Days prior to the Closing Date, providing, at least three Business Days prior to the Closing Date, all documentation with respect to Seller and its controlled Affiliates required by applicable “know your customer” and anti-money laundering applicable laws, including the USA PATRIOT Act, to the extent requested in writing at least ten Business Days prior to the Closing Date; provided, however, that Seller shall not be required to provide, or cause its controlled Affiliates to provide, cooperation under this Section 9.4 that: (A) unreasonably interferes with the ongoing business of Seller or its controlled Affiliates; (B) causes any covenant, representation or warranty in this Agreement to be breached or otherwise causes the breach of this Agreement or any Contract to which any of Seller or its controlled Affiliates is a party, in each case, in a manner that would cause any closing condition set forth herein to fail to be satisfied; (C) requires Seller or its controlled Affiliates to incur any liability, cost or expense (including, without limitation, any commitment fees and expense reimbursement) in connection with the Commitment (other than the authorization letters and management representation letters) prior to, or that are not conditioned upon, the Closing, provided that Seller or its controlled Affiliates shall be reimbursed by Buyer for any such liability, cost or expense so incurred; (D) requires Seller or its controlled Affiliates or their respective directors, officers, managers or employees (other than execution and delivery into escrow by those officers that will act in a similar capacity after the Closing) to execute, deliver or enter into, or perform any agreement, document, certificate or instrument with respect to the Commitment (other than with respect to the authorization letters and management representation letters) or adopt resolutions approving the agreements, documents and instruments pursuant to which the Commitment is obtained; or (E) requires Seller or its controlled Affiliates to provide any information that is prohibited or restricted by applicable Law or applicable confidentiality undertaking or that constitutes privileged information or attorney-client work product, to the extent Seller and its controlled Affiliates uses reasonable best efforts to provide such information in a manner that does not breach such undertaking, obligation or privilege.

Seller hereby consents to the use of its and its controlled Affiliates’ logos in connection with the Commitment; provided that such logos are used solely in a manner that is not intended to or reasonably likely to harm or disparage Seller or any of its controlled Affiliates or the reputation or goodwill of Seller or any of its controlled Affiliates.

9.5Equitable and Other Remedies. The Parties agree that damages may not be a sufficient remedy to any breach of the provisions of Section 4.2, Section 9.6, Section 14.3, Section 16.6 or Section 16.8 of this Agreement and the non-breaching Party may be irreparably and immediately harmed if any of such provisions of this Agreement are not performed by the other Party or its Affiliates (as applicable) strictly in accordance with their respective terms. In the event of a breach of any of the above listed provisions, the non-breaching Party shall provide written notice and a demand to cease or cure any such breach; provided that, in the event such breach (a) is not susceptible to cure or (b) if susceptible to being cured, has not been cured within five days after delivery of such written notice thereof to the breaching Party, the non-breaching Party shall have the right, in addition to any other rights such Party may have, to obtain injunctive relief, without the posting of any bond and without proof of actual damages, to restrain any breach or any anticipated or threatened breach by the other Party or obtain specific enforcement of such terms. Such remedy shall not be deemed to be the exclusive remedy for such breach of this Agreement, but shall be in addition to all of the remedies at Law or in equity available to the non-breaching Party.

9.6Record Retention. Buyer, for a period of seven years following Closing, will (a) retain the Records, (b) provide Seller, its Affiliates, and its and their officers, employees and representatives with reasonable access to the Records during normal business hours for review and copying, and (c) provide Seller, its Affiliates and its and their officers, employees and representatives with access, during normal business hours, to materials received or produced after the Closing relating to any indemnity claim made under Section 13.1(a); provided that Buyer may destroy Records from time to time and prior to the end of such period in accordance with its normal document retention policy as long as Buyer notifies Seller at least 30 days in advance and provides Seller an opportunity to remove or copy such Records.

9.7Successor Operator. Buyer acknowledges and agrees that Seller cannot and does not covenant or warrant that Buyer (or, if applicable, Buyer’s operating Affiliate) shall become successor operator of any Assets operated by Seller or its Affiliates because such Assets may be subject to operating or other agreements that control the appointment of a successor operator. Seller agrees, however, that as to Assets Seller or its Affiliate operates, Seller shall use commercially reasonable efforts to have Buyer (or, if applicable, Buyer’s operating Affiliate) designated or appointed (to the extent legally possible under applicable Law and permitted under any applicable operating agreement) successor operator of such Assets effective as of Closing, provided that in no event shall Seller or any Affiliate of Seller be obligated to provide any consideration in connection therewith.

9.8Bankruptcy Court Matters.

(a)[Reserved.]

(b)Seller and AMR shall take such actions as may be reasonably necessary to (i) obtain entry of the Sale Order and (ii) consummate the Transaction, in each case, in accordance with this Agreement.

(c)To the extent not otherwise set forth in the Sale Order, each of Seller and AMR shall take such actions as may be reasonably necessary to obtain entry of a Final Order approving release and exculpation provisions substantially in the form attached hereto as Exhibit G.

(d)Buyer and Seller acknowledge that this Agreement and the sale of the Assets and assumption and assignment of the Assigned Contracts are subject to Bankruptcy Court approval. Buyer and Seller acknowledge that (i) to obtain such approval and to satisfy Seller’s fiduciary duties to all applicable stakeholders in accordance with applicable Law, Seller must demonstrate that it has taken reasonable steps to obtain the highest or otherwise best offer possible for the Assets, and that such demonstration shall include giving notice of the transactions contemplated by this Agreement to creditors and other interested parties as ordered by the Bankruptcy Court and, if necessary, conducting the Auction, (ii) Buyer must provide adequate assurance of future performance as may be required under section 365 of the Bankruptcy Code with respect to the Assigned Contracts, and (iii) to the extent such adequate assurance of future performance is not provided with respect to an Assigned Contract, then such Assigned Contract will be excluded from the Assets and included in the Excluded Assets.

(e)In the event an objection is filed, an appeal is taken or a stay pending appeal is requested, from either the Bidding Procedures Order, the Sale Order, or any other order reasonably necessary in connection with the Transaction, as applicable, Seller shall promptly notify Buyer of such objection, appeal or stay request and shall provide to Buyer promptly a copy of the related objection, notice of appeal or order of stay. Seller shall also provide Buyer with written notice of any motion or application filed in connection with an objection or any appeal from either of such orders and Seller agrees to take all action as may be commercially reasonable and appropriate to defend against such appeal, petition or motion and Buyer agrees to cooperate in such efforts.

(f)From and after the Original Execution Date and prior to the Closing or the termination of this Agreement in accordance with Section 14.1, neither Seller nor AMR shall take any action which is intended to (or is reasonably likely to), or fail to take any action the intent (or the reasonably likely result) of which failure to act is to, result in the reversal, voiding, modification or staying of the Bidding Procedures Order or this Agreement. If Buyer is the Successful Bidder at the Auction, neither Seller nor AMR shall take any action which is intended to (or is reasonably likely to), or fail to take any action the intent (or the reasonably likely result) of which failure to act is to, result in the reversal, voiding, modification or staying of the Sale Order or this Agreement.

(g)From and after the date of this Agreement and until the Closing Date, at least three (3) Business Days prior to the filing thereof, to the extent reasonably practicable, Seller and AMR shall deliver to Buyer drafts of any and all material pleadings, motions, notices, statements, applications, schedules, reports, and other papers to be filed or submitted by any Seller Party or AMR in connection with or related to this Agreement for Buyer’s prior review. Seller and AMR shall make reasonable efforts to consult and cooperate with Buyer regarding (i) any such pleadings, motions, notices, statements, applications, schedules, reports, or other papers, (ii) any discovery taken in connection with the seeking entry of the Sale Order (including any depositions), and (iii) any hearing relating to the Sale Order, including the submission of any evidence, including witnesses testimony, in connection with such hearing.

(h)The bidding procedures to be employed with respect to this Agreement shall be those reflected in the Bidding Procedures Order. Buyer agrees and acknowledges that Seller, including through its representatives, is and may continue soliciting inquiries, proposals or offers from Third Parties for the Assets (and negotiating the terms of such proposals or offers) in connection with any alternative transaction pursuant to the terms of the Bidding Procedures Order.

(i)Without limiting the requirements of Sections 9.8(a) through (h), from and after the Original Execution Date and through the Closing or the termination of this Agreement in accordance with Section 14.1, each of AMR, the Seller Parties and Buyer agree to:

(i)support and take all steps reasonably necessary and desirable to consummate the Transactions in accordance with this Agreement;

(ii) to the extent any legal or structural impediment arises that would prevent, hinder, or delay the consummation of the Transactions contemplated in this Agreement, support and take all steps reasonably necessary and desirable to address any such impediment;

(iii) negotiate in good faith and use commercially reasonable efforts to execute and deliver the definitive documents and any other required agreements to effectuate and consummate the Transactions as contemplated by this Agreement; and

(iv) consult and negotiate in good faith with material stakeholders, and their advisors regarding the execution of definitive documents and the implementation of the Transactions.

(j)Without limiting the requirements of Section 9.8(a) through (i), from and after the Original Execution Date and through the Closing or the termination of this Agreement in accordance with Section 14.1, each of the Seller Parties and AMR agrees to:

(i)use commercially reasonable efforts to obtain any and all required regulatory and/or Third Party approvals for the Transactions;

(ii)upon reasonable request of Buyer, inform the advisors to Buyer as to: (A) the material business and financial (including liquidity) performance of the Seller Parties, but only to the extent Seller prepares reports or materials regarding such items in the ordinary course of business; (B) the status and progress of the Transactions, including progress in relation to the negotiations of the definitive documents; and (C) the status of obtaining any necessary or desirable authorizations (including any consents) from each secured lender, any competent judicial body, governmental authority, banking, taxation, supervisory, or regulatory body or any stock exchange;

(iii)inform counsel to Buyer as soon as reasonably practicable after becoming aware of: (A) any matter or circumstance which they know, or believe is likely, to be a material impediment to the implementation or consummation of the Transactions; and (B) any notice of any commencement of any material involuntary insolvency proceedings, legal suit for payment of debt or securement of security from or by any person in respect of any Seller Party or AMR; and

(iv)use good faith efforts to seek additional support for the Transaction from their other material stakeholders to the extent reasonably prudent and, to the extent the Seller Parties receive such support, to notify Buyer of such support and documentation thereof.

(k)Nothing in this Agreement, including this Section 9.8, shall require any director or officer of any Seller Party or AMR to violate their fiduciary duties to such Seller Party or AMR, as applicable. No action or inaction on the part of any director or officer of any Seller Party or AMR that such director or officer reasonably believes is required by their fiduciary duties to such Seller Party or AMR (as applicable) shall be limited or precluded by this Agreement; provided, however, that no such action or inaction shall be deemed to prevent Buyer from exercising any termination rights it may have hereunder as a result of such action or inaction.

(l)If an Auction is conducted and Seller does not choose Buyer as the Successful Bidder, but instead chooses Buyer as the Backup Bidder, Buyer will serve as the Backup Bidder. If Buyer is chosen as the Backup Bidder, Buyer will be required to keep its bid to consummate the transactions contemplated by this Agreement on the terms and conditions set forth in this Agreement (as may be amended with Buyer’s written consent prior to or at the Auction) open and irrevocable until the Closing of the sale of the Assets to the Successful Bidder; provided that Buyer shall not be required to serve as Backup Bidder unless (i) the Successful Bid (as defined in the Bidding Procedures Order) contemplates the acquisition of all or substantially all of the assets of both Seller and the KFM Sellers, or (ii) Buyer is also the “Successful Bidder” or “Backup Bidder” (each as defined in the KFM Agreement) for all or substantially all of the assets of the KFM Sellers. If the agreement with the Successful Bidder is terminated prior to Closing, Buyer will be deemed to be the Successful Bidder and will forthwith consummate the transactions contemplated by this Agreement on the terms and conditions set forth in this Agreement (as the same may be amended with Buyer’s written consent prior to or at the Auction). For the avoidance of doubt, Buyer shall have no obligation to consummate the transactions contemplated by this Agreement set forth in this Agreement if the transactions under the KFM Agreement fail to close contemporaneously with, or prior to, the Closing.

(m)Seller shall apply the Deposit to the Purchase Price or return the Deposit to Buyer (as applicable) in accordance with the Bidding Procedures Order and Bid Procedures (including the section of the Bid Procedures titled “Return of Good Faith Deposit”). Any instructions provided by Seller to Escrow Agent in respect of the Deposit shall be consistent with the Bidding Procedures Order and Bid Procedures Order, and this Section 9.8(m), in all respects.

9.9Certain Litigation Matters. At the Auction, Buyer notified Seller in writing which of those matters identified on Schedule 7.6 it desired to be Assumed Obligations, and which of those matters it desired to be Excluded Liabilities, and all such Excluded Liabilities shall be Excluded Liabilities for all purposes of this Agreement.

9.10Accounting Services.

From and after the Closing Date until the end of the calendar month in which the sixty (60) day anniversary of the Closing Date occurs, Seller shall continue to perform the services set forth on Exhibit E (the “Accounting Services”) for the purposes of performing the Accounting Services for production month February 2020. Seller shall perform the Accounting Services with the degree of care, skill and diligence with which it has performed similar services for the Properties and the related operations prior to the Closing Date. The quality of Accounting Services provided by Seller is not required to be higher than the quality of the same or similar services that Seller has historically provided with respect to the Properties. In no event shall Seller have any liability to Buyer hereunder in connection with the performance of the Accounting Services except to the extent of the gross negligence or willful misconduct of Seller (including any employee of Seller performing any of the Accounting Services). Between the Original Execution Date and the Auction, the Parties shall cooperate in good faith to agree a fixed cost or other pricing mechanism for the provision of such Accounting Services, which fixed cost or other pricing mechanism is to be based on the estimated direct fully burdened expenses to be incurred with respect to the provision of such Accounting Services. In the event the Parties are unable to agree to such a fixed cost or other pricing mechanism prior to Closing, after Closing, Buyer shall reimburse Seller for all direct fully burdened expenses incurred by Seller in connection with the provision of the Accounting Services; provided that Seller shall inform Buyer when Seller has incurred cumulative direct fully burdened expenses in connection with the performance of the Accounting Services in amounts totaling $250,000, $500,000, $750,000, and $1,000,000, and in no event shall Buyer be obligated to pay Seller more than $1,000,000 for the provision of such Accounting Services. Seller shall use reasonable efforts to make the employees who will provide the Accounting Services hereunder reasonably available to Buyer throughout the Term; provided that Seller will not be obligated to replace any such employee who resigns or otherwise does not continue to provide services to Buyer or is otherwise unavailable due to disability, illness or otherwise, in which case Seller shall use reasonable efforts to continue to provide the applicable Accounting Services. Buyer may at any time, upon one Business Day prior written notice to Seller, terminate all or any portion of the Accounting Services.

ARTICLE XBUYER’S CONDITIONS TO CLOSING

The obligations of Buyer to consummate the transactions provided for herein is subject, at the option of Buyer, to the fulfillment by Seller or written waiver by Buyer, on or prior to the Closing of each of the following conditions:

10.1Representations. The representations and warranties of Seller set forth in Article VII shall be true and correct as of the Closing Date as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties that in the aggregate would not have a Material Adverse Effect.

10.2Performance. Seller shall have performed or complied with all obligations, agreements, and covenants contained in this Agreement and the Sale Order, as to which performance or compliance by Seller is required prior to or at the Closing Date in all material respects.

10.3No Legal Proceedings. No order, injunction or judgment shall have been issued by any Governmental Authority or arbitrator to restrain, prohibit, enjoin or declare illegal the transactions contemplated by this Agreement, and no Law has been promulgated or enacted and is in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated by this Agreement.

10.4Title Defects, Environmental Defects and Casualty Losses. The sum of (a) all Title Defect Amounts with respect to all unwaived and uncured Title Defects asserted by Buyer in good faith in accordance with Section 5.2, net of any Title Benefit Amounts in excess of the Individual Title Defect Threshold in accordance with Section 5.2(e), in each case, as determined by the Parties prior to the Closing (or if not so determined prior to Closing, as determined pursuant to Section 7.7(b)), plus (b) all Remediation Amounts with respect to all unwaived and unremediated Environmental Defects asserted by Buyer in good faith in accordance with Section 6.1 as determined by the Parties prior to Closing (or if not so determined prior to Closing, as determined pursuant to Section 6.1(f)), plus (c) the aggregate amount of all Casualty or Condemnation Losses as determined by the Parties prior to Closing (or if not so determined prior to Closing, as determined by Seller in its reasonable, good faith opinion), plus (d) all reductions to the Purchase Price pursuant to Section 5.4(b) in respect of unobtained Required Consents, plus (e) all reductions to the Purchase Price pursuant to Section 5.4(a) in respect of exercised Preferential Purchase Rights, shall, in the aggregate, be less than ten percent of the unadjusted Purchase Price.

10.5Certificate. An authorized officer of Seller shall execute and deliver (or be ready, willing and able to deliver at Closing) a certificate dated as of the Closing Date certifying on behalf of Seller that the conditions set forth in Section 10.1 and Section 10.2 have been fulfilled by Seller.

10.6Sale Order. The Bankruptcy Court shall have entered the Sale Order and the Sale Order shall be final, binding and non-appealable and in full force and effect.

10.7Closing Deliverables. Seller shall have delivered (or be ready, willing and able to deliver at Closing) to Buyer the documents and other items required to be delivered by Seller under Section 12.3.

10.8Closing of Transactions under KFM Agreement. The transactions under the KFM Agreement shall close contemporaneously with, or prior to, the Closing.

ARTICLE XISELLER’S CONDITIONS TO CLOSING

The obligations of Seller to consummate the transactions provided for herein is subject, at the option of Seller, to the fulfillment by Buyer or waiver by Seller, on or prior to the Closing of each of the following conditions precedent:

11.1Representations. The representations and warranties of Buyer set forth in Article VIII shall be true and correct in all material respects as of the Closing Date (except with respect to the representations and warranties set forth in Section 8.8, Section 8.9 or Section 8.11 which shall be true in all respects) as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties (other than the representations and warranties set forth in Section 8.8, Section 8.9 or Section 8.11) that in the aggregate would not have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement or the Transaction Documents to which it is or will be a Party or perform its obligations hereunder or thereunder.

11.2Performance. Buyer shall have performed or complied with all obligations, agreements, and covenants contained in this Agreement and the Sale Order, as to which performance or compliance by Buyer is required prior to or at the Closing Date in all material respects.

11.3No Legal Proceedings. No order, injunction or judgment shall have been issued by any Governmental Authority or arbitrator to restrain, prohibit, enjoin or declare illegal the transactions contemplated by this Agreement, and no Law has been promulgated or enacted and is in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated by this Agreement.

11.4Title Defects, Environmental Defects and Casualty Losses. The sum of (a) all Title Defect Amounts with respect to all unwaived and uncured Title Defects asserted by Buyer in good faith in accordance with Section 5.2, net of any Title Benefit Amounts in excess of the Individual Title Defect Threshold in accordance with Section 5.2(e), in each case, as determined by the Parties prior to the Closing (or if not so determined prior to Closing, as determined pursuant to Section 5.2(i)), plus (b) all Remediation Amounts with respect to all unwaived and unremediated Environmental Defects asserted by Buyer in good faith in accordance with Section 6.1 as determined by the Parties prior to Closing (or if not so determined prior to Closing, as determined pursuant to Section 6.1(f)), plus (c) the aggregate amount of all Casualty or Condemnation Losses as determined by the Parties prior to Closing (or if not so determined prior to Closing, as determined by Seller in its reasonable, good faith opinion), plus (d) all reductions to the Purchase Price pursuant to Section 5.4(b) in respect of unobtained Required Consents, shall, in the aggregate, be less than ten percent of the unadjusted Purchase Price.

11.5Certificate. An authorized officer of Buyer shall execute and deliver (or be ready, willing and able to deliver at Closing) a certificate dated as of the Closing Date certifying on behalf of Buyer that the conditions set forth in Section 11.1 and Section 11.2 have been fulfilled by Buyer.

11.6Sale Order. The Bankruptcy Court shall have entered the Sale Order and the Sale Order shall be final, binding and non-appealable and in full force and effect.

11.7Closing Deliverables. Buyer shall have delivered (or be ready, willing and able to deliver at Closing) to Seller the documents and other items, including the Adjusted Purchase Price, required to be delivered by Buyer under Section 12.3.

11.8Closing of Transactions under KFM Agreement. The transactions under the KFM Agreement shall close contemporaneously with, or prior to, the Closing.

ARTICLE XIICLOSING

12.1Date of Closing. Subject to the conditions stated in this Agreement, the transfer by Seller to Buyer of the Assets pursuant to this Agreement (the “Closing”) shall occur on February 12, 2020 (the “Target Closing Date”); provided that, if the conditions to Closing in Article X and Article XI have not yet been satisfied or waived by such applicable date, then the Closing shall occur five Business Days after such conditions have been satisfied or waived, or such other date as Buyer and Seller may agree upon in writing. The date of the Closing shall be the “Closing Date.”

12.2Place of Closing. The Closing shall be held at the offices of Latham & Watkins LLP, 811 Main Street, Suite 3700, Houston, Texas 77002, or such other location as Seller may designate in writing.

12.3Closing Obligations. At the Closing, the following documents shall be delivered and the following events shall occur, the execution of each document and the occurrence of each event being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a)Seller and Buyer shall execute, acknowledge and deliver the Instruments of Conveyance, and, in sufficient counterparts, including all information and formatting required to be accepted by the appropriate Governmental Authorities, to be recorded in the applicable counties, covering the Assets;

(b)Seller and Buyer shall execute and deliver assignments, on appropriate forms prepared by Seller and reasonably acceptable to Buyer, of state and federal Leases comprising portions of the Assets, if any, in sufficient counterparts to facilitate filing with the applicable Governmental Authority;

(c)Seller and Buyer shall execute and deliver the Closing Settlement Statement;

(d)Buyer shall deliver to Seller, to the account(s) designated in the Closing Settlement Statement, by direct bank or wire transfer in same day funds, (i) if the amount of the Closing Escrow is less than or equal to the amount of the Deposit, the Adjusted Purchase Price, less the Deposit, or (ii) if the amount of the Closing Escrow is greater than the amount of the Deposit, the Adjusted Purchase Price, less the Closing Escrow;

(e)Seller and Buyer shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse the Deposit to Seller, less the amount of the Closing Escrow, provided that if the amount of the Closing Escrow is greater than or equal to the amount of the Deposit, there shall be no such disbursement to Seller at Closing;

(f)In the event the amount of the Closing Escrow is greater than the amount of the Deposit, Buyer shall deliver to the Escrow Account, by direct bank or wire transfer in same day funds, the amount obtained by subtracting the amount of the Deposit from the amount of the Closing Escrow;

(g)Seller shall deliver an executed statement described in Treasury Regulation §1.1445-2(b)(2) certifying that Seller is neither a disregarded entity nor a foreign person within the meaning of Section 1445(f)(3) of the Code and the Treasury Regulations promulgated thereunder;

(h)Seller shall prepare and deliver validly executed transfers of Form 1073’s designating Buyer (or, if applicable, Buyer’s operating Affiliate) as operator of the Wells operated by Seller or any Affiliate of Seller with the OCC;

(i)Seller shall deliver on forms prepared by Seller with reasonable assistance from Buyer all transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Buyer of proceeds attributable to production from the Assets from and after the Effective Time, for delivery by Buyer to such purchasers of production;

(j)Seller shall deliver a copy of the Sale Order entered with the Bankruptcy Court;

(k)Seller shall deliver duly-executed, recordable releases (in sufficient counterparts to facilitate recording in the applicable counties where the Assets are located) in form reasonably acceptable to Buyer of any mortgages or security interests over the Assets, in each case, securing indebtedness for borrowed money of a Seller Party or any of their respective Affiliates; and

(l)Seller and Buyer shall execute and deliver the Escrow Agreement; and

(m)Seller and Buyer shall execute and deliver any other agreements, instruments and documents that are required by other terms of this Agreement to be executed or delivered at or prior to the Closing.

12.4Records. In addition to the obligations set forth under Section 12.3 above, on the Closing Date, Seller shall make available to Buyer for pick-up (or will deliver electronically, if applicable), the Records to which Buyer is entitled pursuant to the terms of this Agreement, including all electronic Records.

12.5FCC Filings. Seller and Buyer shall prepare, as soon as is practical following the Closing, any necessary filings in connection with the transactions contemplated by this Agreement that may be required to be filed by the Parties or any Affiliate thereof with the Federal Communications Commission with respect to transfer of the Assigned FCC Licenses. Buyer shall pay all amounts payable to the Federal Communications Commission or other Governmental Authority with respect to the transfer of the Assigned FCC Licenses under this Agreement (provided that each Party shall be responsible for its out of pocket expenses incurred in connection with the preparation of any such filings). Seller and Buyer shall promptly furnish each other with copies of any notices, correspondence or other written communication from the FCC, shall promptly make any appropriate or necessary subsequent or supplemental filings and shall cooperate in the preparation of such filings as is reasonably necessary and appropriate. In addition, at or prior to, or as soon as practical after, the Closing, Buyer shall deliver evidence to Seller of its Federal Registry Number with respect to the Assigned FCC Licenses and its designation of an applicable contact person with respect to the Assigned FCC Licenses. Promptly following Closing, Buyer and Seller shall execute and deliver the forms and documents required by the applicable Governmental Authority to transfer the Assigned FCC Licenses to Buyer.

ARTICLE XIIIASSUMPTION; INDEMNIFICATION; SURVIVAL

13.1Assumed Obligations; Excluded Obligations.

(a)Assumed Obligations. Without prejudice to the Purchase Price adjustments described in Section 3.3, Buyer shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) the following obligations and Liabilities (and only the following obligations and Liabilities) (collectively, the “Assumed Obligations”):

(i)all obligations related to the payment of Burdens and other interests, owners’ revenues or proceeds attributable to sales of Hydrocarbons (including Suspense Funds to the extent attributable to the Assets, including those Burdens associated with Suspense Funds for which there was a downward adjustment to the Purchase Price), in each case, insofar as the same are attributable to periods, and Hydrocarbons produced and marketed with respect to the Assets, at or after the Effective Time;

(ii)all of Seller’s plugging and abandonment obligations relating to the Properties, whether arising prior to, at or after the Effective Time;

(iii)all of Seller’s other Liabilities (including Environmental Liabilities) under the Properties (in addition to those described in Section 13.1(a)(ii) above) that are attached to or run with the Assets (i.e., excluding personal Liabilities of Seller or its Affiliates that are not attached to the Assets) to the extent such Liabilities are attributable to periods at or after the Effective Time;

(iv)all of Seller’s obligations or Liabilities under the Assigned Contracts to the extent attributable to periods at or after the Effective Time;

(v)all obligations with respect to the Cure Costs required to be paid by Buyer in accordance with Section 2.4;

(vi)all Operating Expenses arising from, related to or associated with the Assets, in each case, to the extent attributable to periods at or after the Effective Time;

(vii)all obligations and amounts owed to the Continuing Employees relating to the employment of such individuals by Buyer or one of Buyer’s Affiliates from and after the Closing Date (but excluding any Liabilities or obligations owing under any Benefit Plans), as well as any obligations required under COBRA with respect to Business Employees that are not Continuing Employees (provided that Buyer shall not be responsible for any premiums that any such Business Employees are obligated to pay in order to obtain any health insurance or other benefits under COBRA);

(viii)All Asset Taxes and Transfer Taxes that are the responsibility of Buyer pursuant to Section 16.2;

(ix)any claim, action, order, proceeding or other matter set forth on Schedule 7.6 that Buyer elects to assume pursuant to Section 9.9; and

(x)Those obligations set forth on Schedule 13.1.

The assumption by Buyer of the Assumed Obligations shall not, in any way, enlarge the rights of any Third Parties relating thereto.

(b)Excluded Liabilities. Notwithstanding any provision in this Agreement to the contrary, Buyer shall not assume and shall not be obligated to assume or be obligated to pay, perform or otherwise discharge any Liability or obligation of Seller not associated with the Assets, and Seller shall be solely and exclusively liable with respect to all obligations and Liabilities associated with the Assets, other than the Assumed Obligations (such Liabilities other than Assumed Obligations, collectively, the “Excluded Liabilities”). For purposes of clarity, and without limitation of the generality of the foregoing, the Excluded Liabilities shall include, without limitation, each of the following Liabilities of Seller or any Affiliate of Seller, other than the Assumed Obligations:

(i)all indebtedness for borrowed money of Seller;

(ii)all guarantees of Third Party obligations by Seller and reimbursement obligations to guarantors of Seller’s obligations or under letters of credit;

(iii)all accrued expenses and accounts payables;

(iv)all Seller Taxes;

(v)any claim, action, order, proceeding or other matter set forth on Schedule 7.6 that Buyer elected not to assume pursuant to Section 9.9;

(vi)all Liabilities of Seller to any owner or former owner of capital stock or warrants, or holder of indebtedness for borrowed money;

(vii)any Liabilities related to the Excluded Assets;

(viii)except to the extent specifically assumed by Buyer pursuant to Article XV or Section 13.1(a)(vii) of this Agreement, all Liabilities at any time relating to or arising out of the employment or service with or termination of employment or service from Seller or any of its Affiliates of any Person (including any Continuing Employees), including any severance or incentive compensation, bonus payments, retention payments, change of control payments or similar payments, whether or not such Liabilities, obligations or commitments arise or vest (whether fully or partially) as a result of the transactions contemplated by this Agreement and whether or not immediately due and payable upon the consummation of the transactions contemplated by this Agreement;

(ix)obligations under any Hedge Contracts entered into by Seller;

(x)all Liabilities and any obligations relating to or at any time arising under, with respect to, or in connection with any Benefit Plans or any other compensation or benefit plan, program, policy, agreement or arrangement of any kind (including all assets, trusts, insurance policies and administration service contracts related thereto) that at any time is or was maintained, sponsored, contributed to or required to be contributed to by Seller or any of its Affiliates or under or with respect to which Seller or any of its Affiliates has (or has had) any Liability, including on account of an ERISA Affiliate or on account of Buyer or any of its Affiliates being deemed successor due to the operation of the Assets;

(xi)Liabilities incurred by Seller or any of its Affiliates for brokerage or finders’ fees or agents’ commissions or other similar payments in connection with this Agreement, the other Transaction Documents or the transactions contemplated hereby;

(xii)all Liabilities relating to the accounting for, failure to pay or the incorrect payment of any Burdens and other interests, owners’ revenues or proceeds attributable to sales of Hydrocarbons (including Suspense Funds to the extent attributable to the Assets, other than with respect to those Suspense Funds for which there was a downward adjustment to the Purchase Price), insofar as the same are attributable to periods and Hydrocarbons produced and marketed with respect to the Assets prior to the Effective Time;

(xiii)civil or criminal fines or penalties relating to violations occurring prior to the Closing Date of any Environmental Law with respect to the Properties or Assets or the operation thereof;

(xiv)the off-site transportation, disposal or arrangement therefor of any Hazardous Materials off the premises of the Properties or Assets prior to the Closing;

(xv)all unpaid Operating Expenses attributable to periods prior to the Effective Time that are not taken into account pursuant to Section 3.3;

(xvi)all Liabilities at any time arising out of, or relating to, the WARN Act or any similar state Law as it relates to Business Employees terminated by Seller or its Affiliates; and

(xvii)all Liabilities at any time arising out of, or relating to, any CBA.

13.2Indemnities of Buyer. From and after the Closing, subject to the provisions and limitations set forth in Sections 13.3 through 13.10 (inclusive), Buyer shall assume, be responsible for, shall pay on a current basis, and hereby agrees to release, defend, indemnify and hold harmless Seller and its Affiliates, and all of its and their respective stockholders, partners, members, directors, officers, managers, employees, attorneys, agents and representatives (collectively, “Seller Indemnified Parties”) from and against any and all Liabilities, whether or not relating to Third Party Claims or incurred, directly or indirectly, in the investigation or defense of any of the same or in asserting, presenting or enforcing any of their respective rights hereunder arising from, based upon, related to or associated with:

(a)any breach by Buyer of its representations or warranties contained in Article VIII or in any certificate furnished by or on behalf of Buyer in connection with this Agreement;

(b)any breach by Buyer of its covenants, obligations or agreements under this Agreement (including, for the avoidance of doubt, any other indemnity obligations of Buyer and its Affiliates contained in this Agreement, including pursuant to Section 4.1(d));

(c)the Assumed Obligations; and

(d)any other indemnity obligations of Buyer and its Affiliates expressly set forth in this Agreement.

13.3Express Negligence. THE INDEMNIFICATION, RELEASE, ASSUMED OBLIGATIONS, WAIVER AND LIMITATION OF LIABILITY PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY; PROVIDED, HOWEVER, SUCH PROVISIONS SHALL NOT APPLY TO LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES TO THE EXTENT ARISING OUT OF THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF THE SELLER INDEMNIFIED PARTIES OR BUYER INDEMNIFIED PARTIES, AS APPLICABLE. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS CONSPICUOUS.

13.4Exclusive Remedy. Notwithstanding anything to the contrary contained in this Agreement, except as provided in Section 9.5, from and after Closing, Section 4.1(d),Section 9.2 and Section 13.2(a) shall contain Seller’s exclusive remedies against Buyer with respect to the transactions contemplated by this Agreement, including breaches of the representations, warranties, covenants, obligations and agreements of the Parties contained in this Agreement or the affirmations of such representations, warranties, covenants, obligations and agreements contained in the certificate(s) delivered Buyer at Closing pursuant to Section 11.5. Except as set forth in Section 3.4(b), Section 3.5 and for the limited special warranty of Defensible Title contained in the Instruments of Conveyance, Buyer releases, remises and forever discharges Seller and all Seller Indemnified Parties from any and all Liabilities in Law or in equity, known or unknown, which any of the Buyer Parties might now or subsequently may have, based on, relating to or arising out of this Agreement, the ownership, use or operation of the Assets prior to the Closing, or the condition, quality, status or nature of the Assets prior to the Closing, including rights to contribution under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, breaches of statutory or implied warranties, nuisance or other tort actions, rights to punitive damages, common Law rights of contribution, and rights under insurance maintained by Seller or any of its Affiliates.

13.5Indemnification Procedures. All claims for indemnification under Section 4.1(d), Section 9.2 and Section 13.2 shall be asserted and resolved as follows:

(a)For purposes of this Agreement, the term “Indemnifying Party” means Buyer, and the term “Indemnified Party” when used in connection with particular Liabilities shall mean Seller or the Person(s) having the right to be indemnified with respect to such Liabilities by another Party pursuant to Section 4.1(d), Section 9.2 or Section 13.2.

(b)To make claim for indemnification under Section 4.1(d), Section 9.2, Section 13.2 or Section 13.3, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 13.5, including the specific details of and specific basis under this Agreement for its claim (the “Claim Notice”). In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Party (a “Third PartyClaim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has Knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section 13.5(b) shall not relieve the Indemnifying Party of its obligations under Section 4.1(d), Section 9.2, Section 13.2 or Section 13.3 (as applicable) except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Third Party Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant, obligations or agreement, the Claim Notice shall specify the representation, warranty, covenant, obligation or agreement that was inaccurate or breached.

(c)In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Third Party Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such 30 day period, at the expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party. Failure of an Indemnifying Party to admit its liability to defend an Indemnified Party within such 30 day period shall be deemed a denial of liability to so defend such Indemnified Party.

(d)If the Indemnifying Party admits its liability to defend the Indemnified Party against a Third Party Claim, it shall have the right and obligation to diligently defend, at its sole cost and expense, such Third Party Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified Party shall cooperate in contesting any Third Party Claim that the Indemnifying Party elects to contest. The Indemnified Party may participate in, at its own expense, but subject to the Indemnifying Party’s full control of, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 13.5(d); provided, however, that the Indemnified Party shall not be required to bring any counterclaim or cross complaint against any Person. An Indemnifying Party shall not, without the prior written consent of the Indemnified Party, (i) settle any Third Party Claim or consent to the entry of any judgment or order with respect thereto which does not result in a final resolution of the Indemnified Party’s Liability in respect of such Third Party Claim (including, in the case of a settlement, an unconditional written release of the Indemnified Party from all Liability in respect of such Third Party Claim), or (ii) settle any Third Party Claim or consent to the entry of any judgment or order with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(e)If the Indemnifying Party does not admit its liability or admits its liability to defend the Indemnified Party against the Third Party Claim, but fails to diligently prosecute or settle such Third Party Claim, then the Indemnified Party shall have the right to defend against the Third Party Claim at the sole cost and expense of the Indemnifying Party, with counsel of its choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its liability to defend the Indemnified Party against the Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement, unless the proposed settlement is solely for money damages and results in a final resolution, and the Indemnifying Party shall have the option for ten days following receipt of such notice to (i) admit in writing its liability to indemnify the Indemnified Party from and against the liability and consent to such settlement, (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement, or (iii) deny liability. Any failure to respond to such notice by the Indemnified Party within such ten day-period shall be deemed to be an election under subsection (i) above.

(f)In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to (i) cure the Liabilities complained of, (ii) admit its liability for such Liability or (iii) dispute the claim for such Liabilities. If the Indemnifying Party does not notify the Indemnified Party within such 30 day period that it has cured the Liabilities or that it disputes the claim for such Liabilities, the Indemnifying Party shall be deemed to have disputed the claim for such Liabilities.

13.6Survival.

(a)The representations and warranties of Seller in Article VII and in the certificate delivered pursuant to Section 10.5 shall terminate at the Closing. All covenants, obligations and agreements of Seller (or, if applicable AMR) in this Agreement (i) that are required to be performed at or prior to Closing shall terminate at Closing and (ii) that cannot be performed until after the Closing shall survive until fully performed. The limited special warranty of Defensible Title in the Instruments of Conveyance shall survive Closing for six months.

(b)Subject to Section 13.6(a) and except as set forth in Section 13.6(c), the remainder of this Agreement shall survive the Closing without time limit. Representations, warranties, covenants, obligations and agreements shall be of no further force and effect after the date of their expiration as set forth in Section 13.6(a) or Section 13.6(c); provided that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant, obligation or agreement prior to its expiration date.

(c)The indemnities in Section 13.2(a) and Section 13.2(b) shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification. Buyer’s indemnities set forth in Section 13.2(c), and Section 13.2(d) shall survive the Closing without time limit. Notwithstanding the foregoing, there shall be no termination of any bona fide claim asserted pursuant to the indemnities in Section 13.2 prior to the date of termination for such indemnity.

13.7Non-Compensatory Damages. WITHOUT LIMITING SECTION 9.5, NOTWITHSTANDING ANYTHING CONTAINED IN THIS AGREEMENT TO THE CONTRARY, NONE OF THE BUYER PARTIES NOR THE SELLER INDEMNIFIED PARTIES SHALL BE ENTITLED TO RECOVER FROM THE OTHER PARTY OR SUCH OTHER PARTY’S AFFILIATES ANY INDIRECT, CONSEQUENTIAL, SPECIAL, PUNITIVE, INCIDENTAL, SPECULATIVE OR EXEMPLARY DAMAGES OR DAMAGES FOR LOST PROFITS OR LOSS OF BUSINESS OPPORTUNITY OF ANY KIND ARISING UNDER, RELATED TO OR IN CONNECTION WITH THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY, EXCEPT TO THE EXTENT ANY SUCH PERSON SUFFERS SUCH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEYS’ FEES INCURRED IN CONNECTION WITH THE DEFENSE OF SUCH DAMAGES) TO A THIRD PARTY, WHICH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEYS’ FEES INCURRED IN CONNECTION WITH THE DEFENSE OF SUCH DAMAGES) SHALL NOT BE EXCLUDED BY THIS PROVISION AS TO RECOVERY HEREUNDER. SUBJECT TO THE PRECEDING SENTENCE AND SECTION 9.5, AND NOTWITHSTANDING ANYTHING CONTAINED IN THIS AGREEMENT TO THE CONTRARY, EACH OF SELLER, ON BEHALF OF ITSELF AND THE SELLER INDEMNIFIED PARTIES, AND BUYER, ON BEHALF OF ITSELF AND THE BUYER PARTIES, WAIVES ANY RIGHT TO RECOVER INDIRECT, CONSEQUENTIAL, SPECIAL, PUNITIVE, INCIDENTAL, SPECULATIVE AND EXEMPLARY DAMAGES, INCLUDING DAMAGES FOR LOST PROFITS OR LOSS OF BUSINESS OPPORTUNITY OF ANY KIND, ARISING IN CONNECTION WITH OR WITH RESPECT TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY. THIS SECTION 13.7 SHALL NOT RESTRICT ANY PARTY’S RIGHT TO OBTAIN SPECIFIC PERFORMANCE OR ANY INJUNCTION IN ACCORDANCE WITH THE TERMS AND CONDITIONS OF THIS AGREEMENT.

13.8Waiver or Right to Rescission. Seller and Buyer acknowledge that, subject to any rights the Parties may have hereunder to seek and obtain specific performance or other express injunctive remedies, following Closing, the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant, obligation or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated by this Agreement. As such, Buyer and Seller waive any right to rescind this Agreement or any of the transactions contemplated hereby.

13.9Insurance. The amount of any Liabilities for which any Indemnified Party is entitled to indemnification under this Agreement or in connection with or with respect to the transactions contemplated by this Agreement shall be reduced by any corresponding insurance proceeds, from insurance policies carried by such Indemnified Party or its Affiliates, that are actually realized by such Indemnified Party from Third Party insurers with respect to such Liabilities.

13.10Waiver of Consumer Rights. The Parties each can and do expressly waive those provisions, if any, of the Texas Deceptive Trade Practices-Consumer Protection Act, Texas Business and Commerce Code Article 17.41 et seq. (and any similar Law that gives consumers special rights and protection, including the Oklahoma Consumer Protection Act, Okla. Stat. tit. 15, §§ 751 through 763). Buyer acknowledges, represents and warrants to Seller that Buyer is purchasing the Assets for commercial or business use; that Buyer has Knowledge and experience in financial and business matters that enable Buyer to evaluate the merits and risks of a transaction such as this; and that Buyer is not in a significantly disparate bargaining position with Seller. Further, Buyer expressly recognizes that the price for which Seller has agreed to perform its obligations under this Agreement has been predicated upon the inapplicability of Laws similar to those described in subsections (a) and (b) above, and Buyer further recognizes that Seller, in determining to proceed with the entering into this Agreement, has expressly relied on this waiver and the inapplicability of such Laws. It is not the intent of the Parties to waive, and the Parties shall not waive, any applicable provision thereof that is prohibited by Law from being waived.

ARTICLE XIVTERMINATION, DEFAULT AND REMEDIES

14.1Right of Termination. This Agreement and the transactions contemplated herein may be terminated at any time at or prior to Closing:

(a)by Seller, at Seller’s option, if any of the conditions set forth in Section 11.1, Section 11.2, Section 11.5 or Section 11.7 has not been satisfied by Buyer, or waived by Seller, by the Outside Termination Date and, solely to the extent such condition is capable of being cured, following written notice thereof from Seller to Buyer specifying the reason such condition is unsatisfied, remain uncured for a period of ten Business Days after Buyer’s receipt of such written notice from Seller;

(b)by Buyer, at Buyer’s option, if any of the conditions set forth in Section 10.1, Section 10.2, Section 10.5 or Section 10.7 has not been satisfied by Seller, or waived by Buyer, by the Outside Termination Date and, solely to the extent such condition is capable of being cured, following written notice thereof from Buyer to Seller specifying the reason such condition is unsatisfied, remain uncured for a period of ten Business Days after Seller’s receipt of such written notice from Buyer;

(c)by either Party if the conditions set forth in Section 10.3, Section 10.4, Section 10.6 or Section 10.8, in the case of Buyer, or Section 11.3, Section 11.4,Section 11.6 or Section 11.8, in the case of Seller, have not been satisfied, or waived, by the applicable Party, by the Outside Termination Date;

(d)upon the mutual written agreement of the Parties;

(e)by either Party, at such Party’s option, at any time following the Outside Termination Date;

(f)by Buyer, if:

(i)Buyer is not the Successful Bidder or the Backup Bidder for the Assets at the Auction and Seller does not close the transactions contemplated by this Agreement with Buyer by the Outside Termination Date;

(ii)there shall be in effect a Final Order restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated hereby;

(iii)there is a termination of the Cash Collateral Order;

(iv)[Reserved];

(v)the Bankruptcy Court has not entered the Sale Order by January 22, 2020;

(vi)Seller withdraws or seeks authority to withdraw the Sale Order for the Assets at any time after the filing thereof (it being agreed and understood by Buyer and Seller that the filing of a revised or amended form of Sale Order shall not constitute a withdrawal of the Sale Order), or announces any standalone plan of reorganization or liquidation, in each case with respect to the Assets other than as set forth herein;

(g)by Buyer or Seller, if:

(i)Seller (A) enters into a definitive agreement regarding a Highest or Best Proposal for the Assets and Buyer is not the Backup Bidder, or (B) consummates the transactions under a Highest or Best Proposal for the Assets;

(ii)Seller enters into (or provides written notice to Buyer of its intent to enter into) one or more agreements to sell, transfer or otherwise dispose of any material portion of the Assets having a fair market value in excess of $70,000,000 in a transaction or series of transactions other than in the ordinary course of business with one or more Persons other than Buyer or the Successful Bidder at the Auction;

(iii)the Bankruptcy Court enters an order dismissing, or converting to a case under chapter 7 of the Bankruptcy Code, the Chapter 11 Case, where such order was not requested, encouraged or supported by Seller and Buyer; or

(h)by Seller, at any time after 5:00 p.m. (Central Prevailing Time) on January 20, 2020 if, at the time of such termination, Buyer has failed to fund the Supplemental Deposit into the Escrow Account;

provided, however, that no Party shall have the right to terminate this Agreement pursuant to clause (a), (b), (c), (e) or (f) above if such terminating Party is at such time in material breach of any provision of this Agreement. Buyer shall have no right to terminate this Agreement pursuant to clause (b) above if Buyer’s Closing condition in Section 10.4 is not satisfied as of the Outside Termination Date but the satisfaction of the Closing condition in Section 10.4 is contingent upon the resolution of any Title Dispute or Environmental Dispute that has not been resolved as of the Outside Termination Date (and if upon the final resolution of such Title Disputes and Environmental Disputes, such Buyer’s Closing conditions in Article X are satisfied, the Closing shall occur within five Business Days after such occurrence).

14.2Effect of Termination.

(a)If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 14.1 hereof, then, except for the provisions of Section 1.2, 4.1(d) through 4.1(f), Section 4.2, Section 4.3, Section 9.2, Section 9.5, Section 13.4, Section 13.5, Section 13.7, this Section 14.2,Section 14.3, Article XVI (other than Section 16.2(b) through (e), Section 16.3, Section 16.8, Section 16.9 and Section 16.17) and such of the defined terms in Section 1.1 necessary to give context to the surviving provisions, this Agreement shall forthwith become void and the Parties shall have no liability or obligation hereunder.

(b)If Seller is entitled to terminate this Agreement pursuant to Section 14.1(a) or Section 14.1(e) because of (i) the Willful Breach by Buyer of this Agreement or (ii) the failure of Buyer to close in the instance where, as of the Outside Termination Date, (A) all of the conditions in Article X (excluding conditions that, by their terms, cannot be satisfied until the Closing) have been satisfied by Seller (or waived by Buyer), (B) Seller is ready, willing and able to perform its obligations under Section 12.3, and (C) Buyer nevertheless elects not to close, then, in either such event, Seller shall be entitled to, at its option (1) obtain specific performance in lieu of termination or (2) terminate this Agreement pursuant to Section 14.1(a) or Section 14.1(e), as applicable, and be entitled to retain the Depositas liquidated damages for such termination (the Parties agree that the foregoing liquidated damages are reasonable considering all of the circumstances existing as of the Original Execution Date, shall not serve as a penalty and constitute the Parties’ good faith estimate of the actual damages reasonably expected to result from such termination of this Agreement by Seller). Seller agrees that, to the fullest extent permitted by Law, Seller’s rights set forth in the preceding sentence shall be the sole and exclusive remedies of Seller (other than with respect to those provisions that survive termination pursuant to Section 14.2(a)) if the Closing does not occur as a result of the termination of this Agreement pursuant to Section 14.1(a) or Section 14.1(e), as applicable. Nothing herein shall be construed to prohibit Seller from first seeking specific performance, but thereafter terminating this Agreement and retaining the Deposit as liquidated damages in lieu of fully prosecuting its claim for specific performance. Each Party acknowledges that the remedies at Law of Seller for a breach or threatened breach of this Agreement by Buyer as contemplated pursuant to this Section 14.2(b) may be inadequate and, in recognition of this fact, Seller, without posting any bond or the necessity or proving the inadequacy as a remedy of monetary damages, and in addition to all other remedies that may be available, shall be entitled to obtain equitable relief in the form of specific performance, a temporary restraining order, a temporary or permanent injunction or any other equitable remedy that may then be available.

(c)If this Agreement is terminated by Buyer pursuant to Section 14.1(b) or Section 14.1(e) because of (i) the Willful Breach by Seller of this Agreement, or (ii) the failure of Seller to close in the instance where, as of the Outside Termination Date, (A) all of the conditions in Article XI (excluding conditions that, by their terms, cannot be satisfied until the Closing) have been satisfied by Buyer (or waived by Seller), (B) Buyer is ready, willing and able to perform its obligations under Section 12.3, and (C) Seller nevertheless elects not to close, then, in either such event, Buyer shall be entitled to terminate this Agreement pursuant to Section 14.1(b) or Section 14.1(e), as applicable, and be entitled to return of the Deposit and Buyer shall be entitled to seek actual, direct damages (subject always to Section 13.7) up to an aggregate amount not greater than an amount equal to the Deposit amount, which claim shall be entitled to priority as set forth in Paragraph 30 of the Sale Order. Buyer agrees that, to the fullest extent permitted by Law, Buyer’s rights set forth in the preceding sentence shall be its sole and exclusive remedies of Buyer (other than with respect to those provisions that survive termination pursuant to Section 14.2(a))if the Closing does not occur as a result of the termination of this Agreement pursuant to Section 14.1(b) or Section 14.1(e), as applicable.

(d)[Reserved.]

(e)If this Agreement is terminated by Seller or by Buyer pursuant to Section 14.1 (other than under the circumstances described in Section 14.2(b)), within two Business Days after such termination, the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse the Deposit to Buyer; provided, however, that if (i) this Agreement is terminated by Seller due to a failure of the condition in Section 11.8 to be met and (ii) KFM Sellers are entitled to retain the Deposit (as defined in the KFM Agreement), then the Parties shall execute and deliver a joint instruction to Escrow Agent requiring Escrow Agent to disburse the Deposit to Seller.

(f)Subject to the foregoing, upon the termination of this Agreement neither Party shall have any other liability or obligation hereunder, and Seller shall be free to immediately enjoy all rights of ownership of the Assets and to sell, transfer, encumber or otherwise dispose of the Assets to any Person without any restriction under this Agreement.

14.3Return of Documentation and Confidentiality. Upon termination of this Agreement, Buyer shall return or destroy, at Buyer’s sole expense, all title, engineering, geological and geophysical data, environmental assessments or reports, maps and other data and information (including all copies, extracts and other reproductions, in whole or in part) furnished by Seller or any of its Affiliates or representatives to Buyer or any of the Buyer Representatives or prepared by or on behalf of Buyer in connection with its due diligence investigation of the Assets, in each case, in accordance with the Confidentiality Agreement and the terms of this Agreement, and an officer of Buyer shall certify same to Seller in writing. Any oral information will continue to be subject to the terms of the Confidentiality Agreement notwithstanding the termination of this Agreement.

ARTICLE XVEMPLOYEES

15.1Business Employees. On January 6, 2020, Seller provided Buyer with a list containing the name, position, exempt or non-exempt status and location of those current Business Employees, whether or not actively employed (e.g., including employees on vacation and leave of absence, including maternity, family and medical leave, sick, military (whether qualified or otherwise) or short-term disability leave), and the base salary or hourly wage rate and any target annual incentive applicable to each such Business Employee, and Seller shall update the list as necessary periodically prior to the Closing Date, including within five Business Days at Buyer’s request, to reflect new hires, leaves of absence and employment terminations. Buyer shall, in its sole discretion, have the option, but not the obligation, to offer employment as of the Closing Date to such Business Employees as it determines (the “Offered Employees”) on terms and conditions to be determined in Buyer’s sole discretion. Not later than ten Business Days prior to the Closing Date, Buyer shall provide Seller with a list of the material terms (including compensation details, position and location of employment) of each such offer made to each Business Employee. Within five Business Days after the Original Execution Date and until the Closing Date, Seller shall use its best efforts to provide Buyer reasonable access to the Business Employees for the sole purpose of interviewing such Business Employees and discussing employment with Buyer. Buyer may directly communicate any offer of employment to a Business Employee; provided, however, that Buyer will notify Seller prior to contacting any such Business Employee. Each Offered Employee who accepts Buyer’s offer of employment and actually commences employment with Buyer shall be referred to as a “Continuing Employee”. Prior to the Closing Date, Seller shall waive, effective as of the Closing Date, any restrictions otherwise applicable to a Continuing Employee pursuant to any agreement or other arrangement between Seller or any of its Affiliates and such Continuing Employee, which would restrict or otherwise prevent such Continuing Employee from accepting or commencing employment with Buyer. For the avoidance of doubt, Seller and Buyer are not, and do not intend to be, joint employers at any time, and nothing herein may be construed as creating a joint employer relationship between Seller and Buyer.

15.2Employee Matters

(a)Following the Closing Date, in the period required by applicable Law, Seller shall pay to each Continuing Employee any accrued but unused vacation or other paid-time off arising under any Benefit Plan that is legally required to be paid. Seller shall further be responsible as required by Law for all accrued but unpaid time-off for each employee that is not a Continuing Employee.

(b)Following Closing, Buyer agrees and shall be responsible for providing continuation coverage as required by COBRA, under a group health plan maintained by Buyer to the Continuing Employees.

(c)None of the Buyer or any of its Affiliates shall adopt nor become a sponsoring employer of, nor have any obligations, duties or Liabilities under or with respect to any of the Benefit Plans. Effective as of the Closing, Seller shall take all necessary actions to provide for full vesting of all amounts credited to the accounts of each Continuing Employee under any Benefit Plan that is intended to be “qualified” under Section 401(a) of the Code or a nonqualified retirement or deferred compensation plan.

(d)During the period prior to the Closing Date, Seller shall use commercially reasonable efforts to make individual natural person independent contractors related to the Assets and directly engaged by Seller available to Buyer for the purpose of allowing Buyer to interview each such contractor and determine the nature and extent of each such Person’s continuation with Buyer, if any. Seller shall provide to Buyer contact information for Third Party service providers providing contingent personnel relating to the Assets and reasonably cooperate in identifying such contingent work force to the extent requested by Buyer.

(e)The provisions of this Article XV are solely for the benefit of the respective parties to this Agreement and nothing in this Article XV or elsewhere in this Agreement, express or implied, shall create any Third Party beneficiary or other rights or confer upon any employee, Continuing Employee, or legal representative or beneficiary or dependent thereof, or any other Person, any rights or remedies, including any right to employment or continued employment for any specified period, or compensation or benefits of any nature or kind whatsoever. Nothing in this Agreement is intended as an amendment, modification or waiver of the provisions of any benefit or compensation plan, program, policy, agreement, arrangement or contract (including any Benefit Plan), or shall prohibit or limit the ability of Buyer or any of its Affiliates to amend, modify or terminate any benefit or compensation plan, program, policy, agreement, arrangement or contract at any time assumed, established, sponsored or maintained by Buyer or any of its Affiliates.

ARTICLE XVIMISCELLANEOUS

16.1Exhibits and Schedules. All of the Exhibits and Schedules referred to in this Agreement constitute a part of this Agreement. Each Party to this Agreement and its counsel has received a complete set of Exhibits and Schedules prior to and as of the execution of this Agreement.

16.2Expenses and Taxes.

(a)Except as otherwise specifically provided, all fees, costs and expenses incurred by the Parties in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including legal and accounting fees, costs and expenses.

(b)All Transfer Taxes and all required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to the Assets to Buyer shall be borne by Buyer. The Parties shall cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such Transfer Taxes.

(c)All Taxes that are real property Taxes, ad valorem Taxes, personal property Taxes and similar obligations attributable to the Assets (the “Property Taxes”) with respect to the Tax period in which the Effective Time occurs or estimate(s) thereof shall be apportioned as of the Effective Time between Seller and Buyer. Such Property Taxes shall be apportioned as of the Effective Time between Seller and Buyer and included in the Final Settlement Statement. To the extent the actual amount of any Property Taxes described in this Section 16.2(c) is not determinable at the time of the Final Settlement Statement, Buyer and Seller shall utilize the most recent information available in estimating the amount of such Property Taxes for purposes of the Final Settlement Statement. For purposes of the foregoing, in each case, the Property Taxes shall be allocated pro rata per day between the period immediately prior to the Effective Time and the period beginning on the Effective Time, with the portion of Property Taxes attributable to the period immediately prior to the Effective Time being allocated to Seller, and the portion of the Property Taxes attributable to the period beginning on the Effective Time being allocated to Buyer. Seller shall pay or cause to be paid to the taxing authorities all Asset Taxes due prior to the Closing Date. Buyer shall pay or cause to be paid to the taxing authorities all Property Taxes due after the Closing relating to the Tax period in which the Effective Time occurs without thereby becoming entitled to any additional payment from Seller other than as required by Article III and neither party shall be liable to make any additional payment to the other party in the event an estimate of such Property Taxes used in arriving at the Final Settlement Statement varies from the actual amount thereof.

(d) All Taxes attributable to the Assets that are based upon or measured by the operation of the Assets, the production of Hydrocarbons therefrom or the receipt of proceeds therefrom including severance, production, sales, use, excise and similar Taxes, but excluding, for the avoidance of doubt, income, capital gains and franchise Taxes, Property Taxes and Transfer Taxes (the “Production Taxes”) shall be apportioned between Seller and Buyer as of the Effective Time as if the Tax period ended immediately prior to the Effective Time, with the portion of Production Taxes attributable to the period ending immediately prior to the Effective Time being allocated to Seller, and the portion of the Production Taxes attributable to the period beginning on the Effective Time being allocated to Buyer. To the extent the actual amount of any Production Taxes described in this Section 16.2(d) is not determinable at the time of the Final Settlement Statement, Buyer and Seller shall utilize the most recent information available in estimating the amount of such Production Taxes for purposes of the Final Settlement Statement. Seller shall, in accordance with applicable laws and regulations, pay or withhold or cause to be paid or withheld all such Taxes that have accrued with respect to production prior to Closing and shall file all statements, returns, and documents incident thereto. Buyer shall pay or cause to be paid all such Taxes that accrue with respect to production from Closing onward and shall file all statements, returns, and documents incident thereto. For Tax periods in which the Effective Time occurs, Seller agrees to forward to Buyer copies of any Production Tax reports and returns received by Seller after Closing and to provide Buyer with any information Seller has that is necessary for Buyer to file any required Production Tax reports and returns related to the Assets, which Production Tax returns and reports Buyer agrees to file, and which Production Taxes Buyer agrees to pay or cause to be paid to the extent due after the Closing Date without thereby becoming entitled to any additional payment from Seller other than as required by Article III.

(e)Buyer and Seller agree to furnish or cause to be furnished to the other, upon request, as promptly as practicable, such information and assistance relating to the Assets, including access to books and Records, as is reasonably necessary for the filing of all Tax Returns by Buyer or Seller, the making of any election relating to Taxes, the preparation for any audit by any taxing authority and the prosecution or defense of any claim, suit or proceeding relating to any Tax.

(f)Any payments made to any Party pursuant to Article XIII shall constitute an adjustment to the Purchase Price for Tax purposes and shall be treated as such by Buyer and Seller on their respective Tax Returns to the extent permitted by Law.

(g)If Seller is legally and contractually entitled to cause each Tax Partnership (i) to make a valid election under Section 754 of the Code for the taxable year that includes the Closing Date (the “Section 754 Election”) and (ii) to make the election under Section 6226(a) of the Code (or any similar provision of state or local Law) with respect to the alternative to payment of an imputed underpayment by the Tax Partnership with respect to any taxable year beginning prior to the Closing Date and take other actions such as filings, disclosures and notifications necessary to effectuate such election (the “Push-Out Election”), Seller shall require the Tax Partnership (A) to cause the partnership representative and designated individual, if any, of the Tax Partnership to make the Push-Out Election and (B) to make the Section 754 Election. If Seller is not legally and contractually entitled to cause each Tax Partnership to make the Section 754 Election and the Push-Out Election, Seller shall use commercially reasonable efforts to cause the Tax Partnership (x) to cause the partnership representative and designated individual, if any, of the Tax Partnership to make the Push-Out Election and (y) to make the Section 754 Election.

16.3Value Allocations for Tax Purposes. Seller and Buyer agree that the portion, if any, of the Adjusted Purchase Price and any other items treated for federal Tax purposes as consideration for a sale transaction (collectively, the “Allocable Amount”) shall be allocated among the various Assets for federal and state income Tax purposes in accordance with Section 1060 of the Code and Treasury Regulations promulgated thereunder. The initial draft of such allocations shall be prepared by Seller and shall be provided to Buyer concurrently with the delivery of the Final Settlement Statement and for the avoidance of doubt shall be prepared in a manner consistent with the Allocated Values of the Title Wells determined pursuant to Section 3.6 to the maximum extent permitted by applicable Law. Seller and Buyer shall then prepare a mutually agreeable final schedule of any Allocable Amount among the Assets (as adjusted, the “Allocation Schedule”), which agreement shall be consistent with Section 3.6 and will not be unreasonably withheld, conditioned or delayed by either Party. The Allocation Schedule shall be updated to reflect any adjustments to the Allocable Amount. If required, the allocation of the Allocable Amount shall be reflected on a completed Internal Revenue Service Form 8594 (Asset Acquisition Statement under Section 1060), which such form will be timely filed separately by Seller and Buyer with the Internal Revenue Service pursuant to the requirements of Section 1060(b) of the Code. Neither Buyer nor Seller shall take any Tax position inconsistent with such allocation and neither Buyer nor Seller shall agree to any proposed adjustment to the Allocation by any Taxing authority unless required by a “determination” within the meaning of Section 1313(a) of the Code or with the prior written consent of the other Party; provided, however, that nothing contained herein shall prevent Buyer or Seller from settling any proposed deficiency or adjustment by any Taxing authority based upon or arising out of the Allocation, and neither Buyer nor Seller shall be required to litigate before any court any proposed deficiency or adjustment by any taxing authority challenging such Allocation. The procedures of Section 3.4(a) shall be applied in the event of a dispute for any item under this Section 16.3, mutatis mutandis.

16.4Assignment; Liquidating Trust. Neither this Agreement, nor any rights, obligations, liabilities, covenants, duties or responsibilities hereunder, may be assigned by any Party, in whole or in part, without the prior written consent of the other Party, which consent may be withheld for any reason; provided, however, that Buyer shall be permitted to assign all or any portion of its rights or obligations under this Agreement to one or more of its Affiliates without the prior consent of Seller, provided that the assigning Party shall remain primarily liable all obligations of Buyer hereunder together with its assignee. Any assignment in violation of the foregoing shall be deemed void ab initio; provided, further, that, Buyer may assign all or any portion of its rights and obligations pursuant to this Agreement to the Debt Financing Sources pursuant to the terms of the Commitment Documentation for purposes of creating a security interest herein or otherwise assigning as collateral in respect of the Commitment. No assignment by any Party of this Agreement shall relieve such Party of any of its obligations (including indemnity obligations), liabilities, covenants, duties or responsibilities hereunder without the non-assigning Party’s prior written consent (which may be withheld for any reason). If a Liquidating Trust is established, from and after the formation of the Liquidating Trust all rights and obligations of Seller under this Agreement shall accrue to and be for the benefit of and shall be exercisable by the Liquidating Trust, as provided by any order of the Bankruptcy Court and the Liquidating Trustee shall be entitled to exercise all of the rights of Seller under this Agreement.

16.5Preparation of Agreement. Both Seller and Buyer and their respective counsel participated in the preparation of this Agreement. In the event of any ambiguity in this Agreement, no presumption shall arise based on the identity of the draftsman of this Agreement.

16.6Publicity; Disclosure of Agreement and Transaction. Seller and Buyer and their respective Affiliates, if applicable, shall consult with each other with regard to all press releases or other public or private announcements issued or made at or prior to the Closing concerning this Agreement or the transactions contemplated herein, and neither Buyer nor Seller shall issue, and each of them shall not permit any Affiliate to issue any such press release or other publicity without the prior written consent of the other Party, which consent shall not be unreasonably withheld, conditioned or delayed. The foregoing limitations shall not (A) restrict disclosures by a Party that are permitted or required under this Agreement, including Section 3.4(a), (B) restrict disclosures by Buyer or Seller that are required by applicable securities or other Laws or regulations or the applicable rules of any Governmental Authority or stock exchange having jurisdiction over the disclosing Party or its Affiliates, (C) prevent Buyer or Seller from recording the Instruments of Conveyance or any federal or state assignments delivered at Closing or from complying with any disclosure requirements of Governmental Authorities that are applicable to the transfer of the Assets from Seller to Buyer, (D) prevent Buyer or Seller from making any disclosure of information relating to this Agreement if made in a manner, under conditions and to Persons that would be permitted under the terms of the Confidentiality Agreement so long as such Person continues to hold such information confidential on the same terms as set forth in such agreement, and (E) prevent Seller from making disclosures to the extent reasonably required in connection with complying with Preferential Purchase Rights and seeking to obtain Consents.

16.7Notices. All notices and communications which are required or may be given to a Party hereunder shall be in writing and shall be deemed to have been duly given upon the earliest of: (a) if by personal delivery, then the date of delivery if such date is a Business Day during normal business hours, or, if such date is not a Business Day during normal business hours, then the next Business Day, (b) if sent by U.S. certified mail, postage prepaid, return receipt requested, then the date shown as received on the return notice, (c) if sent by email, with delivery receipt to sender or (d) if by Federal Express overnight delivery (or other reputable overnight delivery service), the date shown on the notice of delivery if such date is a Business Day during normal business hours, or, if such date is not a Business Day during normal business hours, then on the next Business Day:

If to Seller:

Alta Mesa Holdings, LP

15021 Katy Freeway, Suite 400

Houston, Texas 77094

Attention: Ryan McKenzie, Associate General Counsel

E-mail: rmckenzie@AltaMesa.net

with a copy to:

Alta Mesa Holdings, LP

15021 Katy Freeway, Suite 400

Houston, Texas 77094

Attention: F. David Murrell, Vice President- Land

E-mail: dmurrell@AltaMesa.net

with a copy to:

Latham & Watkins LLP

330 North Wabash Avenue, Suite 2800

Chicago, Illinois 60611

Attention: Caroline A. Reckler, Partner

E-mail: caroline.reckler@lw.com

If to Buyer:

c/o Mach Resources LLC

14201 Wireless Way, Suite 300

Oklahoma City, Oklahoma 73134

Attention: Michael Reel, Senior Counsel

E-mail: mreel@machresources.com

3

with a copy to:

Bayou City Energy

1201 Louisiana Street, Suite 3308

Houston, Texas 77002

Attention: Darren Lindamood, Director & General Counsel

E-mail: Darren@bayoucityenergy.com

with a copy to (which shall not constitute notice):

Kirkland & Ellis LLP

609 Main Street, 45^th Floor

Houston, Texas 77002

Attention: David M. Castro Jr., P.C.

Christopher S.C. Heasley

E-mail: david.castro@kirkland.com

christopher.heasley@kirkland.com

and

Kirkland & Ellis LLP

300 North LaSalle

Chicago, Illinois 60654

Attention: Gregory F. Pesce

E-mail: gregory.pesce@kirkland.com

The Parties may change the identity, address and email addresses to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 16.7.

16.8Further Cooperation. After the Closing, Buyer and Seller shall execute and deliver, or shall cause to be executed and delivered from time to time, such further instruments of conveyance and transfer, and shall take such other actions as any Party may reasonably request, to transfer and deliver the Assets to Buyer, and to otherwise accomplish the transactions contemplated by this Agreement.

16.9Filings, Notices and Certain Governmental Approvals. Promptly after Closing, Buyer shall (with reasonable cooperation from Seller, as necessary) (a) record the Instruments of Conveyance relating to the Assets and all state/federal assignments executed at the Closing in all applicable real property records and, if applicable, all state or federal agencies, (b) if applicable, send notices to vendors supplying goods and services for the Assets of the assignment of the Assets to Buyer and, if applicable, the designation of Buyer (or, if applicable, Buyer’s operating Affiliate) as the operator thereof, (c) pursue the approval of all applicable Governmental Authorities of the assignment of the Assets to Buyer and, if applicable, the designation of Buyer (or, if applicable, Buyer’s operating Affiliate) as the operator thereof and (d) subject to the provisions of Section 5.4(b)(iii), pursue all other consents and approvals that may be reasonably required in connection with the assignment of the Assets to Buyer and the assumption of the Liabilities assumed by Buyer hereunder, that shall not have been obtained prior to Closing. Buyer obligates itself to take any and all action reasonably required of it by any Governmental Authority in order to obtain such approval, including but not limited to, the posting of any and all bonds or other security that may be required in excess of its existing lease, pipeline or area-wide bond.

16.10Entire Agreement; Conflicts. THIS AGREEMENT, THE CONFIDENTIALITY AGREEMENT, THE EXHIBITS AND SCHEDULES HERETO AND THE TRANSACTION DOCUMENTS COLLECTIVELY CONSTITUTE THE ENTIRE AGREEMENT AMONG THE PARTIES PERTAINING TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ALL PRIOR AGREEMENTS, UNDERSTANDINGS, NEGOTIATIONS, AND DISCUSSIONS, WHETHER ORAL OR WRITTEN, OF THE PARTIES PERTAINING TO THE SUBJECT MATTER OF THIS AGREEMENT, INCLUDING THE ORIGINAL AGREEMENT. THERE ARE NO WARRANTIES, REPRESENTATIONS, OR OTHER AGREEMENTS AMONG THE PARTIES RELATING TO THE SUBJECT MATTER OF THIS AGREEMENT EXCEPT AS SPECIFICALLY SET FORTH IN THIS AGREEMENT AND THE TRANSACTION DOCUMENTS, AND NO PARTY SHALL BE BOUND BY OR LIABLE FOR ANY ALLEGED REPRESENTATION, PROMISE, INDUCEMENT OR STATEMENTS OF INTENTION NOT SO SET FORTH. IN THE EVENT OF A CONFLICT BETWEEN: (A) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY SCHEDULE OR EXHIBIT HERETO, THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL; OR (B) THE TERMS AND PROVISION OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY TRANSACTION DOCUMENT, THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL; PROVIDED, HOWEVER, THAT THE INCLUSION IN ANY OF THE SCHEDULES OR EXHIBITS HERETO OR ANY TRANSACTION DOCUMENT OF TERMS AND PROVISIONS NOT ADDRESSED IN THIS AGREEMENT SHALL NOT BE DEEMED A CONFLICT, AND ALL SUCH ADDITIONAL PROVISIONS SHALL BE GIVEN FULL FORCE AND EFFECT, SUBJECT TO THE PROVISIONS OF THIS SECTION 12.5.

16.11Successors and Permitted Assigns. This Agreement shall be binding upon and inure to the benefit of the Parties and their permitted successors and assigns.

16.12Parties in Interest. Notwithstanding anything contained in this Agreement to the contrary, nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Parties, or their respective related Indemnified Parties hereunder any rights, remedies, obligations or liabilities under or by reason of this Agreement; provided that only a Party will have the right to enforce the provisions of this Agreement on its own behalf or on behalf of any of its related Indemnified Parties (but shall not be obligated to do so) ; provided, further, that that the Debt Financing Sources may enforce on behalf of the Debt Financing Related Parties (and each is an intended third party beneficiary of) the provisions of Section 16.4, this Section 16.12, Section 16.13, Section 16.14, Section16.15 and Section 16.21.

16.13Amendment. This Agreement may be amended only by an instrument in writing executed by all of the Parties and expressly identified as an amendment or modification; provided, that notwithstanding anything to the contrary contained herein, Section 16.4, Section 16.12, this Section 16.13, Section 16.14, Section16.15 and Section 16.21 (and any other provision of this Agreement to the extent an amendment, modification, waiver or termination of such provision would modify the substance of any of the foregoing provisions) may not be amended, modified, waived or terminated in a manner that is materially adverse to a Debt Financing Related Party without the prior written consent of the Debt Financing Sources.

16.14Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance; provided, that notwithstanding anything to the contrary contained herein, Section 16.4, Section 16.12, this Section 16.13, this Section 16.14, Section16.15 and Section 16.21 (and any other provision of this Agreement to the extent an amendment, modification, waiver or termination of such provision would modify the substance of any of the foregoing provisions) may not be amended, modified, waived or terminated in a manner that is materially adverse to a Debt Financing Related Party without the prior written consent of the Debt Financing Sources. No course of dealing on the part of any Party, or their respective officers, employees, agents, or representatives, nor any failure by a Party to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such Party at a later time to enforce the performance of such provision. No waiver by any Party of any condition, or any breach of any term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation, or warranty. The rights of the Parties under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

16.15Governing Law; Jurisdiction; Venue; Jury Waiver. EXCEPT TO THE EXTENT THE MANDATORY PROVISIONS OF THE BANKRUPTCY CODE APPLY, THIS AGREEMENT AND THE LEGAL RELATIONS BETWEEN THE PARTIES SHALL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS EXCLUDING ANY CONFLICTS OF LAW RULE OR PRINCIPLE THAT MIGHT REFER CONSTRUCTION OF SUCH PROVISIONS TO THE LAWS OF ANOTHER JURISDICTION; PROVIDED THAT ANY DISPUTE WITH RESPECT TO REAL PROPERTY SHALL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE WHERE SUCH REAL PROPERTY IS LOCATED. WITHOUT LIMITATION OF ANY PARTY’S RIGHT TO APPEAL ANY ORDER OF THE BANKRUPTCY COURT, (I) THE BANKRUPTCY COURT SHALL RETAIN EXCLUSIVE JURISDICTION TO ENFORCE THE TERMS OF THIS AGREEMENT AND ANY OF THE TRANSACTION DOCUMENTS DELIVERED PURSUANT HERETO, AND TO DECIDE ANY CLAIMS OR DISPUTES WHICH MAY ARISE OR RESULT FROM, OR BE CONNECTED WITH, THIS AGREEMENT OR SUCH TRANSACTION DOCUMENTS, OR ANY BREACH OR DEFAULT HEREUNDER OR THEREUNDER, OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY AND (II) ANY AND ALL CLAIMS RELATING TO THE FOREGOING SHALL BE FILED AND MAINTAINED ONLY IN THE BANKRUPTCY COURT, AND THE PARTIES AND HEREBY CONSENT AND SUBMIT TO THE EXCLUSIVE JURISDICTION AND VENUE OF THE BANKRUPTCY COURT AND IRREVOCABLY WAIVE THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF ANY SUCH ACTION OR PROCEEDING; PROVIDED, HOWEVER, THAT, IF THE BANKRUPTCY CASE IS CLOSED, EACH PARTY CONSENTS TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE UNITED STATES FEDERAL DISTRICT COURTS LOCATED IN HOUSTON, HARRIS COUNTY, TEXAS (OR IF THE FEDERAL DISTRICT COURTS DO NOT HAVE JURISDICTION, THEN THE STATE COURTS IN HOUSTON, HARRIS COUNTY, TEXAS) FOR ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS, OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY. SUBJECT TO THE FOREGOING PROVISIONS OF THIS SECTION 16.15, ANY SUCH ACTIONS, SUITS OR PROCEEDINGS WITH RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO, OR FROM THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY SHALL BE EXCLUSIVELY LITIGATED IN THE UNITED STATES FEDERAL DISTRICT COURTS HAVING SITES IN HOUSTON, HARRIS COUNTY, TEXAS (AND ALL APPELLATE COURTS HAVING JURISDICTION THEREOVER) OR, IF THE FEDERAL COURTS DO NOT HAVE JURISDICTION, THEN THE STATE COURTS IN HOUSTON, HARRIS COUNTY, TEXAS (AND ALL APPELLATE COURTS HAVING JURISDICTION THEREOVER). EACH PARTY WAIVES ANY OBJECTION TO LAYING VENUE IN ANY SUCH ACTION, SUIT OR PROCEEDING IN SUCH COURTS AND WAIVE ANY OBJECTION THAT SUCH COURTS ARE AN INCONVENIENT FORUM OR DO NOT HAVE JURISDICTION OVER SUCH PARTY. EACH PARTY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY (INCLUDING ANY LEGAL PROCEEDING AGAINST OR INVOLVING ANY DEBT FINANCING RELATED PARTY ARISING OUT OF THIS AGREEMENT OR THE DEBT FINANCING).

NOTWITHSTANDING ANYTHING HEREIN TO THE CONTRARY, (I) EACH PARTY HERETO ACKNOWLEDGES AND IRREVOCABLY AGREES THAT ANY PROCEEDING, WHETHER IN CONTRACT OR TORT, AT LAW OR IN EQUITY OR OTHERWISE, INVOLVING ANY DEBT FINANCING RELATED PARTY ARISING OUT OF, OR RELATING TO, THE TRANSACTIONS CONTEMPLATED HEREBY SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK AND (II) EACH OF THE PARTIES AGREES (I) THAT ANY CLAIM, CROSS-CLAIM, SUIT, ACTION OR PROCEEDING OF ANY KIND OR DESCRIPTION, WHETHER IN LAW OR IN EQUITY, WHETHER IN CONTRACT OR IN TORT OR OTHERWISE, INVOLVING ANY OF THE DEBT FINANCING RELATED PARTIES ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OF THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT, THE TRANSACTIONS CONTEMPLATED BY THE COMMITMENT OR THE PERFORMANCE OF SERVICES THEREUNDER SHALL BE SUBJECT TO THE EXCLUSIVE JURISDICTION OF A STATE OR FEDERAL COURT SITTING IN THE BOROUGH OF MANHATTAN WITHIN THE CITY OF NEW YORK AND THE APPELLATE COURTS THEREOF, (II) NOT TO BRING OR PERMIT ANY OF THEIR AFFILIATES TO BRING OR SUPPORT ANYONE ELSE IN BRINGING ANY SUCH CLAIM, SUIT, ACTION OR PROCEEDING IN ANY OTHER COURTS, OTHER THAN A STATE OR FEDERAL COURT SITTING IN THE BOROUGH OF MANHATTAN WITHIN THE CITY OF NEW YORK, (II) TO WAIVE AND HEREBY WAIVE, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH ANY OF THEM MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF, AND THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF, ANY SUCH ACTION IN ANY SUCH COURT, AND (IV) THAT ANY SUCH CLAIM, CONTROVERSY OR DISPUTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

4

16.16Severability. If any term or other provision of this Agreement is invalid, illegal, or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any Party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

16.17Removal of Name. As promptly as practicable, but in any case within 60 days after the Closing Date, Buyer shall eliminate the names of Seller and any of its Affiliates and any variants thereof from the Assets acquired pursuant to this Agreement and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Seller or any of its Affiliates.

16.18Counterparts. This Agreement may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission or other electronic transmission shall be deemed an original signature hereto.

16.19Time is of the Essence. With respect to all dates and time periods in this Agreement, time is of the essence. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (or the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

16.20No Recourse.

(a)Notwithstanding anything that may be expressed or implied in this Agreement or any other Transaction Document, Buyer, on behalf of its Affiliates and its and their representatives, covenants, agrees and acknowledges that no Person other than Seller and, for the limited purposes described in Sections 9.8(b), (c), (f), (g), (i), (j) and (k), AMR (and their respective successors or assignees, as applicable) has any obligation hereunder and that, neither Buyer, its Affiliates or its or their representatives have any right of recovery under this Agreement or any other Transaction Document against, and no personal liability under this Agreement or any Transaction Document shall attach to, any of Seller’s (and, for the limited purposes described in Sections 9.8(b), (c), (f), (g), (i), (j) and (k), AMR’s) former, current or future equity holders, controlling persons, directors, officers, employees, general or limited partners, members, managers, Affiliates or agents, or any former, current or future equity holder, controlling person, director, officer, employee, general or limited partner, member, manager, Affiliate or agent of any of the foregoing (collectively, each of the foregoing but not including Seller, a “Seller Non-Recourse Party”), through Buyer or otherwise, whether by or through attempted piercing of the corporate, limited partnership or limited liability company veil, by or through a claim by or on behalf of Buyer against any Seller Non-Recourse Party, by the enforcement of any assessment or by any legal or equitable proceeding, by virtue of any applicable Law, whether in contract, tort or otherwise.

(b)Notwithstanding anything that may be expressed or implied in this Agreement or any other Transaction Document, Seller, on behalf of its Affiliates and its and their representatives, covenants, agrees and acknowledges that no Person other than Buyer (and its successors or assignees, as applicable) has any obligation hereunder and that, neither Seller, its Affiliates or its or their representatives have any right of recovery under this Agreement or any other Transaction Document against, and no personal liability under this Agreement or any Transaction Document shall attach to, any of Buyer’s former, current or future equity holders, controlling persons, directors, officers, employees, general or limited partners, members, managers, Affiliates or agents, or any former, current or future equity holder, controlling person, director, officer, employee, general or limited partner, member, manager, Affiliate or agent of any of the foregoing (collectively, each of the foregoing but not including Buyer, a “Buyer Non-Recourse Party”), through Seller or otherwise, whether by or through attempted piercing of the corporate, limited partnership or limited liability company veil, by or through a claim by or on behalf of Seller against any Buyer Non-Recourse Party, by the enforcement of any assessment or by any legal or equitable proceeding, by virtue of any applicable Law, whether in contract, tort or otherwise.

16.21No Recourse to Financing Sources. Notwithstanding anything to the contrary contained herein, Seller and its controlled Affiliates agree on behalf of themselves and their respective Affiliates that none of the Debt Financing Related Parties shall have any liability or obligation to Seller and its controlled Affiliates or any of their respective Affiliates relating to this Agreement or any of the transactions contemplated herein (including the Commitment), in each case whether based on contract, tort or strict liability by the enforcement of any assessment, by any legal or equitable proceeding, by virtue of any statute, regulation or applicable laws or otherwise and whether by or through attempted piercing of the corporate, limited liability company or partnership veil, by or through a claim by or on behalf of a party hereto or another Person (including a claim to enforce the commitments under the Commitment Documentation) or otherwise. This Section 16.21 is intended to benefit and may be enforced by the Buyer, its Affiliates and the Debt Financing Sources providing the Commitment (and each such Person shall be a third party beneficiary of this Section 16.21) and shall be binding on all the respective successors and permitted assigns of Seller, its controlled Affiliates and their respective Affiliates.

[Remainder of page intentionally left blank. Signature page follows.]

(a)

5

EX-10.24

Exhibit 10.24

ALTA MESA RESOURCES, INC.

SUMMARY OF DIRECTOR COMPENSATION PROGRAM

Eligible Directors (as defined below), as members of the board of directors (the “Board”) of Alta Mesa Resources, Inc. (the “Company”), shall receive cash compensation as set forth in this Director Compensation Program (this “Program”). Such compensation shall be paid automatically and without further action of the Board unless such Eligible Director declines the receipt of such cash compensation by written notice to the Company. For purposes herein, an “Eligible Director” is any member of the Board who is not (i) an employee of the Company or any parent or subsidiary of the Company or (ii) affiliated with Riverstone Investment Group LLC, Bayou City Energy Management, LLC or HPS Investment Partners, LLC. This Program shall remain in effect until it is revised or rescinded by further action of the Board. This Program may be amended, modified or terminated by the Board at any time in its sole discretion. The terms and conditions of this Program shall supersede any prior compensation arrangements for service as a member of the Board between the Company and any of its Eligible Directors.

I. Annual Retainers. Each Eligible Director shall receive an annual retainer of $237,500 for service on the Board.

II. Additional Annual Retainers. In addition, each Eligible Director shall receive the following annual retainers:

A. Audit Committee. An Eligible Director serving as Chairperson of the Audit Committee shall receive an additional annual retainer of $22,500 for such service. An Eligible Director serving as a member other than the Chairperson of the Audit Committee shall receive an additional annual retainer of $10,000 for such service.

B. Compensation Committee. An Eligible Director serving as Chairperson of the Compensation Committee shall receive an additional annual retainer of $15,000 for such service. An Eligible Director serving as a member other than the Chairperson of the Compensation Committee shall receive an additional annual retainer of $6,000 for such service.

C. Nominating and Corporate Governance Committee. An Eligible Director serving as Chairperson of the Nominating and Corporate Governance Committee shall receive an additional annual retainer of $12,500 for such service. An Eligible Director serving as a member other than the Chairperson of the Nominating and Corporate Governance Committee shall receive an additional annual retainer of $5,000 for such service.

III. Meeting Fees. In addition, each Eligible Director shall receive the following per meeting fees:

A. Audit Committee. Each Eligible Director serving as a member of the Audit Committee shall receive a per meeting fee of $1,500 for each Audit Committee meeting attended per calendar year in excess of eight meetings.

B. Compensation Committee. Each Eligible Director serving as a member of the Compensation Committee shall receive a per meeting fee of $1,500 for each Compensation Committee meeting attended per calendar year in excess of six meetings.

C. Nominating and Corporate Governance Committee. Each Eligible Director serving as a member of the Nominating and Corporate Governance Committee shall receive a per meeting fee of $1,500 for each Nominating and Corporate Governance Committee meeting attended per calendar year in excess of six meetings.

D. Additional Meeting Fees. Each Eligible Director shall receive a per meeting fee of $2,000 for each Board meeting attended per calendar year in excess of seven meetings.

E. Special Meeting Fees. Each Eligible Director shall receive a per meeting fee of $2,000 to address time commitments of four or more continuous hours in a day or six hours in any 10-day period as a result of time commitments required outside of the normal course. The Chairman and General Counsel shall be responsible for the administration of special meeting fees.

IV. Payment of Retainers and Fees. The annual retainers and meeting fees described in herein shall be earned on a quarterly basis based on a calendar quarter and shall be paid in cash by the Company in arrears not later than the fifteenth day following the end of each calendar quarter. In the event an Eligible Director does not serve as an Eligible Director, or in the applicable positions described in Section II, for an entire calendar quarter, the retainer paid to such Eligible Director shall be prorated for the portion of such calendar quarter actually served as an Eligible Director, or in such position, as applicable.

EX-21.1

EXHIBIT 21.1

ALTA MESA RESOURCES, INC.

Subsidiaries as of the date of this filing

Subsidiary		Jurisdiction of Formation
1.	Alta Mesa Finance Services Corp.	Delaware
2.	OEM GP, LLC	Texas
3.	Alta Mesa Services, LP	Texas
4.	Oklahoma Energy Acquisitions, LP	Texas
5.	Kingfisher Stack Oil PL LLC	Delaware
6.	OK Prod. Water Solutions, LLC	Delaware

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark P. Castiglione, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: March 5, 2020

/s/ Mark P. Castiglione

Mark P. Castiglione

Chief Executive Officer

Alta Mesa Resources, Inc.

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, John C. Regan, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: March 5, 2020

/s/ John C. Regan

John C. Regan

Chief Financial Officer

Alta Mesa Resources, Inc.

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

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

1. The Annual Report on Form 10-K of the Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

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

Date: March 5, 2020

/s/ Mark P. Castiglione

Mark P. Castiglione

Chief Executive Officer

Alta Mesa Resources, Inc.

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

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

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

1. The Annual Report on Form 10-K of the Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

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

Date: March 5, 2020

/s/ John C. Regan

John C. Regan

Chief Financial Officer

Alta Mesa Resources, Inc.

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

EX-99.1

XXX Company

Date

Page 1

Exhibit 99.1

ALTA MESA HOLDINGS, L.P.

Estimated

Future Reserves

Attributable to Certain Leasehold and Royalty Interests

OKLAHOMA PROPERTIES

SEC Parameters

As of

December 31, 2019

/s/ Miles R. Palke	/s/ Amara N. Okafor
Miles R. Palke	Amara N. Okafor, P.E.
TBPE License No. 94894	TBPE License No. 113166
Managing Senior Vice President	Vice President

[SEAL]                             [SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

February 4, 2020

Tim J. Turner

VP Corporate Planning and Reserves

Alta Mesa Holdings, L.P.

15021 Katy Freeway, Suite 400

Houston, Texas 77094

Dear Mr. Turner:

At the request of Alta Mesa Holdings, L.P. (AMH), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2019 prepared by AMH’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on January 23, 2020 and presented herein, was prepared for public disclosure by AMH in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent AMH’s estimated net reserves attributable to the leasehold and royalty interestsin certain properties owned by AMH and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2019. The properties reviewed by Ryder Scott incorporate 362 reserves determinations and are located in the state of Oklahoma.

The properties reviewed by Ryder Scott account for a portion of AMH’s total net proved reserves located in the state of Oklahoma as of December 31, 2019. Based on the estimates of total net proved reserves prepared by AMH, the reserves audit conducted by Ryder Scott addresses 97 percent of the total proved net liquid and 97 percent of the total proved net gas hydrocarbon reserves. The properties reviewed by Ryder Scott account for a portion of AMH’s total proved discounted future net income using SEC hydrocarbon price parameters as of December 31, 2019. Although it was not included in our scope of study to review the economic analysis prepared by AMH, the net income projections for the reserves reviewed by Ryder Scott account for 97 percent of the total proved discounted future net income of AMH’s Oklahoma properties, as estimated by the staff of AMH.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Alta Mesa Holdings, L.P. – Oklahoma Properties – SEC Parameters

February 4, 2020

Page 1

Based on our review, including the data, technical processes and interpretations presented by AMH, it is our opinion that the overall procedures and methodologies utilized by AMH in preparing their estimates of the proved reserves as of December 31, 2019 comply with the current SEC regulations, and that the overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. AMH has informed us that in the preparation of their reserves and income projections, as of December 31, 2019, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by AMH attributable to AMH's interest in properties that we reviewed and for those that we did not review are summarized below:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold and Royalty Interests of

Alta Mesa Holdings, L.P.

Oklahoma Properties

As of December 31, 2019

	Total
	Proved
	Producing
Net Reserves of Properties
Audited by Ryder Scott
Oil/Condensate – MBarrels	16,258
Plant Products – MBarrels	10,288
Gas – MMcf	110,574
MBOE	44,975
Net Reserves of Properties
Not Audited by Ryder Scott
Oil/Condensate – MBarrels	658
Plant Products – MBarrels	227
Gas – MMcf	3,869
MBOE	1,530
Total Net Reserves
Oil/Condensate – MBarrels	16,916
Plant Products – MBarrels	10,515
Gas – MMcf	114,443
MBOE	46,505

SUITE 800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799    FAX (403) 262-2790

633 17TH STREET, SUITE 1700    DENVER, COLORADO 80202    TEL (303) 339-8110

Alta Mesa Holdings, L.P. – Oklahoma Properties – SEC Parameters

February 4, 2020

Page 2

Liquid hydrocarbons are expressed in thousands of standard 42 U.S. gallon barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.

The plant products in our review are based on AMH’s calculations of estimated plant product recovery yields to gas production.

As stated previously, AMH requested that Ryder Scott conduct an audit of only reserves volumes for certain properties for which they have interests, but did not request Ryder Scott conduct an economic analysis of the net economic benefit from the production of those reserves volumes. However, AMH did request that the total future net income discounted at 10 percent (FNI @ 10%) as prepared by AMH for the same properties that were included in our reserves audit, as well as those that were not a part of our reserves audit, be summarized below (even though Ryder Scott did not review or analyze these economic projections). As a result, Ryder Scott expresses no opinion on these economic values. This information is only intended to show the FNI @ 10% estimated by AMH, which is associated with the properties that were included in the Ryder Scott audit (of the reserves volumes), as compared to those that were not.

SEC PARAMETERS

Discounted Future Net Income

Certain Leasehold and Royalty Interests of

Alta Mesa Holdings, L.P.

Oklahoma Properties

As of December 31, 2019

	Total
	Proved
	Producing
Future Net Income Discounted at 10% (M$)
Properties Reviewed by	337,660
Ryder Scott
Properties Not Reviewed by	8,686
Ryder Scott
Total	346,346

The discounted future net income shown above is presented at AMH’s request for your information and should not be construed as an estimate of fair market value. The term M$ denotes thousands of U.S. dollars.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

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The various proved reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. At Alta Mesa’s request, only proved producing reserves were included in this report.

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.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At AMH’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, They may or may not be actually recovered, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves

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quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves, prepared by AMH, for the properties that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through November 2019, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by AMH and were considered sufficient for the purpose thereof.

No proved developed non-producing or undeveloped reserves were reviewed as part of this audit.

Horizontal wells, essentially all of which are located in the Meramec, Osage, and Oswego plays in Oklahoma, represent approximately 99.6 percent of AMH’s liquids reserves and 99.9 percent of AMH’s gas reserves in Oklahoma.

To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by AMH relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by AMH for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.

The initial SEC hydrocarbon prices in effect on December 31, 2019 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to

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the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by AMH for the geographic area reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used by AMH to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH.

The table below summarizes AMH’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as AMH’s “average realized prices.” The average realized prices shown in the table below were determined from AMH’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and AMH’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for the geographic area reviewed by us.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
United States	Oil/Condensate	WTI Cushing	$55.69/bbl	$54.50/bbl
	NGLs	WTI Cushing	$55.69/bbl	$14.60/bbl
	Gas	Henry Hub	$2.58/MMBTU	$2.19/MCF

The term MMBTU denotes millions of British thermal units.

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in AMH’s individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserves estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by AMH are based on the operating expense reports of AMH and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating cost also includes the transportation and marketing cost for oil, natural gas, and natural gas liquids (NGL). For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

This review does not include any undeveloped reserves, hence no development costs were furnished by AMH. The estimated net cost of abandonment after salvage was included by AMH for properties where abandonment costs net of salvage were material. AMH’s estimates of the net abandonment costs were accepted without independent verification.

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Current costs used by AMH were held constant throughout the life of the properties.

AMH’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

The future production rates from wells currently on production or wells that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

AMH’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income taxand are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a review of the properties in which AMH owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by AMH for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of AMH are responsible for the preparation of reserves estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

AMH has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of AMH’s forecast of future proved production, we have relied upon data furnished by AMH with respect to property interests owned, production and well tests from examined wells, plant production yields, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion costs, abandonment costs after salvage, product prices based on the SEC regulations and adjustments or differentials to product prices. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by AMH. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by AMH to be appropriate and sufficient for the purpose of our review of AMH’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by AMH and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

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Based on our reserves review, including the data, technical processes and interpretations presented by AMH, it is our opinion that the overall procedures and methodologies utilized by AMH in preparing their estimates of the proved reserves as of December 31, 2019 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by AMH in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.

We were in reasonable agreement with AMH's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between AMH's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to AMH when its reserves estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by AMH.

Other Properties

Other properties, as used herein, are those Oklahoma properties of AMH which we did not review. The proved net reserves attributable to the other properties account for approximately three percent of the total proved net liquid hydrocarbon reserves and approximately three percent of the total proved net gas reserves based on estimates prepared by AMH as of December 31, 2019.

The same technical personnel of AMH were responsible for the preparation of the reserves estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

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We are independent petroleum engineers with respect to AMH. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by AMH.

We have provided AMH with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by AMH and the original signed report letter, the original signed report letter shall control and supersede the digital version.

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The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Miles R. Palke

Miles R. Palke, P.E

TBPE License No. 94894

Managing Senior Vice President    [SEAL]

/s/ Amara N. Okafor

Amara N. Okafor, P.E.

TBPE License No. 113166

Vice President                [SEAL]

MRP-ANO (DCR)/pl

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Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Miles Robert Palke was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott presented herein.

Mr. Palke, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2009, is a Managing Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies with extensive experience in the Gulf of Mexico and other regions. Before joining Ryder Scott, Mr. Palke served in a number of engineering positions with BHP Billiton, Ryder Scott Company, and ARCO. For more information regarding Mr. Palke’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Palke earned a Bachelor of Science in Petroleum Engineering from Texas A&M University in College Station TX and a Master of Science in Petroleum Engineering from Stanford University in Palo Alto California. Mr. Palke graduated Magna Cum Laude and with University Honors from Texas A&M University and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Palke fulfills. As part of his 2019 continuing education hours, Mr. Palke attended 16 hours of industry and in-house engineering training.

Based on his educational background, professional training and more than 23 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Palke has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

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PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

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.All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples

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of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

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.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

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(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

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Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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SIGNIFICANT CONCENTRATIONS (Tables)

12 Months Ended

Dec. 31, 2019

Risks and Uncertainties [Abstract]

Schedule of Significant Concentrations

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	123,000	$	336,248	$	28,757
Marketing and management fees paid to ARM	$	1,715	$	—	$	—
Fees paid to ARM for services relating to our derivatives	496		784		66
Total fees paid to ARM	$	2,211	$	784	$	66

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Oil and Natural Gas Disclosures [Abstract]

Estimated Quantities Of Proved Reserves

The following table sets forth our net proved reserves as of December 31, 2019 and 2018 and February 8, 2018, and the changes therein during the periods then ended.

	Oil (Mbbls)		Gas (MMcf)		NGL’s (Mbbls)		Boe (Mbbls)
Total Proved Reserves:
Balance at December 31, 2017 (Predecessor)	73,518		433,519		36,887		182,658
Production	(521	)	(1,984	)	(161	)	(1,012	)
Sales of reserves in place (1)	(1,667	)	(24,239	)	(771	)	(6,478	)
Revisions of previous quantity estimates and other	375		3,506		289		1,248
Balance at February 8, 2018 (Predecessor)	71,705		410,802		36,244		176,416
Production(2)	(5,053	)	(16,913	)	(2,268	)	(10,140	)
Purchases in place(2)	2,658		13,331		1,751		6,631
Discoveries and extensions(2)	30,026		155,306		19,646		75,557
Revisions of previous quantity estimates and other(2)	(74,064	)	(418,378	)	(35,581	)	(179,375	)
Balance at December 31, 2018 (Successor)	25,272		144,148		19,792		69,089
Production	(5,885	)	(24,802	)	(2,760	)	(12,779	)
Discoveries and extensions	4,265		24,351		2,835		11,159
Revisions of previous quantity estimates and other(3)	(6,736	)	(29,254	)	(9,352	)	(20,964	)
Balance at December 31, 2019 (Successor)	16,916		114,443		10,515		46,505
Proved Developed Reserves:
Balance at December 31, 2017	20,347		150,183		12,180		57,557
Balance at February 8, 2018	19,345		126,231		11,348		51,731
Balance at December 31, 2018	25,272		144,148		19,792		69,089
Balance at December 31, 2019	16,916		114,443		10,515		46,505
Proved Undeveloped Reserves:
Balance at December 31, 2017	53,171		283,336		24,707		125,101
Balance at February 8, 2018	52,360		284,571		24,896		124,685
Balance at December 31, 2018	—		—		—		—
Balance at December 31, 2019	—		—		—		—

_________________

(1) Sales of reserves in place during the 2018 Predecessor Period represent amounts related to our non-STACK properties that were distributed to High Mesa and are classified as discontinued operations in our financial statements.

(2) An analysis of changes in our reserves from February 8, 2018 to December 31, 2018 follows:

	MBoe
Description	Proved Developed Reserves		Proved Undeveloped Reserves		Total
Balance at February 8, 2018	51,731		124,685		176,416
Production	(10,140	)	—		(10,140	)
Purchases in place, discoveries and extensions	35,096		47,092		82,188
Revisions of previous quantity estimates and other:
Lower estimated recoveries identified as a result of 2018 drilling program	(31,964	)	(69,534	)	(101,498	)
Higher average commodity prices in Successor Period compared to 2017	5,367		5,829		11,196
Transfers of PUDs to proved developed reserves	18,999		(18,999	)	—
Derecognition of PUDs due to significant concerns about ability to fund development of those reserves	—		(89,073	)	(89,073	)
Balance at December 31, 2018	69,089		—		69,089

(3) Revisions decreased our estimated recovery of proved reserves and is ratably due to lower average commodity prices in 2019 as compared to 2018, the decision to report ethane rejection rather than ethane recovery, and decreases in volume estimates based on the overall performance of our wells.

Results of Operations for Oil and Gas Producing Activities

Results of Operations for Oil and Gas Producing Activities - Upstream Segment

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Operating revenue	$	423,576		$	414,507		$	40,136
Production expense (1)	232,212			247,748			30,743
Depreciation, depletion and amortization	120,617			133,554			11,670
Exploration expense	52,354			34,085			7,003
Impairment expense	556,427			2,033,712			—
Income tax expense (benefit)	—			4			—
Results of operations	$	(538,034	)	$	(2,034,596	)	$	(9,280	)

_________________

(1)

Production expense consists of direct lease operating expense, transportation and marketing expense, production taxes, workover expense and allocated general and administrative expense.

Capitalized Costs Relating To Oil And Natural Gas Producing Activities

Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
(in thousands)	2019			2018
Capitalized costs:
Proved properties	$	2,239,444		$	2,110,346
Unproved properties	813,310			816,282
Total	3,052,754			2,926,628
Accumulated depreciation, depletion, amortization and impairment	(2,837,402		)	(2,163,291		)
Net capitalized costs	$	215,352		$	763,337

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Costs incurred during the period: (1)
Property acquisition
Unproved (2)	$	—	$	54,587	$	4,240
Proved	—		16,300		327
Exploration	7,305		32,130		3,678
Development (3)	134,908		664,138		37,672
	$	142,213	$	767,155	$	45,917

_________________

(1) Costs incurred in the 2018 Predecessor Period include amounts related to non-STACK oil and gas assets, which were distributed in connection with the Business Combination.

(2) Property acquisition costs for unproved properties include the acquisition of unevaluated leasehold portion from an unaffiliated third party of approximately $22.3 million for the 2018 Successor Period.

(3)

Includes asset retirement additions (revisions) of $0.9 million and $5.6 million for the 2019 and the 2018 Successor Period, respectively. For the 2018 Predecessor Period, there were no material asset retirement additions (revisions).

Components Of The Standardized Measure Of Discounted Future Net Cash Flows

The following table sets forth the components of the standardized measure of discounted future net cash flows:

	Successor						Predecessor
(in thousands, except per unit data)	December 31, 2019			December 31, 2018			February 8, 2018
Future cash inflows	$	1,326,490		$	2,446,888		$	5,798,886
Future production costs	(825,300		)	(1,214,479		)	(2,556,361		)
Future development costs	(25,251		)	(23,183		)	(965,780		)
Future income taxes	(26,707		)	(146,632		)	—
Future net cash flows(1)	449,232			1,062,594			2,276,745
Discount to present value at 10 percent per annum	(122,321		)	(348,311		)	(1,096,859		)
Standardized measure of discounted future net cash flows	$	326,911		$	714,283		$	1,179,886
Base price for crude oil, per barrel, in the above computation	$	55.69		$	65.56		$	52.89
Base price for gas, per Mcf, in the above computation	$	2.58		$	3.10		$	2.99
Realized price for NGLs, per barrel, in the above computation	$	14.60		$	22.44		$	27.48

Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows

Changes in Standardized Measure of Discounted Future Net Cash Flows

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Balance at beginning of period	$	714,283		$	1,179,886		$	1,105,922
Sales and transfers of oil and gas produced, net of production costs	(253,582		)	(278,091		)	(30,391		)
Net changes in prices and production costs	(270,712		)	38,963			71,334
Revisions of previous quantity estimates	(129,305		)	(1,120,097		)	10,887
Purchases of reserves in-place	—			24,376			—
Sales of reserves in-place(1)	—			—			(4,807		)
Current year discoveries and extensions, less related costs	134,451			684,700			—
Changes in estimated future development costs	473			(39,069		)	491
Development costs incurred during the period	84			160,583			—
Accretion of discount	81,285			117,989			110,592
Net change in income taxes	79,134			(98,568		)	—
Change in production rate (timing) and other	(29,200		)	43,611			(84,142		)
Net change	(387,372		)	(465,603		)	73,964
Balance at end of period	$	326,911		$	714,283		$	1,179,886

_________________

(1)

The sale of reserves in-place during the 2018 Predecessor Period includes the sale of non-STACK properties.

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RECEIVABLES (Management Services Agreement with HMI) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Allowance for Doubtful Accounts Receivable [Roll Forward]
HMI related party receivable at December 31, 2018	$ 12,376
HMI related party receivable at December 31, 2019	12,144
Allowance for doubtful accounts	(12,144)	$ (9,035)
Balance at December 31, 2019, net	0	3,341
High Mesa Agreement
Allowance for Doubtful Accounts Receivable [Roll Forward]
HMI related party receivable at December 31, 2018	10,066
Additions	832
Payments	(1,073)
HMI related party receivable at December 31, 2019	9,825
Allowance for doubtful accounts	(9,825)
Balance at December 31, 2019, net	0
High Mesa Agreement | Affiliated Entity
Allowance for Doubtful Accounts Receivable [Roll Forward]
Allowance for uncollectible accounts	$ 9,800	$ 9,000

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PROPERTY AND EQUIPMENT (Sale of Produced Water Assets) (Details) - KFM Credit Facility - Affiliated Entity $ in Millions	1 Months Ended
	Nov. 30, 2018 USD ($) well mi
Property, Plant and Equipment [Line Items]
Miles of produced water gathering pipelines | mi	200
Number of produced water disposal wells sold | well	20
Proceeds from sale of produced water assets	$ 99
Cash at closing	90
Purchase price adjustments	$ 9
Produced water agreement term	15 years

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SIGNIFICANT ACQUISITIONS AND DIVESTITURES (Earn-Out Consideration) (Details) - $ / shares		3 Months Ended
	Feb. 09, 2018	Jun. 30, 2018
AM Contributor
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares issued to acquire business (in shares)		1,197,934
KFM Contributor
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares issued to acquire business (in shares)		89,680
SRII Opco, LP | $14.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
20-Day VWAP (in dollars per share)	$ 14.00
SRII Opco, LP | $16.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
20-Day VWAP (in dollars per share)	16.00
SRII Opco, LP | $18.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
20-Day VWAP (in dollars per share)	18.00
SRII Opco, LP | $20.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
20-Day VWAP (in dollars per share)	$ 20.00
SRII Opco, LP | AM Contributor | $14.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares issued to acquire business (in shares)	10,714,285
SRII Opco, LP | AM Contributor | $16.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares issued to acquire business (in shares)	9,375,000
SRII Opco, LP | AM Contributor | $18.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares issued to acquire business (in shares)	13,888,889
SRII Opco, LP | AM Contributor | $20.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares issued to acquire business (in shares)	12,500,000
SRII Opco, LP | KFM Contributor | $14.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares issued to acquire business (in shares)	7,142,857
SRII Opco, LP | KFM Contributor | $16.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares issued to acquire business (in shares)	6,250,000

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ADOPTION OF ASU NO. 2016-02, LEASES (Operating Lease Liability Maturities) (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Leases [Abstract]
2020	$ 2,256
2021	2,209
2022	2,329
2023	2,321
2024	2,367
Thereafter	8,219
Total lease payments	19,701
Less: imputed interest	(8,336)
Less: reclassification to liabilities subject to compromise	(11,088)
Present value of operating lease liabilities	277
Current portion of operating lease liabilities	88
Operating lease liabilities, net of current portion	$ 189

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FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Original Carrying Value | Midstream
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unproved oil and gas properties	$ 31,023	$ 816,282
Proved oil and gas properties	700,182	1,895,670
Operating lease right-of-use assets, net	13,514	0
Other long-term assets(1)	51,518	0
Equity method investment	0	17,063
Midstream property, plant and equipment	432,415	474,529
Intangible assets	0	394,999
Goodwill	0	691,970
Total	1,228,652	4,290,513
Estimated Fair Value | Alta Mesa RBL | 7.875% Senior Unsecured Notes Due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of unsecured senior notes	45,300	312,500
Estimated Fair Value | Midstream
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unproved oil and gas properties	0	74,217
Proved oil and gas properties	215,352	604,023
Operating lease right-of-use assets, net	0	0
Other long-term assets(1)	24,189	0
Equity method investment	0	1,100
Midstream property, plant and equipment	83,818	406,122
Intangible assets	0	0
Goodwill	0	0
Total	323,359	1,085,462
Impairment | Midstream
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unproved oil and gas properties	31,023	742,065
Proved oil and gas properties	484,830	1,291,647
Operating lease right-of-use assets, net	13,514	0
Other long-term assets(1)	27,329	0
Equity method investment	0	15,963
Midstream property, plant and equipment	348,597	68,407
Intangible assets	0	394,999
Goodwill	0	691,970
Total	$ 905,293	$ 3,205,051

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SUPPLEMENTAL CASH FLOW INFORMATION (Supplemental Disclosures To The Consolidated Statements Of Cash Flows) (Details) - USD ($) $ in Thousands		1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2018	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Supplemental cash flow information:
Cash paid for interest		$ 1,145	$ 52,017	$ 56,683
Cash paid for income taxes		0	1,573	706
Non-cash investing and financing activities:
Increase in asset retirement obligations		0	5,665	853
Increase (decrease) in accruals or payables for capital expenditures		4,896	39,997	(155,681)
Increase in withholding tax accruals for share-based compensation		0	534	142
Distribution of non-STACK assets, net of liabilities		43,482	0	0
Equity issued in Business Combination		0	2,067,393	0
Release of common stock from possible redemption	$ 996,384	0	996,384	0
Other		$ 0	$ (6)	$ 78

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EQUITY-BASED COMPENSATION (Successor) (Schedule of Restricted Stock Awards and PSUs Granted) (Details) - $ / shares	11 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019
Restricted Stock Awards
Restricted Stock Awards
Outstanding, beginning balance (shares)	0	1,792,011
Granted (shares)	2,238,359	70,093
Vested (shares)	(384,413)	(619,061)
Forfeited or expired (shares)	(61,935)	(719,766)
Outstanding, ending balance (shares)	1,792,011	523,277
Weighted Average Grant Date Fair Value per share
Outstanding, beginning balance (usd per share)	$ 0	$ 7.32
Granted (usd per share)	7.54	0.96
Vested (usd per share)	8.40	7.04
Forfeited or expired (usd per share)	8.80	7.36
Outstanding, ending balance (usd per share)	$ 7.32	$ 6.74
Tax withholdings paid (in shares)	94,576	130,432
PSUs
Restricted Stock Awards
Outstanding, beginning balance (shares)	0	0
Granted (shares)	2,093,453	1,220,490
Vested (shares)	(1,559,749)	(100,870)
Forfeited or expired (shares)	(533,704)	(54,112)
Outstanding, ending balance (shares)	0	1,065,508
Weighted Average Grant Date Fair Value per share
Outstanding, beginning balance (usd per share)	$ 0	$ 0
Granted (usd per share)	4.07	0.32
Vested (usd per share)	2.53	0.96
Forfeited or expired (usd per share)	8.54	0.27
Outstanding, ending balance (usd per share)	$ 0	$ 0.27
Tax withholdings paid (in shares)	388,655	32,481

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

Recurring measurements

We historically utilized the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and gas derivatives. Inputs to these models included observable inputs from the NYMEX for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and gas prices. We have classified the inputs used to determine fair values of all our oil, gas and natural gas liquids derivative contracts as Level 2. See Note 13 - Derivatives for further information.

Non-recurring measurements

We estimated the fair value of Alta Mesa’s 2024 Notes to be $45.3 million at December 31, 2019 ($312.5 million at December 31, 2018), based on their most recent trading values at or near each reporting date, which is a Level 1 determination.

At December 31, 2019, our oil, gas and midstream properties were evaluated for impairment based on the winning bid prices in a January 2020 auction of our assets conducted as part of a Bankruptcy Court approved sales process. These bid prices are considered a Level 1 input. Prior to December 31, 2019, our oil, gas, and midstream properties, as well as our goodwill and intangible assets in our Midstream segment were subject to impairment testing and potential impairment based largely on future estimated cash flows determined using Level 3 inputs.

	December 31, 2019						December 31, 2018
(in thousands)	Carrying Value Before Assessment		Estimated Fair Value		Impairment		Carrying Value Before Assessment		Estimated Fair Value		Impairment
Unproved oil and gas properties	$	31,023	$	—	$	31,023	$	816,282	$	74,217	$	742,065
Proved oil and gas properties	700,182		215,352		484,830		1,895,670		604,023		1,291,647
Operating lease right-of-use assets	13,514		—		13,514		—		—		—
Other long-term assets(1)	51,518		24,189		27,329		—		—		—
Equity method investment	—		—		—		17,063		1,100		15,963
Midstream property and equipment(1)	432,415		83,818		348,597		474,529		406,122		68,407
Intangible assets	—		—		—		394,999		—		394,999
Goodwill	—		—		—		691,970		—		691,970
Total	$	1,228,652	$	323,359	$	905,293	$	4,290,513	$	1,085,462	$	3,205,051

_________________

(1) Amounts reflect only those assets that were impaired.

We estimate the fair value of additions to asset retirement obligations associated with new or acquired properties. Such estimations of fair value are based on present value techniques that utilize company-specific information for inputs such as the cost and timing of plugging and abandonment of wells and facilities. These inputs are classified as Level 3.

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COMMITMENTS AND CONTINGENCIES (Schedule Of Firm Transportation Contracts) (Details) MMBTU in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) MMBTU
Long-term Purchase Commitment [Line Items]
2020	$ 18,352
2021	18,352
2022	18,095
2023	17,912
2024	11,342
Thereafter	83,686
Firm transportation contracts total	$ 167,739
Committed capacity, 2020 (in MMBtus) | MMBTU	45,750
Committed capacity, 2021 (in MMBtus) | MMBTU	45,625
Committed capacity, 2022 (in MMBtus) | MMBTU	40,275
Committed capacity, 2023 (in MMBtus) | MMBTU	36,500
Committed capacity, 2024 (in MMBtus) | MMBTU	36,600
Committed capacity, thereafter (in MMBtus) | MMBTU	413,850
Upstream
Long-term Purchase Commitment [Line Items]
2020	$ 12,236
2021	12,236
2022	12,236
2023	12,236
2024	5,666
Thereafter	19,358
Firm transportation contracts total	73,968
Midstream
Long-term Purchase Commitment [Line Items]
2020	6,116
2021	6,116
2022	5,859
2023	5,676
2024	5,676
Thereafter	64,328
Firm transportation contracts total	$ 93,771

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IMPAIRMENT OF ASSETS

12 Months Ended

Dec. 31, 2019

Other Income and Expenses [Abstract]

IMPAIRMENT OF ASSETS

IMPAIRMENT OF ASSETS

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Upstream
Impairment of unproved properties	$	31,023	$	742,065	$	—
Impairment of proved properties	484,830		1,291,647		—
Impairment of operating lease right-of-use assets	13,245		—		—
Impairment of other long-term assets	27,329		—		—
Total Upstream impairment of assets	556,427		2,033,712		—
Midstream
Impairment of Cimarron investment	—		15,963		—
Impairment of property and equipment	348,597		68,407		—
Impairment of operating lease right-of-use assets	269		—		—
Impairment of intangible assets	—		394,999		—
Impairment of goodwill	—		691,970		—
Total Midstream impairment of assets	348,866		1,171,339		—
Total impairment of assets	$	905,293	$	3,205,051	$	—

Impairment of Proved and Unproved Properties

The Initial Debtors filed for bankruptcy protection in September 2019. The sales price per the AMH PSA is $232.0 million (with a January 1, 2020 effective date) for substantially all of our oil and gas properties and certain other upstream property and equipment, resulting in total impairment expense of $515.9 million for our proved and unproved oil and gas properties and $13.1 million for certain other upstream property and equipment during 2019.

During the late fourth quarter of 2018, we experienced a 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. We determined these factors indicated possible impairment of our assets. Following our analysis of impairment, we recognized impairment charges of $2.0 billion in 2018 to our proved and unproved oil and gas properties using an income approach supplemented by a market approach for our unproved properties.

Impairment of Operating Lease Right-of-Use Assets

During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We sought to sublease our unused office space resulting from the consolidation but have since suspended those efforts in connection with our bankruptcy filing. Additionally, as a result of the expected Sale Transactions, we concluded that all remaining operating lease right-of-use assets were also not recoverable based on expected rejection of those leases in bankruptcy. As a result, we recognized charges of $13.2 million and $0.3 million, respectively, to fully impair all remaining Upstream and Midstream operating lease right-of-use assets at December 31, 2019. This impairment had no impact on our lease liability.

Impairment of Other Long-Term Assets

In addition to the impairment of certain other upstream property and equipment described above, we also recognized impairment expense of $14.2 million associated with a long-term asset relating to a prepayment of certain transportation fees under a long-term customer contract. As part of our bankruptcy proceedings, we expect this contract will be rejected and have determined that recovery of this prepayment is unlikely.

Impairment of equity method investment

As the late-2018 outlook for Alta Mesa volumes and third-party volume opportunities in the area were significantly lower than initially projected, we suspended future contributions to Cimarron and agreed with our partner to abandon the project. We conducted an impairment analysis resulting in recognition of an impairment charge of $16.0 million to reduce the carrying value of our investment in Cimarron to its estimated fair value at December 31, 2018. In November 2019, we acquired the remaining 50% interest in Cimarron and consolidated this entity thereafter.

Impairment of property and equipment and intangible assets

The sales price per the KFM PSA is $88.0 million (with a January 1, 2020 effective date) for substantially all of our midstream property and equipment, resulting in total impairment expense of $348.6 million during 2019.

In the fourth quarter of 2018, we performed a quantitative assessment of our Midstream property and equipment and intangible assets, which included the use of an income approach which determined that the future undiscounted cash flows associated with our Midstream long-lived assets and intangible assets were below the combined carrying value of those assets. The cash flows used in the income approach were largely determined based on expected future gathering volumes which are dedicated to our gathering and processing facilities and are considered Level 3 inputs. We also considered the overall utilization of the processing plant and applied downward adjustments to the cost approach to account for decreased plant utilization. Based on an estimate of fair value using a discounted cash flow income approach, we determined that the carrying value of our Midstream property and equipment was in excess of its fair value and that the intangible assets were fully impaired at December 31, 2018. Accordingly, we recognized impairment charges in 2018 of $68.4 million to reduce the carrying value of our Midstream property and equipment to fair value and $395.0 million to reduce the remaining carrying value of our intangible assets to zero.

Impairment of goodwill

We performed a quantitative assessment to determine if the goodwill attributable to the Midstream segment was impaired as of December 31, 2018. Our assessment included the use of (i) an income approach to calculate the present value of estimated future discounted cash flows and (ii) a market approach to assess the value of the Midstream segment based on market participant multiples applied to the segment’s 2019 estimated cash generation. The cash flows used in the income approach were largely determined based on expected future production volumes of our Upstream segment, much of which is dedicated to the Midstream segment’s gathering and processing facilities. The income approach also used a market participant-based discount rate. Each of our assumptions regarding earnings, cash flows and discount rates were based mainly on Level 3 unobservable inputs. The results from the income approach and the market approach were appropriately weighted to recognize an impairment charge to eliminate the remaining carrying value of our goodwill.

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SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	56,683		$	52,017		$	1,145
Cash paid for income taxes	706			1,573			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	853			5,665			—
Increase (decrease) in accruals or payables for capital expenditures	(155,681		)	39,997			4,896
Increase in withholding tax accruals for share-based compensation	142			534			—
Distribution of non-STACK assets, net of liabilities	—			—			43,482
Equity issued in Business Combination	—			2,067,393			—
Release of common stock from possible redemption	—			996,384			—
Other	78			(6		)	—

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STOCKHOLDERS' EQUITY AND PARTNERS' CAPITAL (Details)	11 Months Ended	12 Months Ended
	Dec. 31, 2018 USD ($) shares	Dec. 31, 2019 director vote $ / shares shares	Dec. 31, 2018 USD ($) shares	Aug. 31, 2018 USD ($)
Class of Warrant or Right [Line Items]
Voting percentage for election of directors		50.00%
Number of directors that may be elected (director) | director		5
Share repurchase program, authorized amount | $				$ 50,000,000.0
Price paid for the shares repurchased | $	$ 14,750,000
Warrants outstanding (in shares)		62,966,651
Noncontrolling interest		55.80%
Public Warrants
Class of Warrant or Right [Line Items]
Warrants outstanding (in shares)		34,499,985
Number of shares called by each warrant (in shares)		1
Warrant exercise price per share (in dollars per share) | $ / shares		$ 11.50
Private Placement
Class of Warrant or Right [Line Items]
Warrants issued (in shares)		15,133,333
Forward Purchase Warrants
Class of Warrant or Right [Line Items]
Shares issued during period (in shares)		13,333,333
SRII Opco, LP
Class of Warrant or Right [Line Items]
Noncontrolling interest	53.00%	52.25%	53.00%
Paid-In Capital
Class of Warrant or Right [Line Items]
Price paid for the shares repurchased | $	$ 25,589,000
Common Class A
Class of Warrant or Right [Line Items]
Number of votes for each share of common stock (votes) | vote		1
Shares sold (in shares)			3,101,510
Common stock, shares outstanding (in shares)	180,072,227	182,774,952	180,072,227
Common Class A | Alta Mesa Contributor
Class of Warrant or Right [Line Items]
Conversion of common shares (in shares)	2,752,312	2,181,600
Common Class A | Kingfisher Contributor
Class of Warrant or Right [Line Items]
Conversion of common shares (in shares)	9,588,764
Common Class A | SRII Opco, LP
Class of Warrant or Right [Line Items]
Adjustment to additional paid in capital | $	$ 10,800,000
Common Class A | Alta Mesa Holdings GP, LLC
Class of Warrant or Right [Line Items]
Percentage of economic interest held		100.00%
Common Class A | Paid-In Capital
Class of Warrant or Right [Line Items]
Price paid for the shares repurchased | $			$ 14,800,000
Common Class C
Class of Warrant or Right [Line Items]
Shares issued during period (in shares)		213,402,398
Common stock, shares outstanding (in shares)	202,169,576	199,987,976	202,169,576
Common Class C | Kingfisher Contributor
Class of Warrant or Right [Line Items]
Conversion of common shares (in shares)	12,341,076	2,181,600
Preferred Class A
Class of Warrant or Right [Line Items]
Number of directors that may be elected (director) | director		2
Preferred stock, shares outstanding (in shares)	2	2	2
Period for election of directors		5 years
Preferred Class A | Bayou City
Class of Warrant or Right [Line Items]
Preferred stock, shares outstanding (in shares)		1
Preferred Class B
Class of Warrant or Right [Line Items]
Number of directors that may be elected (director) | director		3
Preferred stock, shares outstanding (in shares)	1	1	1
Period for election of directors		5 years
Common Class B | Alta Mesa Holdings GP, LLC
Class of Warrant or Right [Line Items]
Percentage of voting interest held		100.00%
Common Class B | Alta Mesa Holdings GP, LLC | SRII Opco, LP
Class of Warrant or Right [Line Items]
Percentage of economic interest held		90.00%
Percentage of voting interest held		10.00%

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CHAPTER 11 PROCEEDINGS (Tables)

12 Months Ended

Dec. 31, 2019

Reorganizations [Abstract]

Schedule of Liabilities Subject to Compromise

Following are the components of liabilities subject to compromise:

(in thousands)	December 31, 2019
Alta Mesa RBL	$	355,943
2024 Notes	500,000
Accounts payable and accrued liabilities	20,315
Accrued interest payable on 2024 Notes	9,516
Operating lease liabilities	11,088
Liabilities subject to compromise	$	896,862

Schedule of Reorganization Items

Components of reorganization items, net included are:

(in thousands)	Year Ended December 31, 2019
Unamortized deferred financing fees and premiums	$	24,725
Terminated contracts	1,435
Legal and other professional advisory fees	(26,357		)
Reorganization items, net	$	(197	)

Schedule Of Debtor In Possession

Combined Statement of Operations

(in thousands)	Year Ended December 31, 2019
Revenue
Oil	$	328,386
Natural gas	53,693
Natural gas liquids	40,026
Other	1,471
Operating revenue	423,576
Gain on sale of assets	1,488
Loss on derivatives	(11,744		)
Total revenue	413,320
Operating expenses
Lease operating	79,884
Transportation and marketing	70,324
Production taxes	19,455
Workovers	2,652
Exploration	52,354
Depreciation, depletion and amortization	120,617
Impairment of assets	556,427
General and administrative	71,823
Total operating expenses	973,536
Operating income	(560,216		)
Other income (expenses)
Interest expense	(49,823		)
Interest income	154
Reorganization items, net	(197		)
Total other income (expense), net	(49,866		)
Loss from continuing operations before income taxes	(610,082		)
Income tax provision (benefit)	—
Net loss	$	(610,082	)

Combined Balance Sheet

(in thousands)	December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	81,669
Restricted cash	681
Accounts receivable, net	49,256
Other receivables	1,311
Related party receivables, net	17,586
Prepaid expenses and other current assets	6,340
Total current assets	156,843
Property and equipment, net
Oil and gas properties, successful efforts method	215,352
Other property and equipment	23,210
Total property and equipment, net	238,562
Other assets
Investment in subsidiary	1,505,533
Operating lease right-of-use assets, net	—
Deferred financing costs, net	—
Deposits and other long-term assets	6,116
Total other assets	1,511,649
Total assets	$	1,907,054
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	58,858
Accounts payable - related parties	19,425
Advances from non-operators	811
Advances from related party	3,175
Asset retirement obligations, current portion	34
Total current liabilities	82,303
Long-term liabilities
Asset retirement obligations, net of current portion	12,995
Total long-term liabilities	12,995
Liabilities subject to compromise	896,862
Total liabilities	992,160
Partners’ capital	914,894
Total liabilities and partners’ capital	$	1,907,054

Combined Statement of Cash Flows

(in thousands)	Year Ended December 31, 2019
Cash flows from operating activities:
Net loss	$	(610,082	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	120,617
Non-cash lease expense	2,981
Provision for uncollectible receivables	1,218
Impairment of assets	556,427
Non-cash reorganization items, net	(26,160		)
Amortization of deferred financing costs	195
Amortization of debt premium	(3,432		)
Equity-based compensation expense	5,718
Non-cash exploration expense	43,412
(Gain) loss on derivatives	11,744
Cash settlements of derivatives	7,642
Cash paid for derivatives	(1,906		)
Impact on cash from changes in:
Accounts receivable	18,783
Other receivables	4,957
Related party receivables	3,651
Prepaid expenses and other assets	(25,716		)
Advances from related party	(6,647		)
Settlement of asset retirement obligations	(234		)
Accounts payable, accrued liabilities and other liabilities	22,373
Operating lease obligations	(2,636		)
Cash from operating activities	122,905
Cash flows from investing activities:
Capital expenditures	(249,955		)
Distribution received from subsidiary	691
Cash from investing activities	(249,264		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	199,362
Repayments of long-term debt	(4,496		)
Payment of taxes withheld on equity-based compensation awards	(142		)
Cash from financing activities	194,724
Net increase in cash, cash equivalents and restricted cash	68,365
Cash, cash equivalents and restricted cash, beginning of period	13,985
Cash, cash equivalents and restricted cash, end of period	$	82,350

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

Gathering Agreements

On August 31, 2015, Alta Mesa’s wholly owned subsidiary Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM. The Gas Gathering and Processing Agreement was subsequently amended in February 2017, effective December 2016, and again in June 2018, effective April 2018. The more recent amendment to the Gas Gathering and

Processing Agreement impacts our ability to make elections with respect to the NGL portion of our production volumes but has no other effect on our consolidated financial statements.

Employees

David McClure, our former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of approximately $769,000, $1,158,000, and $29,000 for the year ended December 31, 2019, the 2018 Successor Period, and the 2018 Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019.

Bayou City Joint Development Agreement

In January 2016, 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 Alta Mesa’s drilling operations and to allow Alta Mesa to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provided opportunities for the parties to potentially agree to an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of Alta Mesa’s working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. In exchange for funding the drilling and completion costs, BCE received 80% of our working interest in each wellbore, which BCE interest would be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, Alta Mesa and BCE would each bear its respective proportionate working interest share of all subsequent operating costs related to such joint well.  Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depended on a number of factors outside his control and is not known at this time.  During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA, a portion of which was refunded during the 2018 Successor Period. As of December 31, 2019, 61 joint wells have been drilled or spudded. As of December 31, 2019 and December 31, 2018, $3.2 million and $9.8 million, respectively of revenue payable liabilities 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 consolidated balance sheets. No new wells were drilled in 2019 under the JDA and as of December 31, 2019, there were no funded horizontal wells in progress, and none were developed in 2020. 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. The JDA expired in January 2020 pursuant to its terms.

BCE-Mach III LLC

BCE-Mach III LLC, a Delaware limited liability company formed by Bayou City Energy Management, LLC, a related party, and Mach Resources LLC, is the buyer of our assets pursuant to the Sale Transactions, which we expect to close no later than mid-April 2020.

High Mesa - Promissory Notes

In September 2017, Alta Mesa entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC, which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured in February 2019. At December 31, 2019 and 2018, amounts due under the promissory note totaled $1.7 million. HMS defaulted under the terms of that promissory note when it was not paid when due on February 28, 2019, and HMS has failed to cure such default. Alta Mesa subsequently declared all amounts owing under the note immediately due and payable. Alta Mesa also has an $8.5 million promissory 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. As of December 31, 2019 and 2018, the note receivable amounted to $11.7 million. HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to Alta Mesa. We oppose HMI’s claims and believe HMI’s obligation under the notes to be valid assets of Alta Mesa and that the full amount is payable to Alta Mesa. We are pursuing remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. As a result of the potential conflict of interest of certain of our directors who are also controlling holders and directors of HMI, our disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2019, we have an allowance for doubtful accounts for the promissory notes totaling $13.4 million, the expense for which is included in general and administrative expense in 2018.

Interest income on the promissory notes amounted to approximately $0.9 million and $0.1 million for the 2018 Successor Period and the 2018 Predecessor Period, respectively, all recorded as paid-in-kind and added to the balance due thereunder. Due to our assessment of collectability, we did not recognize interest income related to this receivable in 2019.

High Mesa - Management Services Agreement

In connection with the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Under the HMI 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 HMI Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the HMI 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 Alta Mesa 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 HMI Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the HMI Agreement, and pursuant to the HMI Agreement have reflected these costs as “Related party receivables” in the balance sheets. As of December 31, 2019 and December 31, 2018, we had receivables of approximately $9.8 million and $10.1 million, respectively, for costs and expenses incurred on HMI’s behalf. During 2019, we billed HMI $0.8 million for incremental costs incurred and have received approximately $1.1 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. We are pursuing remedies under applicable law in connection with repayment of this receivable.

We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. As a result, at December 31, 2019 and December 31, 2018, we had allowances for uncollectible accounts of $9.8 million and $9.0 million, respectively, to fully provide for the unremitted balance. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities and expect such liabilities, if any, to be addressed in connection with our pending bankruptcy proceedings.

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BUSINESS SEGMENT INFORMATION (Schedule Of Results Of Reportable Segments) (Details) - USD ($)		1 Months Ended		10 Months Ended	11 Months Ended	12 Months Ended
	Nov. 13, 2019	Nov. 30, 2019	Feb. 08, 2018	Nov. 13, 2019	Dec. 31, 2018	Dec. 31, 2019
Revenue
Operating revenue			$ 40,136,000		$ 473,473,000	$ 500,220,000
Gain on sale of assets			840,000		4,751,000	1,382,000
Gain (loss) on derivatives			6,663,000		(10,247,000)	(11,744,000)
Total revenue			47,639,000		467,977,000	489,858,000
Operating expenses
Lease operating			4,408,000		56,827,000	63,755,000
Transportation, processing and marketing			3,725,000		19,293,000	21,042,000
Midstream operating			0		15,221,000	24,719,000
Cost of sales for purchased gathered production			0		31,247,000	34,529,000
Production taxes			953,000		16,865,000	19,455,000
Workovers			423,000		5,563,000	3,189,000
Exploration			7,003,000		34,085,000	52,354,000
Depreciation, depletion and amortization			11,670,000		160,942,000	132,292,000
Impairment of assets					3,205,051,000	905,293,000
General and administrative			21,234,000		131,052,000	107,655,000
Total operating expenses			49,416,000		3,676,146,000	1,364,283,000
Operating income			(1,777,000)		(3,208,169,000)	(874,425,000)
Other income (expense)
Interest expense			(5,511,000)		(43,296,000)	(61,459,000)
Interest income and other			172,000		2,049,000	243,000
Equity in earnings of unconsolidated subsidiaries			0	$ 713,000	0	6,216,000
Reorganization items, net			0		0	(197,000)
Total other income (expense), net			(5,339,000)		(41,247,000)	(55,197,000)
Income (loss) from continuing operations before income taxes			(7,116,000)		(3,249,416,000)	(929,622,000)
Interest expense			(5,511,000)		(43,296,000)	(61,459,000)
Depreciation, depletion and amortization			11,670,000		160,942,000	132,292,000
Loss on unrealized hedges						19,386,000
Gain on unrealized hedges					(28,714,000)
Loss on sale of property and equipment					388,000	106,000
Impairment assets					3,205,051,000	905,293,000
Provision for uncollectible related party receivables					22,438,000	3,196,000
Equity-based compensation			0		22,025,000	6,412,000
Exploration			7,003,000		34,085,000	52,354,000
Severance costs						7,027,000
Strategic costs						21,620,000
Non-cash lease operating expense						3,835,000
Adjustment of investment in Cimarron to fair value based on assets received	$ 5,503,000	$ 5,500,000				(5,503,000)
Business Combination					23,717,000
Adjusted EBITDAX					233,812,000	278,052,000
Equity method investment	$ 7,316,000		0	$ 7,316,000	1,100,000	0
Capital expenditures			36,695,000		762,760,000	327,567,000
Total assets at period end					1,357,830,000	498,580,000
Oil
Revenue
Operating revenue			30,972,000		323,299,000	328,386,000
Natural gas
Revenue
Operating revenue			4,276,000		43,407,000	53,693,000
Natural gas liquids
Revenue
Operating revenue			4,000,000		43,039,000	40,026,000
Sales of gathered production
Revenue
Operating revenue			0		31,506,000	37,195,000
Gathering and processing
Revenue
Operating revenue					27,460,000	30,590,000
Segment Operating Revenue
Revenue
Operating revenue					468,711,000	489,890,000
Other
Revenue
Operating revenue			$ 888,000		4,762,000	10,330,000
Operating Segments | Upstream
Revenue
Operating revenue					414,507,000	423,576,000
Gain on sale of assets					4,751,000	1,488,000
Gain (loss) on derivatives					(10,247,000)	(11,744,000)
Total revenue					409,011,000	413,320,000
Operating expenses
Lease operating					60,547,000	79,884,000
Transportation, processing and marketing					50,038,000	70,324,000
Midstream operating					0	0
Cost of sales for purchased gathered production					0	0
Production taxes					16,865,000	19,455,000
Workovers					5,563,000	2,652,000
Exploration					34,085,000	52,354,000
Depreciation, depletion and amortization					133,554,000	120,617,000
Impairment of assets					2,033,712,000	556,427,000
General and administrative					114,735,000	59,897,000
Total operating expenses					2,449,099,000	961,610,000
Operating income					(2,040,088,000)	(548,290,000)
Other income (expense)
Interest expense					(38,265,000)	(49,823,000)
Interest income and other					1,983,000	154,000
Equity in earnings of unconsolidated subsidiaries						0
Reorganization items, net						449,000
Total other income (expense), net					(36,282,000)	(49,220,000)
Income (loss) from continuing operations before income taxes					(2,076,370,000)	(597,510,000)
Interest expense					(38,265,000)	(49,823,000)
Depreciation, depletion and amortization					133,554,000	120,617,000
Loss on unrealized hedges						19,386,000
Gain on unrealized hedges					(28,714,000)
Loss on sale of property and equipment					388,000	0
Impairment assets					2,033,712,000	556,427,000
Provision for uncollectible related party receivables					22,438,000	886,000
Equity-based compensation					20,000,000	5,718,000
Exploration					34,085,000	52,354,000
Severance costs						4,865,000
Strategic costs						8,116,000
Non-cash lease operating expense						3,835,000
Adjustment of investment in Cimarron to fair value based on assets received						0
Business Combination					23,717,000
Adjusted EBITDAX					201,075,000	224,068,000
Equity method investment					0	0
Capital expenditures					700,953,000	249,955,000
Total assets at period end					935,719,000	396,041,000
Operating Segments | Upstream | Oil
Revenue
Operating revenue					323,299,000	328,386,000
Operating Segments | Upstream | Natural gas
Revenue
Operating revenue					43,407,000	53,693,000
Operating Segments | Upstream | Natural gas liquids
Revenue
Operating revenue					43,039,000	40,026,000
Operating Segments | Upstream | Sales of gathered production
Revenue
Operating revenue					0	0
Operating Segments | Upstream | Gathering and processing
Revenue
Operating revenue					0	0
Operating Segments | Upstream | Segment Operating Revenue
Revenue
Operating revenue					409,745,000	422,105,000
Operating Segments | Upstream | Other
Revenue
Operating revenue					4,762,000	1,471,000
Operating Segments | Midstream
Revenue
Operating revenue					100,025,000	146,946,000
Gain on sale of assets					0	(106,000)
Gain (loss) on derivatives					0	0
Total revenue					100,025,000	146,840,000
Operating expenses
Lease operating					0	0
Transportation, processing and marketing					9,911,000	9,659,000
Midstream operating					15,221,000	24,719,000
Cost of sales for purchased gathered production					31,247,000	34,529,000
Production taxes					0	0
Workovers					0	537,000
Exploration					0	0
Depreciation, depletion and amortization					27,388,000	11,675,000
Impairment of assets					1,171,339,000	348,866,000
General and administrative					14,025,000	35,427,000
Total operating expenses					1,269,131,000	465,412,000
Operating income					(1,169,106,000)	(318,572,000)
Other income (expense)
Interest expense					(5,031,000)	(11,636,000)
Interest income and other					6,000	17,000
Equity in earnings of unconsolidated subsidiaries						6,216,000
Reorganization items, net						0
Total other income (expense), net					(5,025,000)	(5,403,000)
Income (loss) from continuing operations before income taxes					(1,174,131,000)	(323,975,000)
Interest expense					(5,031,000)	(11,636,000)
Depreciation, depletion and amortization					27,388,000	11,675,000
Loss on unrealized hedges						0
Gain on unrealized hedges					0
Loss on sale of property and equipment					0	106,000
Impairment assets					1,171,339,000	348,866,000
Provision for uncollectible related party receivables					0	2,310,000
Equity-based compensation					1,190,000	694,000
Exploration					0	0
Severance costs						2,162,000
Strategic costs						11,479,000
Non-cash lease operating expense						0
Adjustment of investment in Cimarron to fair value based on assets received						(5,503,000)
Business Combination					0
Adjusted EBITDAX					30,817,000	59,450,000
Equity method investment					1,100,000	0
Capital expenditures					61,807,000	77,612,000
Total assets at period end					437,721,000	112,825,000
Operating Segments | Midstream | Oil
Revenue
Operating revenue					0	0
Operating Segments | Midstream | Natural gas
Revenue
Operating revenue					0	0
Operating Segments | Midstream | Natural gas liquids
Revenue
Operating revenue					0	0
Operating Segments | Midstream | Sales of gathered production
Revenue
Operating revenue					31,506,000	37,195,000
Operating Segments | Midstream | Gathering and processing
Revenue
Operating revenue					68,519,000	84,763,000
Operating Segments | Midstream | Segment Operating Revenue
Revenue
Operating revenue					100,025,000	121,958,000
Operating Segments | Midstream | Other
Revenue
Operating revenue					0	24,988,000
Eliminations
Revenue
Operating revenue					(41,059,000)	(70,302,000)
Gain on sale of assets					0	0
Gain (loss) on derivatives					0	0
Total revenue					(41,059,000)	(70,302,000)
Operating expenses
Lease operating					(3,720,000)	(16,129,000)
Transportation, processing and marketing					(40,656,000)	(58,941,000)
Midstream operating					0	0
Cost of sales for purchased gathered production					0	0
Production taxes					0	0
Workovers					0	0
Exploration					0	0
Depreciation, depletion and amortization					0	0
Impairment of assets					0	0
General and administrative					2,292,000	12,331,000
Total operating expenses					(42,084,000)	(62,739,000)
Operating income					1,025,000	(7,563,000)
Other income (expense)
Interest expense					0	0
Interest income and other					60,000	72,000
Equity in earnings of unconsolidated subsidiaries						0
Reorganization items, net						(646,000)
Total other income (expense), net					60,000	(574,000)
Income (loss) from continuing operations before income taxes					1,085,000	(8,137,000)
Interest expense					0	0
Depreciation, depletion and amortization					0	0
Loss on unrealized hedges						0
Gain on unrealized hedges					0
Loss on sale of property and equipment					0	0
Impairment assets					0	0
Provision for uncollectible related party receivables					0	0
Equity-based compensation					835,000	0
Exploration					0	0
Severance costs						0
Strategic costs						2,025,000
Non-cash lease operating expense						0
Adjustment of investment in Cimarron to fair value based on assets received						0
Business Combination					0
Adjusted EBITDAX					1,920,000	(5,466,000)
Equity method investment					0	0
Capital expenditures					0	0
Total assets at period end					(15,610,000)	(10,286,000)
Eliminations | Oil
Revenue
Operating revenue					0	0
Eliminations | Natural gas
Revenue
Operating revenue					0	0
Eliminations | Natural gas liquids
Revenue
Operating revenue					0	0
Eliminations | Sales of gathered production
Revenue
Operating revenue					0	0
Eliminations | Gathering and processing
Revenue
Operating revenue					(41,059,000)	(54,173,000)
Eliminations | Segment Operating Revenue
Revenue
Operating revenue					(41,059,000)	(54,173,000)
Eliminations | Other
Revenue
Operating revenue					0	$ (16,129,000)
ASC 606 | Eliminations
Other income (expense)
Income (loss) from continuing operations before income taxes					$ 3,316

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INCOME TAXES (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax asset:
Investment in SRII Opco, LP	$ 424,086	$ 269,846
59(e) capitalized IDC	53,814	0
NOL carryforward	29,866	101,337
Organizational/startup costs	144	154
Other	7	11
Total deferred tax assets	507,917	371,348
Less: valuation allowance	(507,917)	(371,348)
Net deferred tax assets	0	0
Deferred tax liability:
Deferred tax liability	0	0
Total net deferred tax assets/(liabilities)	$ 0	$ 0

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities) (Details) - USD ($)	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
Property acquisition costs, unproved properties	$ 4,240,000	$ 54,587,000	$ 0
Property acquisition costs, proved properties	327,000	16,300,000	0
Costs incurred, exploration	3,678,000	32,130,000	7,305,000
Costs incurred, development	37,672,000	664,138,000	134,908,000
Costs Incurred, Total	45,917,000	767,155,000	142,213,000
Costs Incurred, Additional Information [Abstract]
Unproven leasehold acquisition cost		22,300,000
Additions to asset retirement obligations	$ 0	$ 5,600,000	$ 900,000

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Balance, beginning of period	$	11,552		$	—		$	10,469
Liabilities assumed in Business Combination(1)	—			5,998			—
Liabilities incurred	859			2,676			—
Liabilities settled	(234		)	(1,610		)	(63		)
Liabilities transferred in sale of properties	—			(19		)	—
Revisions to estimates	26			3,766			63
Accretion expense	980			741			40
Balance, end of period	13,183			11,552			10,509
Less: current portion	34			2,079			33
Long-term portion	$	13,149		$	9,473		$	10,476

_________________

(1)

Represents the same wells as under the Predecessor Period but valued at a higher interest rate of 10.2% compared to Predecessor interest rates ranging between 4.4% and 8.8%.

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EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS 

We sponsor a 401(k) savings plan, whereby the employees can elect to make contributions. We make matching contributions equal to 100% of the first 5% of an employee’s contributions. Employee contributions are immediately vested whereas company matching contributions typically vested 50% after two years and become fully vested after three years. Company matching contributions were approximately $1.2 million, $1.1 million, and $0.3 million for 2019, the 2018 Successor Period, and the 2018 Predecessor Period, respectively.

Due to the extent of our employee reductions and the expected Sale Transactions, we expect that all employees will receive accelerated vesting of company matching contributions as a result of a partial plan termination.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Preferred stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Common stock par value (in dollars per share)	$ 0.0001	$ 0.0001
Preferred Class A
Preferred stock, shares authorized (in shares)	1,000,000	1,000,000
Preferred stock, shares issued (in shares)	3	3
Preferred stock, shares outstanding (in shares)	2	2
Preferred Class B
Preferred stock, shares authorized (in shares)	1,000,000	1,000,000
Preferred stock, shares issued (in shares)	1	1
Preferred stock, shares outstanding (in shares)	1	1
Common Class A
Common stock, shares authorized (in shares)	1,200,000,000	1,200,000,000
Common stock, shares issued (in shares)	182,774,952	180,072,227
Common stock, shares outstanding (in shares)	182,774,952	180,072,227
Common Class C
Common stock, shares authorized (in shares)	280,000,000	280,000,000
Common stock, shares issued (in shares)	199,987,976	202,169,576
Common stock, shares outstanding (in shares)	199,987,976	202,169,576

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DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value of Derivative Contracts

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

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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

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Effect of Derivative Instruments in the Consolidated Statements of Operations

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

	Successor						Predecessor
				February 9, 2018			January 1, 2018
Derivatives not	Year Ended			Through			Through
designated as hedges	December 31, 2019			December 31, 2018			February 8, 2018
Gain (loss) on derivatives -
Oil commodity contracts	$	(16,013	)	$	(3,559	)	$	4,796
Natural gas commodity contracts	4,269			(6,688		)	1,867
Total gain (loss) on derivatives	$	(11,744	)	$	(10,247	)	$	6,663

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DESCRIPTION OF BUSINESS

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

DESCRIPTION OF BUSINESS

DESCRIPTION OF BUSINESS

Alta Mesa Resources, Inc. (“AMR”), together with its consolidated subsidiaries (“we”, “us”, “our” or “the Company”), is an independent exploration and production company focused on the development of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generates revenue primarily through long-term, fee-based contracts.

We were originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II. On March 29, 2017, we consummated our initial public offering (“IPO”). Proceeds from the IPO and a private sale of warrants were placed in a trust account and were used on February 9, 2018, to acquire the interests in Alta Mesa, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and KFM through a newly formed subsidiary, SRII Opco, LP (“SRII Opco”) in a transaction referred to as the “Business Combination” at which time we changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.”.

On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).

On January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.

The Initial and Additional Debtors continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

On December 31, 2019, the Initial Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “AMH PSA”) with BCE-Mach III LLC (the “Buyer”) pursuant to which the AMH Debtors agreed to sell to the Buyer substantially all of our upstream assets for an unadjusted purchase price of $232.0 million in cash, subject to customary purchase price adjustments (such transaction, the “AMH Sale Transaction”). On December 31, 2019, the KFM Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “KFM PSA” and, together with the AMH PSA, the “PSAs”) with the Buyer pursuant to which the KFM Debtors agreed to sell to the Buyer substantially all of our midstream assets for an unadjusted purchase price of $88.0 million in cash, subject to customary purchase price adjustments (such transaction, the “KFM Sale Transaction” and, together with the AMH Sale Transaction, the “Sale Transactions”).

The Sale Transactions are expected to close no later than mid-April 2020, after which we will no longer own any operating assets. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

In March 2020, AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the “AMR Plan”). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH’s creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A common stock and class C common stock in the Company are expected to be canceled.

The AMR Plan will be subject to approval by the Bankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent that the AMR Plan is confirmed by the Bankruptcy Court, AMR expects the AMR Plan to become effective and be consummated shortly thereafter.

In March 2020, the KFM Debtors filed a Chapter 11 plan (the “KFM Plan”). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors’ estates. Under the KFM Plan, the KFM Debtors will appoint a plan administrator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation.

The KFM Plan is subject to approval by the Bankruptcy Court and the KFM Debtors are expected to solicit votes on the KFM Plan from certain of the KFM Debtors’ creditors pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the KFM Plan in April 2020. To the extent that the KFM Plan is confirmed by the Bankruptcy Court, KFM expects the KFM Plan to become effective and be consummated shortly thereafter.

Our Class A Common Stock and public warrants to purchase Class A Common Stock, sold as part of the shares issued in the IPO, were initially traded on the NASDAQ Capital Market (“NASDAQ”), but due to our failure to continue to meet the NASDAQ’s listing requirements, trading in our stock and public warrants was suspended in September 2019, and are now traded over the counter on the OTC Pink Marketplace under the symbols “AMRQQ” and “AMRWQ”, respectively. In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.

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

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SIGNIFICANT ACQUISITIONS AND DIVESTITURES (Tables)

12 Months Ended

Dec. 31, 2019

Business Acquisition [Line Items]

Earn-out Consideration

Pursuant to the Contribution Agreements, until February 2025, the Contributors were entitled to receive additional SRII Opco Common Units as earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of our Class A Common Stock equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):

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

Alta Mesa

Business Acquisition [Line Items]

Purchase Consideration

Purchase Price for Alta Mesa

(in thousands)	February 9, 2018
Purchase Consideration: (1)
SRII Opco Common Units issued (2)	$	1,261,249
Estimated fair value of contingent earn-out purchase consideration (3)	284,109
Settlement of preexisting working capital	5,476
Total purchase price consideration	$	1,550,834

_________________

(1) The purchase price consideration was for 100% of the limited partner interests in Alta Mesa and 100% of the economic interests and 90% of the voting interests in Alta Mesa GP.  

(2) At closing, the Riverstone Contributor received 20,000,000 SRII Opco Common Units and High Mesa received 138,402,398 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, High Mesa received an additional 1,197,934 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity.

(3) For a period of seven years following Closing, High Mesa was to be entitled to receive earn-out consideration in the form of SRII Opco Common Units. We determined that the fair value of the earn-out consideration was approximately $284.1 million, which was classified as equity. The fair value of the contingent earn-out was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to the Company (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining term of the earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.

KFM Credit Facility

Business Acquisition [Line Items]

Purchase Consideration

Purchase Price for KFM

(in thousands)	February 9, 2018
Purchase Consideration:
Cash (1)	$	809,812
SRII Opco Common Units issued (2)	433,931
Estimated fair value of contingent earn-out purchase consideration (3)	88,105
Settlement of preexisting working capital	(5,476		)
Total purchase price consideration	$	1,326,372

_________________

(1) The cash consideration paid at February 9, 2018 was net of estimated net working capital adjustments, transaction expenses, capital expenditures and banking fees. Pursuant to a final closing statement during the second quarter of 2018, KFM Holdco remitted back to the Company $5.0 million in cash.

(2) At closing, KFM Holdco, LLC received 55,000,000 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, KFM Holdco remitted back 89,680 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock. The SRII Common Units were valued at approximately $7.90 per unit, reflecting discounts for holding requirements and liquidity.

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

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ADOPTION OF ASU NO. 2016-02, LEASES (Lease Costs) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 3,122
Variable lease cost	1,250
Short-term lease cost	4,410
Total lease cost	8,782
Lease operating expense
Lessee, Lease, Description [Line Items]
Total lease cost	4,241
General and administrative expense
Lessee, Lease, Description [Line Items]
Total lease cost	$ 4,541

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ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Accounts payable	$ 27,349	$ 20,422
Accruals for capital expenditures	1,244	139,904
Revenue and royalties payable	27,355	50,241
Accruals for operating expenses	25,131	21,830
Accrued interest	9,663	2,477
Derivative settlements	511	109
Other	1,716	12,456
Total accrued liabilities	65,620	227,017
Less: liabilities subject to compromise	(28,832)	0
Accounts payable and accrued liabilities	$ 64,137	$ 247,439

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CHAPTER 11 PROCEEDINGS (Reorganization Items) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Reorganizations [Abstract]
Unamortized deferred financing fees and premiums			$ 24,725
Terminated contracts			1,435
Legal and other professional advisory fees			(26,357)
Reorganization items, net	$ 0	$ 0	$ (197)

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DERIVATIVES (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivatives	$ 6,663	$ (10,247)	$ (11,744)
Derivatives Not Designated As Hedging Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivatives	6,663	(10,247)	(11,744)
Derivatives Not Designated As Hedging Instruments | Oil commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivatives	4,796	(3,559)	(16,013)
Derivatives Not Designated As Hedging Instruments | Natural gas commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivatives	$ 1,867	$ (6,688)	$ 4,269

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ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance, beginning of period	$ 10,469	$ 10,509	$ 11,552
Liabilities assumed in Business Combination	0	5,998	0
Liabilities incurred	0	2,676	859
Liabilities settled	(63)	(1,610)	(234)
Liabilities transferred via sale	0	(19)	0
Revisions to estimates	63	3,766	26
Accretion expense	40	741	980
Balance, end of period	10,509	11,552	13,183
Less: Current portion	33	2,079	34
Long-term portion	$ 10,476	$ 9,473	$ 13,149
Asset retirement obligation, measurement input, interest rates		10.20%
Minimum
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, measurement input, interest rates	4.40%
Maximum
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, measurement input, interest rates	8.80%

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CHAPTER 11 PROCEEDINGS (Cash Flows) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Cash flows from operating activities:
Net income (loss)	$ (14,862)	$ (3,249,347)	$ (929,622)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	12,554	160,942	132,292
Non-cash lease expense	0	0	3,122
Provision for uncollectible receivables	0	22,438	3,528
Impairment of assets	5,560	3,205,051	905,293
Non-cash reorganization items, net	0	0	(26,160)
Amortization of deferred financing costs	171	526	658
Amortization of debt premium	0	(4,512)	(3,432)
Equity-based compensation expense	0	22,025	6,412
Non-cash exploration expense	4,575	26,055	43,412
(Gain) loss on derivatives	(6,663)	10,247	11,744
Cash settlements of derivatives	(2,296)	(38,961)	7,642
Cash paid for derivatives	0	0	(1,906)
Impact on cash from changes in:
Accounts receivable	(21,184)	18,011	26,323
Other receivables	(662)	(4,045)	4,988
Related party receivables	(117)	(11,468)	145
Prepaid expenses and other assets	(591)	11,149	(29,078)
Advances from related party	24,116	(37,668)	(6,664)
Settlement of asset retirement obligations	(63)	(1,610)	(234)
Accounts payable, accrued liabilities and other liabilities	23,857	(41,463)	4,216
Operating lease obligations	0	0	(2,771)
Cash from operating activities	26,336	86,809	143,798
Cash flows from investing activities:
Capital expenditures	(36,695)	(762,760)	(327,567)
Cash from investing activities	(37,913)	(560,547)	(320,329)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	60,000	431,500	254,362
Repayments of long-term debt	(43,000)	(273,565)	(9,496)
Payment of taxes withheld on equity-based compensation awards	0	0	(142)
Cash from financing activities	16,932	501,205	244,724
Net increase in cash, cash equivalents and restricted cash	5,355	27,467	68,193
Cash, cash equivalents and restricted cash, beginning of period	4,990	10,345	27,855
Cash, cash equivalents and restricted cash, end of period	$ 10,345	27,855	96,048
Debtor-In-Possession
Cash flows from operating activities:
Net income (loss)			(610,082)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization			120,617
Non-cash lease expense			2,981
Provision for uncollectible receivables			1,218
Impairment of assets			556,427
Non-cash reorganization items, net			(26,160)
Amortization of deferred financing costs			195
Amortization of debt premium			(3,432)
Equity-based compensation expense			5,718
Non-cash exploration expense			43,412
(Gain) loss on derivatives			11,744
Cash settlements of derivatives			7,642
Cash paid for derivatives			(1,906)
Impact on cash from changes in:
Accounts receivable			18,783
Other receivables			4,957
Related party receivables			3,651
Prepaid expenses and other assets			(25,716)
Advances from related party			(6,647)
Settlement of asset retirement obligations			(234)
Accounts payable, accrued liabilities and other liabilities			22,373
Operating lease obligations			(2,636)
Cash from operating activities			122,905
Cash flows from investing activities:
Capital expenditures			(249,955)
Distribution received from subsidiary			691
Cash from investing activities			(249,264)
Cash flows from financing activities:
Proceeds from long-term debt borrowings			199,362
Repayments of long-term debt			(4,496)
Payment of taxes withheld on equity-based compensation awards			(142)
Cash from financing activities			194,724
Net increase in cash, cash equivalents and restricted cash			68,365
Cash, cash equivalents and restricted cash, beginning of period			13,985
Cash, cash equivalents and restricted cash, end of period		$ 13,985	$ 82,350

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Capitalized Costs Relating to Oil and Natural Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
Proved properties	$ 2,239,444	$ 2,110,346
Unproved properties	813,310	816,282
Total	3,052,754	2,926,628
Accumulated depreciation, depletion, amortization and impairment	(2,837,402)	(2,163,291)
Net capitalized costs	$ 215,352	$ 763,337

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BUSINESS SEGMENT INFORMATION (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019 segment
Segment Reporting [Abstract]
Number of reportable segments	2

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INCOME TAXES (Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Federal income tax expense (benefit) - at statutory rate		$ (682,378)	$ (195,221)
State income taxes - net of federal income tax benefit		(154,022)	(44,064)
Non-controlling interest		833,239	123,316
Return to provision		(71)	(1,690)
Change in valuation allowance		3,135	136,568
Permanent items		25	0
Other		3	(18,909)
Income tax expense (benefit)	$ 0	$ (69)	$ 0
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal income tax expense (benefit) - at statutory rate		21.00%	21.00%
State income taxes - net of federal income tax benefit		4.74%	4.74%
Non-controlling interest		(25.64%)	(13.27%)
Return to provision		0.00%	0.18%
Change in valuation allowance		(0.10%)	(14.69%)
Permanent items		0.00%	0.00%
Other		0.00%	2.04%
Income tax expense (benefit)		0.00%	0.00%

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EQUITY METHOD INVESTMENT

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INVESTMENT

EQUITY METHOD INVESTMENT

In May 2018, a subsidiary of KFM entered into agreements with a third party to jointly construct and operate a new crude oil pipeline via creation of Cimarron that we accounted for under the equity method. Cimarron’s proposed pipeline was to extend from our processing plant to Cushing, Oklahoma and was to be constructed and operated by Cimarron, which we determined was controlled by the third-party. During 2018, we invested $17.1 million in Cimarron, but at December 31, 2018, based on our decision to ultimately abandon the project, we reduced our investment to fair value, which we determined was our portion of the estimated cash remaining at Cimarron after satisfaction of liabilities.

In November 2019, Cimarron redeemed its 50% membership interest from the third party for one-half of the remaining cash in Cimarron plus an immaterial amount of other equipment. As a result, we adjusted our preacquisition equity method investment to the fair value of the residual assets remaining in Cimarron, consisting primarily of cash. This resulted in our recognition of a gain of $5.5 million, which is included in “Equity in earnings of unconsolidated subsidiaries” in our consolidated statements of operations. Following this transaction, Cimarron became our wholly owned subsidiary.

Activity in our equity method investment was as follows:

(in thousands)
Balance, as of February 9, 2018	$	—
Capital contributions	17,063
Impairment	(15,963		)
Balance, as of December 31, 2018	1,100
Equity in earnings through November 13, 2019	713
Adjustment of investment in Cimarron to fair value based on assets received	5,503
Ending balance before obtaining control	$	7,316

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Commitments

Firm Natural Gas Transportation Commitments  

We have entered into certain firm commitments intended to secure capacity on third party pipelines for transportation of natural gas that extend through 2036 with the following remaining minimum commitments at December 31, 2019:

໿

(in thousands)	Upstream		Midstream(1)		Total
2020	$	12,236	$	6,116	$	18,352
2021	12,236		6,116		18,352
2022	12,236		5,859		18,095
2023	12,236		5,676		17,912
2024	5,666		5,676		11,342
Thereafter	19,358		64,328		83,686
	$	73,968	$	93,771	$	167,739

_________________

(1) Total cash payments required for committed capacity in MMBtus of 45,750,000 in 2020, 45,625,000 in 2021, 40,275,000 in 2022, 36,500,000 in 2023, 36,600,000 in 2024 and 413,850,000 thereafter. KFM does not currently utilize the full amount of contracted capacity but strives to release capacity to third parties to attempt to minimize the under-utilization.

Other Commitments

KFM has entered into 2 commitments with other midstream providers with the following significant terms:

• An annual commitment for 3,650,000 mcf of processing volumes that runs through December 31, 2021. KFM is required to pay $0.85 per mcf for any shortfall volumes. Volumes processed under this contract are sold to the processor at market value after processing. KFM has entered into an agreement with Alta Mesa whereby Alta Mesa will reimburse KFM for half of the expenses associated with any shortfall.

• A commitment for approximately $128,000 per month of processing services that runs through December 31, 2021. Although there are no associated volumetric minimums, KFM is required to pay for the value of any shortfall from the approximately $128,000 monthly fee. Any volumes processed under this contract are sold to the processor at prevailing market prices after processing.

Pursuant to the expected Sale Transactions, we anticipate certain of these firm and other commitments will be assumed by the Buyer. As part of the Chapter 11 proceedings any remaining commitments will be rejected by the Bankruptcy Court.

Contingencies

Environmental claims

Various landowners have sued Alta Mesa in lawsuits concerning several fields in which Alta Mesa’s subsidiaries have, or historically had, operations.  The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from its oil and gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims as of December 31, 2019.

Litigation

On January 30, 2019, the Company, James T. Hackett, our then interim Chief Executive Officer and Chairman of the Board, certain of our former and current directors, Thomas J. Walker, our former Chief Financial Officer, and Riverstone Investment Group LLC were named as defendants in a putative securities class action filed in the United States District Court for the Southern District of New York (“SDNY Complaint”). The plaintiff, Plumbers and Pipefitters National Pension Fund, alleges that the defendants disseminated a false and misleading proxy statement in connection with the Business Combination and, therefore, violated Section 14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 14-9 promulgated thereunder. In addition, the plaintiff alleges that Riverstone and the individual defendants violated Section 20(a) of the Exchange Act. The plaintiff is seeking compensatory and/or rescissory damages against the defendants. The District Court transferred this action to the U.S. District Court for the Southern District of Texas.

On March 14 and 19, 2019, two additional putative securities class action complaints were filed in the U.S. District Court for the Southern District of Texas (“SDTX Complaints”) against the same defendants named in the SDNY Complaint, and Harlan H. Chappelle, our former President and Chief Executive Officer, and Michael A. McCabe, our former Chief Financial Officer. These complaints include the same claims asserted in the initial complaint, but also add claims under Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder against us and certain of our current and former officers and directors on behalf of all persons or entities who purchased or otherwise acquired Silver Run or AMR securities between March 24, 2017, and February 25, 2019. The new claims are based upon alleged misstatements contained in our proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants.

On December 19, 2019, the U.S. District Court for the Southern District of Texas consolidated the three putative securities class action lawsuits into a single action. On January 16, 2020, the Court entered a stipulated order appointing Plumbers and Pipefitters National Pension Fund and the First New York Group (consisting of FNY Partners Fund LP, FNY Managed Accounts LLC, and Paul J. Burbach) as co-lead plaintiffs and appointing Camelot Event Driven Fund as an additional consolidated class representative. The amended Consolidated Putative Securities Class Action complaint is due March 16, 2020. The commencement of the Chapter 11 proceedings automatically stayed these actions against the Company.

The outcome of the above consolidated class actions is uncertain, and while we believe that we have valid defenses to the plaintiff’s claims and intend to defend the lawsuits vigorously, no assurance can be given as to the outcome of the lawsuits.

On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to KFM in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants.  We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves. The Mustang litigation was automatically stayed on the commencement of the Chapter 11 proceedings.

Mustang filed an adversary proceeding (Mustang Gas Products LLC v. Oklahoma Energy Acquisitions, LP et al., Adversary Proceeding No. 20-03015 (Bankr. S.D. Tex.)) against Oklahoma Energy Acquisitions, LP (“OEA”) and other defendants on January 20, 2020, alleging that gas dedication covenants running with the land have a value of not less than $37 million, and entitle Mustang to a corresponding portion of the proceeds of the forthcoming sale of all or substantially all of OEA’s assets. OEA denies these allegations and intends to defend the case vigorously. OEA’s time to respond to Mustang’s complaint has been extended until 15 days after the bankruptcy court enters an order on the pending motion to dismiss filed by the Administrative Agent to the Alta Mesa RBL. It is not possible at this stage of the case to estimate the likelihood of an unfavorable outcome or the range of damages that may be awarded.

In August 2017, Biloxi Marsh Lands (“Biloxi”) filed suit in the 34th District Court for the Parish of St. Bernard, Louisiana, against Meridian Resource & Exploration LLC (“Meridian”, a subsidiary of HMI), Alta Mesa, and other defendants.  Biloxi alleges negligent construction, installation, maintenance, use and operation of a pipeline. In lieu of litigating corporate structure allegations and to reduce potential litigation expenses, Alta Mesa stipulated with respect to Biloxi that it would be bound by and assume liability and responsibility for any unpaid debts, obligations or final judgments that may be entered against Meridian in favor of Biloxi in this matter. However, these allegations relate to non-STACK oil and gas assets that Alta Mesa distributed to a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Consequently, we believe that any potential damages incurred by Alta Mesa or Meridian as a result of these allegations are the responsibility of HMI. There is no guarantee that HMI will pay any settlement amounts or judgments rendered against Alta Mesa or Meridian. In addition, Alta Mesa’s ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI, which recently filed for relief under Chapter 7 of the Bankruptcy Code in the Bankruptcy Court. The commencement of the Chapter 11 proceedings automatically stayed these against the Company. 

SEC Investigation

The SEC is conducting a formal investigation into, among other things, the facts involved in the fair value measurements used in accounting for the Business Combination and the impairment charge recognized during 2018. We are cooperating with this investigation. At this point we are unable to predict the timing or outcome of this investigation. If the SEC determines that violations of the federal securities laws have occurred, the agency has a broad range of civil penalties and other remedies available, some of which, if imposed on us, could be material to our business, financial condition or results of operations.

Other contingencies

We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business, the outcomes of which 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, the Company 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.

Performance appreciation rights.

Our Predecessor had a plan that was intended to provide incentive compensation to key employees and consultants. We canceled all amounts due under the plan at the time of the Business Combination, but recognized and paid $10.9 million as strategic costs in G&A during the 2018 Successor Period.

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INTANGIBLE ASSETS (Tables)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Customer Relationships

(in thousands)	December 31, 2018
Customer contracts and relationships acquired	$	414,150
Accumulated amortization and impairment	(414,150		)
Intangibles, net	$	—

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Bankruptcy Accounting

As discussed further in Note 3, on September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Initial Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on our statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy process have been classified as “liabilities subject to compromise” on our balance sheet at December 31, 2019. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. The accompanying financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on stockholders’ deficit accounts of any changes that may be made to our capitalization; or (iv) the effect on operations of any changes that may be made to our business. While operating as debtor-in-possession under Chapter 11 of the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected on its consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications on our historical financial statements.

Also, as described further in Note 3, on January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases. The Additional Debtors also continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

Ability to Continue as a Going Concern

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.

As described further in Note 1, we expect to sell substantially all of our assets no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.

Basis of Accounting and Presentation

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  We had no items of other comprehensive income during any period presented. Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation, but had no impact on net income (loss), stockholders’ equity or partners’ capital.  

As a result of the Business Combination, we are the acquirer for accounting purposes and Alta Mesa and KFM are the acquirees. The identifiable assets acquired and liabilities assumed were recorded at their estimated fair values, which were pushed down to each entity. As a result, our financial statements and certain footnotes separate our presentation into two distinct periods, the periods before the consummation of the Business Combination (“Predecessor Periods”) and the period after that date (the “Successor Period”). Our financial statements reflect Alta Mesa as the “Predecessor” for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, reflecting the consolidation of Alta Mesa and KFM beginning on February 9, 2018. The period January 1, 2018 to February 8, 2018 is referred to as the 2018 Predecessor Period. The 2018 Predecessor Period and the periods prior to January 1, 2018 are collectively referred to as the “Predecessor Periods”.

As noted above, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa in connection with the closing of the Business Combination. We determined the non-STACK oil and gas assets and related liabilities are discontinued operations during the Predecessor Periods and have segregated their financial information from ours in the financial statements.

Principles of Consolidation

The financial statements include the accounts of the Company and its subsidiaries, and eliminate all intercompany transactions and balances. The Company’s interests in oil and gas upstream ventures and partnerships are proportionately consolidated. Noncontrolling interest (“NCI”) represents third-party ownership interests in SRII Opco and is presented as a component of equity. The portion of SRII Opco earnings that are not attributable to the Company are separately presented in our statements of operations.

Segment Reporting (Successor) 

We operate in two reportable business segments: (i) Upstream and (ii) Midstream. Alta Mesa conducts our Upstream activities and owns proved and unproved oil and gas properties. KFM operates our Midstream segment and owns gas gathering, processing and produced water disposal assets and crude oil gathering and transportation assets. Both segments are conducted in the United States and all revenue was derived from customers located in the United States. 

Use of Estimates

Preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported revenue and expenses during the reporting period. Estimates of reserves and their value are used to determine depletion and to conduct impairment analysis of oil and gas properties and can significantly affect future estimated cash flows utilized to assess goodwill and intangible assets for impairment. Estimating reserves has inherent uncertainty, including the projection of future rates of production and the timing of development expenditures.

Other significant estimates are utilized to determine amounts reported under GAAP related to collectibility of receivables, asset retirement obligations, federal and state taxes and contingencies. We base certain of our estimates on historical experience and various other assumptions that we believe to be reasonable. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. We regularly maintain cash balances that exceed federally insured amounts, but we have experienced no losses associated with these amounts.

Restricted Cash

Cash balances that are legally, contractually or otherwise restricted as to withdrawal or usage are considered restricted cash. As of December 31, 2019, and 2018, our restricted cash represents cash received for production where the final division of ownership is in dispute or there is unclaimed property for pooling orders in Oklahoma. 

Accounts Receivable

Our receivables arise primarily from (i) the sale of our production, (ii) joint interest owners’ portion of operating costs for properties in which we are the operator, and (iii) for midstream services provided to third-party customers. The purchasers of our production and our midstream customers are concentrated in the oil and gas industry and therefore they are similarly affected by prevailing industry conditions.  Accounts receivable are generally not collateralized.  We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties we operate and market the production.

We routinely assess the recoverability of our receivables to determine their collectibility. We establish a valuation allowance to reduce receivables to their estimated collectible amounts, based upon several factors including, our historical experience, the length of time a receivable has been outstanding, communication with customers and the current and projected financial condition of specific customers.

Property and Equipment 

Our oil and gas property is accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts to obtain a mineral interest or right in a property, including related broker and other fees. These costs are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties

and become subject to depletion, or when we abandon plans to develop leases are impaired, at which time the costs are expensed as exploration costs. Unproved properties are not subject to depletion.

Proved Oil and Gas Properties — We capitalize costs incurred to drill, complete and equip proved reserves. Proved property costs include all costs incurred to drill and equip successful exploratory wells, development wells (regardless of success), development-type stratigraphic test wells and service wells, plus costs transferred from unproved properties.

Accounting policies for Midstream and other assets include:

Other Property and Equipment — Other property and equipment, such as land, buildings, plant equipment, assets associated with produced water disposal, vehicles, office furniture and office equipment, are recorded at cost.  Maintenance, repairs and minor renewals are expensed as incurred.  Plant and equipment also includes costs for our cryogenic gas processing facility along with gas gathering pipelines and compression, including rights of way, and a crude oil gathering system and crude oil storage facility.

Other important accounting policies affecting property and equipment include:

Depreciation and Depletion — Depletion of proved oil and gas properties is computed using the unit-of-production method based upon produced volumes and estimated proved reserves. Because all of our oil and gas properties are located in a single basin, we apply depletion on a single cost center. We deplete leasehold acquisition costs and the cost to acquire proved properties (generally proved undeveloped costs) based upon total estimated proved reserves. We deplete costs to drill, complete and equip wells plus the related lease costs (generally proved developed costs) over estimated proved developed reserves. 

Through December 31, 2019, we depreciated our Midstream property and equipment using the straight-line method over the estimated useful lives of the assets, which included 35 years for our produced water disposal assets, processing plant and pipelines and 25 years for our compressors. Leasehold improvements were depreciated over the shorter of their useful lives or the term of the lease. Vehicles and office furniture and office equipment were depreciated over their estimated useful lives, ranging from three years to seven years.  As a result of the expected sale of substantially all of our assets no later than mid-April 2020, we will depreciate any assets that are not to be acquired by the Buyer over our expected wind-down period, expected to be less than one year.

Impairment — Because proved reserves have not been ascribed to unproved property, in determining whether it is impaired, we consider numerous factors including recent leasing activity, recent drilling results in the area, our geologists’ evaluation and the remaining lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated proved and unproved reserves and, combined with a market approach, estimate fair value. Our cash flow estimates for unproved reserves are reduced by additional risk-weighting factors. We then reduce the carrying amount, if higher, to estimated fair value.

We review proved oil and gas properties at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows to the carrying value. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value, which we estimate by discounting the projected future cash flows using an appropriate risk-adjusted rate.

We evaluate whether the value of all other long-lived assets, including our midstream assets, is impaired when circumstances indicate the carrying value of those assets may not be recoverable. Such circumstances could result from events such as changes in the condition of an asset, changes to planned throughput or a change in our intent to utilize the asset. The determination of recovery is based on undiscounted cash flow projections or the likely cash flow from sale of the assets compared to the carrying value of the assets. If the carrying amount exceeds undiscounted future net cash flows, we adjust the carrying amount of the assets to their estimated fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent comparable sales, estimated replacement cost, an internally-developed, market participant-based discounted cash flow analysis, an analysis from outside professional advisors or, if the long-lived asset is to be sold, utilizing the likely cash flow from sale as the best estimate of fair value.

Exploration Expense

Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired or expiring leases with no expected development, delay rentals, gains or losses on settlement of asset retirement obligations, salaries for geologically-focused employees and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well yields commercial reserves.  If the exploratory well is determined to be unsuccessful, the cost is expensed as exploration expense in the period of that determination. If the exploratory well yields commercial reserves, it is transferred to proved oil and gas properties. Exploratory well costs may continue to be capitalized for several reporting periods if the assessment of commerciality is ongoing.

Equity Method Investment

We account for investments that we do not control, but in which we can exercise significant influence, using the equity method of accounting. Such investments are originally recorded at our acquisition cost. The investment is adjusted by our proportionate share of the investee’s net income, increased by contributions made and decreased by distributions received.

We assess the carrying value of our equity method investments for impairment when indicators exist indicating an impairment may be other-than-temporary. If an impairment is deemed to be other-than-temporary, we adjust the carrying value to fair value, if lower.

In November 2019, we acquired the remaining 50% interest in Cimarron Express Pipeline, LLC (“Cimarron”), which we previously accounted for under the equity method, and consolidated this entity beginning in November 2019.

Deferred Financing Costs

Deferred financing costs reflect fees paid to lenders and third parties that are directly related to our establishment of our long term debt. Prior to the bankruptcy filing by the Initial Debtors, the costs associated with the Alta Mesa RBL were amortized over the term of the Alta Mesa RBL as additional interest expense, with the remaining unamortized costs written off to “reorganization items, net” in our statement of operations upon the bankruptcy filing. The costs associated with the KFM Credit Facility are reported as non-current assets and are amortized over the term of the KFM Credit Facility as additional interest expense but were written off in January after it filed for bankruptcy. During the Predecessor Periods, costs associated with the issuance of our 7.875% senior unsecured notes maturing in December 2024 (the “2024 Notes”) were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense. These Predecessor defined financing costs were eliminated with the Business Combination’s adjustment to 2024 Notes to fair value.

Acquisitions

Business combinations are accounted for using the acquisition method. The results of operations of any acquired businesses are included in our results of operations from the closing date. The total cost of each acquisition is allocated to tangible and intangible assets acquired and liabilities assumed based on their estimated fair values at the time of the acquisition.

Intangible Assets 

In connection with the acquisition of KFM, we recognized the estimated fair value of acquired customer contracts and related customer relationships as intangible assets, which were valued using the income approach. These intangible assets, all of which related to the Midstream segment, had finite lives and were subject to amortization utilizing an accelerated attrition method to approximate the benefit received over their economic lives.

Goodwill

We recognized goodwill as the excess of the purchase price over the estimated fair value of the identified assets and liabilities acquired in the Business Combination. Goodwill was not amortized but was subject to periodic impairment assessment at least annually, or whenever events and circumstances indicated an impairment may exist. 

Asset Retirement Obligations 

We recognize liabilities for the anticipated future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets by increasing the carrying amount of the related long-lived asset at the time it is legally incurred.  The

fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The asset retirement cost is recognized as depletion or depreciation over the life of the asset.  Accretion expense represents the increase to the discounted liability toward its expected settlement value and is included in “Depreciation, depletion and amortization” in the statements of operations.  Asset retirement obligations are subject to revision primarily for changes related to the estimated timing and cost of abandonment.

There are no material legal or contractual obligations relating to dismantlement, decommissioning or removal of our Midstream assets, other than for certain of our produced water assets, for which asset retirement obligations have been established as of December 31, 2019.

Bond Premium on 2024 Notes  

In connection with the Business Combination, we estimated the fair value of our $500.0 million 2024 Notes at $533.6 million.  The excess fair value above the face value was recognized as a bond premium, which was being amortized as a reduction in interest expense over the remaining term of the notes prior to the time of the bankruptcy filing by the Initial Debtors. The remaining unamortized premium was written off to “reorganization items, net” in our consolidated statement of operations upon the Initial Debtors’ bankruptcy filing.

Derivatives 

We present our derivatives as assets or liabilities at estimated fair value. Changes in fair value of our derivatives, along with realized gains or losses from settlements, are recognized as “Gain (loss) on derivatives” in the statements of operations. Settlements of derivatives are classified as operating cash flows. Where master netting agreements are in place, we net the value of our derivative assets and liabilities with the same counterparty.

Income Taxes

Successor

Deferred income taxes are provided for the temporary differences between the basis of assets and liabilities for financial reporting and income tax purposes. We classify deferred tax assets and liabilities as noncurrent.

We assess the ability to realize our deferred tax assets on a quarterly basis. Deferred tax assets may be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. A valuation allowance is established to reduce deferred tax assets to the amount expected to be realized when we determine that it is more likely than not that some or all of the deferred tax assets are not realizable.

We are also subject to the Texas margin tax, which is considered an income-based tax. We recognize tax (current and deferred) based on taxable income, as determined using the rules for the margin tax as a component of our income tax provision.

We assess uncertain tax positions using a two-step process. If we determine it is more likely than not that the income tax position will be sustained upon examination by the taxing authorities, we recognize the largest amount that is greater than 50% likely to be realized upon ultimate settlement. We have considered our exposure under the standard at both the federal and state tax levels. We did not record any liabilities for uncertain tax positions as of December 31, 2019 or December 31, 2018.

We record interest and penalties for the taxation, as a component of income tax expense. We did not incur any material tax interest or penalties for any period presented.

Alta Mesa’s tax returns for the years ended December 31, 2016 and forward remain open for examination, but none are currently under examination by the relevant authorities.

Predecessor

Alta Mesa historically elected to be treated as an individual partnership for tax purposes. Accordingly, its items of income, expense, gains and losses flowed through to the partners and were taxed at the partner level. Accordingly, no tax provision for federal income taxes was recognized by the Predecessor.

Predecessor net income (loss) for financial statement purposes differed significantly from taxable income (loss) reported to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under Alta Mesa’s amended and restated partnership agreement.  As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes could not be readily determined due to some tax basis differences being determined at the partner level and Alta Mesa’s lack of information about each unitholder’s tax attributes in Alta Mesa.

Revenue Recognition

Predecessor -

Oil, natural gas, and NGL revenue were recognized when production was sold to a purchaser at a fixed or determinable price, when delivery had occurred and title had transferred, and collectibility of the revenue was reasonably assured. During the Predecessor Periods, we followed the sales method of accounting for revenue. Under this method of accounting, revenue was recognized based on volumes sold. There were no material gas imbalances during the periods presented.

Successor (Upstream) -

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU and the associated subsequent amendments (collectively, “ASC 606”), superseded virtually all of the revenue recognition guidance under GAAP. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services.

Our revenue from contracts with customers includes the sale of crude oil, natural gas, and NGLs. These sales are recognized as revenue when production is sold to a customer in fulfillment of performance obligations under the terms of the underlying contracts. Performance obligations primarily comprise delivery of our production at a delivery point, as negotiated within each contract. Each unit of oil, natural gas, and NGL is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.

Performance obligations are satisfied once control of the product has been transferred to the customer. We consider a variety of facts and circumstances in assessing the point control is transferred, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, our right to payment, and transfer of legal title. Moreover, as part of the process of applying the five-step model, we also evaluated AMH’s and KFM’s arrangement in following the principal-versus-agent guidance under ASC 606. As a principal seller to the customer, revenues are recognized on a gross basis, and as an agent, revenue are recognized on a net basis.

Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price or at purchaser posted prices for the producing area. For oil contracts, AMH is considered to be the principal seller to its customers, and we record sales and related expenses on a gross basis upon satisfaction of our performance obligations.

Our natural gas production is primarily sold to purchasers at prevailing market prices. We evaluate the contract terms of our gas processing arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis based on the assessment of control and, when applicable, principal versus agent guidance under ASC 606. During the Successor Period, we determined that we controlled the products during processing (i.e., control transfers at the tailgate of the processing plant) or until the processor’s sale to the end customers in downstream markets (i.e., the processor is our agent and we are the principal selling party). Accordingly, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the customer and the gathering and processing services are rendered, similar to the accounting treatment required under previous revenue accounting guidance. However, instances in which all or a significant percentage of the proceeds from the sale must be returned to the producer, we are deemed to be the agent. As a result, the purchase and sale are presented as a net transaction with our margin included in gathering and processing revenue. When evaluating the principal-versus-agent guidance under ASC 606 and its impact on AMH and KFM, all facts and circumstances are considered and judgment is often required in making this determination.

Customers are invoiced once our performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30-60 days. There are no significant judgments that

affect the amount or timing of revenue from contracts with customers. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities, apart from production receivables.

Our receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates, as well as for unbilled costs for wells subject to Oklahoma’s forced pooling process in which mineral owners have the option to participate in the drilling of pooled wells. Depending on the mineral owner’s decision, these costs will be billed to them or added to our oil and gas properties or lease operating expense. Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts.

We have concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors and have reflected this disaggregation of revenue for all periods presented.

We do not have material unsatisfied performance obligations for contracts as all contracts have either an original expected length of one year or less or the entire future consideration is variable and allocated entirely to a wholly unsatisfied performance obligation.

Midstream -

We have the following significant revenue sources each of which we consider to be a distinct service and each of which possesses a single performance obligation:

• Natural gas gathering, processing and sale of residue gas and NGLs for Alta Mesa and third parties;

• Crude oil gathering for Alta Mesa; and

• Produced water gathering and disposal for Alta Mesa and third parties.

We provide our services pursuant to a variety of contracts that set forth our fees, including in certain contracts, the percentage of the proceeds from the sale of our customers’ products in addition to the specified fee. Our services are typically billed on a monthly basis in the month following services or delivery of the product with payment typically due within 30 days. We do not offer extended payment terms and we have no contracts with financing components. Our gathering contracts have initial terms that span multiple years up to the life of the dedicated properties. Our most significant produced water contract has an initial term of 15 years.

We recognize revenue principally under contracts that contain one or more of the following arrangements:

Fee-based arrangements

Revenue for fee-based arrangements are recognized over the contract term with revenue recognized for each month of service based on the volumes delivered by the customer. Both natural gas gathering and processing plus crude oil gathering services are recognized in gathering and processing revenues. Produced water services are recognized as produced water disposal fees.

For service rates that are unchanged over the contract term or escalate only due to inflation, we recognize revenue at the rate in effect during the month of service. We have instances where we also charge supplemental fees for an early period of time during the contract term and this revenue is recognized over the expected period of customer benefit, which is generally the remaining term of the contract. The difference between the amount billed and collected for such early term fees billed during the initial contract term and the amount recorded as revenue is deferred and recognized as contract liabilities. At December 31, 2019 and 2018, we had recognized a deferral of $3.4 million and $1.7 million, respectively, of these early term fees which is included in other long-term liabilities.

Percent-of-proceeds arrangements

Under our percent-of-proceeds arrangements, we generally receive natural gas from producers at or near the wellhead, move it through our gathering system, process it to separate the gas and liquid products and sell the resulting gas and NGLs to third parties. We then remit to the producers an agreed-upon percentage of the actual proceeds received from sales. The margins we earn are directly related to the volumes that flow through our system and the price at which we are able to sell the products.

We evaluate our percent-of-proceeds arrangements with customers against the principal/agent provisions of the underlying contract. For those arrangements where we possess control of the commodity after processing and act as principal in the sale, we record sales revenue equal to the gross price received and we recognize the cost paid to the purchaser as cost of sales of

gathered purchased production. For those percent-of-proceeds arrangements where we do not control the products after processing, because substantially all of the sales proceeds are paid to the producer, we act as an agent for the producer and only recognize the net margin that we earn within sales of gathered production.

In limited instances, we may also receive products as consideration under percent-of-proceeds agreements. We recognize revenue for the products received at their fair value in the month of service.

Sale of gathered production

We sell gas, NGLs and condensate purchased from our customers to third parties pursuant to short term arrangements at market-based prices adjusted for location and quality differentials. These sales are recognized at the point (i) when we satisfy our performance obligation by transferring control of the product to the purchaser at the specified delivery point, (ii) when amounts are determinable and (iii) when we determine that collectibility is probable. The determination of the point control is transferred relies upon a variety of facts and circumstances including: the purchaser’s ability to use the products, the transfer of significant risks and rewards, our right to payment and transfer of legal title. The cost to purchase the underlying products is recognized when we obtain control of the product, but is generally concurrent with their sale.

Also, we may sell products to other midstream companies pursuant to off-take agreements. Under these contracts, we evaluate whether we control the products during processing and whether the processor controls the products in their sale to the ultimate purchaser. For those contracts where we do not control the products during processing, we recognize revenue on their sale to the midstream company based on the price received net of processing fees earned by the midstream company. For those contracts where we control the products during processing and where we direct their sale, we recognize revenue on the gross price received within sales of gathered production and we recognize the fees paid to the midstream company as transportation, processing and marketing expense.

Equity-Based Compensation 

In 2018, we granted various types of stock-based awards, including stock options, restricted stock and performance-based restricted stock units to certain of our employees.

The fair value of stock option awards is determined using the Black-Scholes option pricing model, which includes various assumptions. Expected volatilities utilized in the option pricing model are based on the re-levered asset volatility implied by a set of comparable companies.  Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date.  Dividend yield is based on our expectations of dividend payments during the expected term of the options granted and risk-free interest rates are based on U.S. Treasury rates in effect at the grant date.

Service-based restricted stock awards are valued using the market price of our Class A Common Stock on the grant date. Performance-based restricted stock awards are valued using the market price of Class A Common Stock at the later of grant date and when all performance-based criteria are determined.

We recognize the estimated fair value of stock option and restricted stock awards as compensation expense on a straight-line basis over the applicable vesting period, which generally is 3.0 years, except in the case of awards made to our directors, which vest immediately upon issuance. Awards of performance-based restricted stock units that contain tranches with multi-year performance targets are recognized over the vesting period for which performance criteria for each tranche have been determined. All awards to employees typically require continued employment to vest. Forfeitures of unvested awards are recognized when they occur and result in the reversal of previously recognized expense.

Fair Value Hierarchy

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date within our principal market.

There are three levels of the fair value hierarchy:

• Level 1 — Fair value is based on quoted prices in active markets for identical assets or liabilities.

• Level 2 — Fair value is determined using significant observable inputs, generally either quoted prices in active markets for similar assets or liabilities, or quoted prices in markets that are not active.

• Level 3 — Fair value is determined using one or more significant inputs that are unobservable in active markets at the measurement date. Such inputs are often used in pricing models, discounted cash flow calculations, or similar techniques.

We utilize fair value measurements to account for certain items, determine certain account balances and provide disclosures. Fair value measurements are also utilized in assessing the impairment of long-lived assets.

We consider the book values of our cash, accounts and notes receivable and current liabilities to approximate fair value due to their short-term nature. Our outstanding borrowings under the Alta Mesa RBL have been classified as liabilities subject to compromise at December 31, 2019 and the outstanding borrowings under the KFM Credit Facility will be classified similarly following the January 2020 bankruptcy filing by the Additional Debtors as full recovery by our lenders following the expected sale of substantially all of our assets is unlikely.

Earnings Per Share 

Basic earnings per share is calculated by dividing earnings available to Class A common stockholders by the weighted average number of shares outstanding during each period. In periods where we report negative earnings, basic and diluted earnings per share are identical.

The Company uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding SRII Opco Common Units and corresponding shares of its outstanding Class C Common Stock, as well as outstanding warrants and the treasury stock method to determine the potential dilutive effect of restricted stock, restricted stock units and stock options.

Recently Issued Accounting Standards Applicable to Us

Adopted

As described further in Note 5, we adopted Accounting Standards Update 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, effective January 1, 2019.

Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today and would have been effective for us beginning January 2023. We made no determination as to the impact of this new standard on our financial position or results of operations upon adoption.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard, on a prospective basis, beginning January 2020.

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

XML

PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Summary of Property and Equipment and Depreciation, Depletion and Amortization

Depreciation and Depletion

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	118,003	$	129,579	$	11,021
Midstream tangible asset depreciation	11,663		8,235		—
Other property and equipment depreciation	1,646		3,236		609
Total depletion and depreciation	$	131,312	$	141,050	$	11,630

(in thousands)	December 31, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	813,310		$	816,282
Accumulated impairment of unproved properties	(813,310		)	(742,065		)
Unproved properties, net	—			74,217
Proved oil and gas properties	2,239,444			2,110,346
Accumulated depreciation, depletion, amortization and impairment	(2,024,092		)	(1,421,226		)
Proved oil and gas properties, net	215,352			689,120
Total oil and gas properties, net	215,352			763,337
Other property and equipment
Land	5,690			5,600
Fresh water wells	27,373			27,366
Produced water disposal system	108,966			104,498
Gas processing plant and gathering lines	414,615			380,470
Office furniture, equipment and vehicles	3,397			3,703
Accumulated depreciation and impairment	(453,013		)	(77,368		)
Other property and equipment, net	107,028			444,269
Total property and equipment, net	$	322,380		$	1,207,606

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Cash flows from operating activities:
Net loss	$ (14,862)	$ (3,249,347)	$ (929,622)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	12,554	160,942	132,292
Non-cash lease expense	0	0	3,122
Provision for uncollectible receivables	0	22,438	3,528
Impairment of assets	5,560	3,205,051	905,293
Non-cash reorganization items, net	0	0	(26,160)
Amortization of deferred financing costs	171	526	658
Amortization of debt premium	0	(4,512)	(3,432)
Equity-based compensation expense	0	22,025	6,412
Non-cash exploration expense	4,575	26,055	43,412
(Gain) loss on derivatives	(6,663)	10,247	11,744
Cash settlements of derivatives	(2,296)	(38,961)	7,642
Premium paid on derivatives	0	0	(1,906)
Interest converted into debt related to Founder notes	103	0	0
Interest added to notes receivable from related party	(85)	(949)	0
Loss on sale of property and equipment	1,923	388	106
Equity in earnings of unconsolidated subsidiaries	0	0	(6,216)
Impact on cash from changes in:
Accounts receivable	(21,184)	18,011	26,323
Other receivables	(662)	(4,045)	4,988
Related party receivables and payables	(117)	(11,468)	145
Prepaid expenses and other assets	(591)	11,149	(29,078)
Advances from related party	24,116	(37,668)	(6,664)
Settlement of asset retirement obligations	(63)	(1,610)	(234)
Accounts payable, accrued liabilities and other liabilities	23,857	(41,463)	4,216
Operating lease obligations	0	0	(2,771)
Cash from operating activities	26,336	86,809	143,798
Cash flows from investing activities:
Capital expenditures	(36,695)	(762,760)	(327,567)
Acquisitions, net of cash acquired	(1,218)	(823,778)	0
Proceeds withdrawn from Trust Account	0	1,042,742	0
Proceeds from (Contribution to) equity method investment and other	0	(17,063)	7,238
Proceeds from sale of assets	0	312	0
Cash from investing activities	(37,913)	(560,547)	(320,329)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	60,000	431,500	254,362
Repayments of long-term debt	(43,000)	(273,565)	(9,496)
Payment of taxes withheld on equity-based compensation awards	0	0	(142)
Deferred financing costs paid	0	(3,722)	0
Purchase and retirement of Class A common shares	0	(14,750)	0
Capital contributions (distributions)	(68)	0	0
Proceeds from issuance of Class A shares	0	400,000	0
Repayment of sponsor note	0	(2,000)	0
Repayment of deferred underwriting compensation	0	(36,225)	0
Redemption of Class A common shares	0	(33)	0
Cash from financing activities	16,932	501,205	244,724
Net increase in cash, cash equivalents and restricted cash	5,355	27,467	68,193
Cash, cash equivalents and restricted cash, beginning of period	4,990	10,345	27,855
Cash, cash equivalents and restricted cash, end of period	$ 10,345	$ 27,855	$ 96,048

XML

Cover Page - USD ($)

12 Months Ended

Dec. 31, 2019

Jan. 31, 2020

Jun. 28, 2019

Document Information [Line Items]

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2019

Document Transition Report

false

Entity File Number

001-38040

Entity Registrant Name

Alta Mesa Resources, Inc. /DE

Entity Incorporation, State or Country Code

DE

Entity Tax Identification Number

81-4433840

Entity Address, Address Line One

15021 Katy Freeway,

Entity Address, Address Line Two

Suite 400,

Entity Address, City or Town

Houston,

Entity Address, State or Province

TX

Entity Address, Postal Zip Code

77094

City Area Code

281

Local Phone Number

530-0991

Entity Current Reporting Status

Yes

Entity Voluntary Filers

No

Entity Well-known Seasoned Issuer

No

Entity Interactive Data Current

Yes

Entity Filer Category

Non-accelerated Filer

Entity Small Business

true

Entity Emerging Growth Company

false

Entity Shell Company

false

Entity Public Float

$ 16,522,531

Entity Central Index Key

0001690769

Amendment Flag

false

Document Fiscal Year Focus

2019

Document Fiscal Period Focus

FY

Current Fiscal Year End Date

--12-31

Documents Incorporated by Reference

Portions of the registrant’s definitive Proxy Statement for its 2020 annual meeting of shareholders, which will be filed with the Securities and Exchange Commission on Schedule 14A within 120 days after the end of 2019, will be incorporated by reference into Part III of this Form 10-K to the extent indicated therein upon such filing.

Common Class A

Document Information [Line Items]

Entity Common Stock, Shares Outstanding (in shares)

182,791,388

Common Class C

Document Information [Line Items]

Entity Common Stock, Shares Outstanding (in shares)

199,987,976

XML

CHAPTER 11 PROCEEDINGS (Liabilities Subject to Compromise) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long term debt	$ 855,943	$ 0
Accounts payable and accrued liabilities	20,315
Accrued interest payable on 2024 Notes	9,516
Operating lease liabilities	11,088
Liabilities subject to compromise	896,862	$ 0
2024 Notes
Debt Instrument [Line Items]
Long term debt	500,000
Alta Mesa RBL | Alta Mesa RBL
Debt Instrument [Line Items]
Long term debt	$ 355,943

XML

DERIVATIVES (Fair Values Of Derivative Contracts) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Derivatives, Fair Value [Line Items]
Gross fair value of assets	$ 30,422
Gross liabilities offset against assets in the Balance Sheet	(11,052)
Net fair value of assets presented in the Balance Sheet	19,370
Gross fair value of liabilities	12,942
Gross assets offset against liabilities in the Balance Sheet	(11,052)
Net fair value of liabilities presented in the Balance Sheet	1,890
Derivatives, current assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	22,512
Gross liabilities offset against assets in the Balance Sheet	(6,089)
Net fair value of assets presented in the Balance Sheet	16,423
Derivatives, long-term assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	7,910
Gross liabilities offset against assets in the Balance Sheet	(4,963)
Net fair value of assets presented in the Balance Sheet	2,947
Derivatives, current liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	7,799
Gross assets offset against liabilities in the Balance Sheet	(6,089)
Net fair value of liabilities presented in the Balance Sheet	1,710
Derivatives, long-term liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	5,143
Gross assets offset against liabilities in the Balance Sheet	(4,963)
Net fair value of liabilities presented in the Balance Sheet	$ 180

XML

EQUITY METHOD INVESTMENT (Details) - USD ($) $ in Thousands		1 Months Ended		10 Months Ended	11 Months Ended	12 Months Ended
	Nov. 13, 2019	Nov. 30, 2019	Feb. 08, 2018	Nov. 13, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity method investment, beginning balance				$ 1,100	$ 0	$ 1,100
Capital contributions					17,063
Impairment					(15,963)
Equity in earnings of unconsolidated subsidiaries			$ 0	713	0	6,216
Adjustment of investment in Cimarron to fair value based on assets received	$ 5,503	$ 5,500				(5,503)
Equity method investment, ending balance	$ 7,316		$ 0	$ 7,316	$ 1,100	$ 0	$ 1,100
Cimarron Express
Schedule of Equity Method Investments [Line Items]
Capital contributions							$ 17,100
Cimarron Express Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Cash		7,238
Land and rights-of-way		90
Accrued liabilities		(12)
Net assets received upon consolidation of Cimarron		$ 7,316

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CHAPTER 11 PROCEEDINGS (Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Feb. 08, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 95,367	$ 26,854
Restricted cash	681	1,001
Total accounts receivable, net	61,187	87,842
Other receivables	1,344	6,331
Related party receivables	0	3,341
Prepaid expenses and other current assets	8,047	1,125
Total current assets	166,626	142,917
Property and equipment, net
Oil and gas properties, successful efforts method	215,352	763,337
Other property and equipment	107,028	444,269
Total property and equipment, net	322,380	1,207,606
Other assets
Operating lease right-of-use assets, net	0
Deferred financing costs, net	1,581	3,195
Deposits and other long-term assets	7,993	65
Total other assets	9,574	7,307
Total assets	498,580	1,357,830
Current liabilities
Accounts payable and accrued liabilities	64,137	247,439
Advances from non-operators	811	5,193
Advances from related party	3,175	9,839
Asset retirement obligations, current portion	34	2,079	$ 33
Total current liabilities not subject to compromise	292,245	956,383
Long-term liabilities
Long-term portion	13,149	9,473	10,476
Total long-term liabilities not subject to compromise	16,698	185,320
Liabilities subject to compromise	896,862	0
Total liabilities	1,205,805	1,141,703
Noncontrolling interest	(236,628)	245,520	$ 183,065	$ 154,445
Total liabilities and stockholders’ equity	498,580	$ 1,357,830
Debtor-In-Possession
Current assets
Cash and cash equivalents	81,669
Restricted cash	681
Total accounts receivable, net	49,256
Other receivables	1,311
Related party receivables	17,586
Prepaid expenses and other current assets	6,340
Total current assets	156,843
Property and equipment, net
Oil and gas properties, successful efforts method	215,352
Other property and equipment	23,210
Total property and equipment, net	238,562
Other assets
Investment in subsidiary	1,505,533
Operating lease right-of-use assets, net	0
Deferred financing costs, net	0
Deposits and other long-term assets	6,116
Total other assets	1,511,649
Total assets	1,907,054
Current liabilities
Accounts payable and accrued liabilities	58,858
Accounts payable - related parties	19,425
Advances from non-operators	811
Advances from related party	3,175
Asset retirement obligations, current portion	34
Total current liabilities not subject to compromise	82,303
Long-term liabilities
Long-term portion	12,995
Total long-term liabilities not subject to compromise	12,995
Liabilities subject to compromise	896,862
Total liabilities	992,160
Noncontrolling interest	914,894
Total liabilities and stockholders’ equity	$ 1,907,054

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ADOPTION OF ASU NO. 2016-02, LEASES (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets, net	$ 0
Operating lease liabiliites	$ 277
Weighted-average remaining lease term (in years)	8 years
Weighted-average discount rate	14.50%
ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets, net		$ 15,400
Operating lease liabiliites		$ 15,400

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LONG-TERM DEBT, NET (Summary Of Future Maturities Of Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
2023	$ 579,943
2024	500,000
Total debt, net	$ 1,079,943	$ 864,123

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of Firm Transportation Contracts

We have entered into certain firm commitments intended to secure capacity on third party pipelines for transportation of natural gas that extend through 2036 with the following remaining minimum commitments at December 31, 2019:

໿

(in thousands)	Upstream		Midstream(1)		Total
2020	$	12,236	$	6,116	$	18,352
2021	12,236		6,116		18,352
2022	12,236		5,859		18,095
2023	12,236		5,676		17,912
2024	5,666		5,676		11,342
Thereafter	19,358		64,328		83,686
	$	73,968	$	93,771	$	167,739

_________________

(1)

Total cash payments required for committed capacity in MMBtus of 45,750,000 in 2020, 45,625,000 in 2021, 40,275,000 in 2022, 36,500,000 in 2023, 36,600,000 in 2024 and 413,850,000 thereafter. KFM does not currently utilize the full amount of contracted capacity but strives to release capacity to third parties to attempt to minimize the under-utilization.

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BUSINESS SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Schedule Of Results Of Reportable Segments

	Year Ended December 31, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations				Total
Revenue
Oil	$	328,386		$	—		$	—			$	328,386
Natural gas	53,693			—			—				53,693
Natural gas liquids	40,026			—			—				40,026
Sales of gathered production	—			37,195			—				37,195
Midstream revenue	—			84,763			(54,173		)		30,590
Segment sales revenue	422,105			121,958			(54,173		)		489,890
Other revenue	1,471			24,988			(16,129		)		10,330
Operating revenue	423,576			146,946			(70,302		)		500,220
Gain (loss) on sale of assets	1,488			(106		)	—				1,382
Gain (loss) on derivatives	(11,744		)	—			—				(11,744		)
Total revenue	413,320			146,840			(70,302		)		489,858
Operating expenses
Lease operating	79,884			—			(16,129		)		63,755
Transportation, processing and marketing	70,324			9,659			(58,941		)		21,042
Midstream operating	—			24,719			—				24,719
Cost of sales for purchased gathered production	—			34,529			—				34,529
Production taxes	19,455			—			—				19,455
Workovers	2,652			537			—				3,189
Exploration	52,354			—			—				52,354
Depreciation, depletion, and amortization	120,617			11,675			—				132,292
Impairment of assets	556,427			348,866			—				905,293
General and administrative	59,897			35,427			12,331				107,655
Total operating expenses	961,610			465,412			(62,739		)		1,364,283
Operating income	(548,290		)	(318,572		)	(7,563		)		(874,425		)
Other income (expense)
Interest expense	(49,823		)	(11,636		)	—				(61,459		)
Interest income and other	154			17			72				243
Equity in earnings of unconsolidated subsidiaries	—			6,216			—				6,216
Reorganization items, net	449			—			(646		)		(197		)
Total other income (expense)	(49,220		)	(5,403		)	(574		)		(55,197		)
Income (loss) from continuing operations before income taxes	(597,510		)	(323,975		)	(8,137		)	—	(929,622		)
Interest expense	49,823			11,636			—				61,459
Depreciation, depletion and amortization	120,617			11,675			—				132,292
Loss on unrealized hedges	19,386			—			—				19,386
Loss on sale of property and equipment	—			106			—				106
Impairment assets	556,427			348,866			—				905,293
Provision for uncollectible related party receivables	886			2,310			—				3,196
Equity-based compensation	5,718			694			—				6,412
Exploration	52,354			—			—				52,354
Severance costs	4,865			2,162			—				7,027
Strategic costs	8,116			11,479			2,025				21,620
Non-cash lease operating expense	3,835			—			—				3,835
Gain on equity method investment	—			(5,503		)	—				(5,503		)
Reorganization items, net	(449		)	—			646				197
Adjusted EBITDAX	$	224,068		$	59,450		$	(5,466	)		$	278,052
Equity method investment	$	—		$	—		$	—			$	—
Capital expenditures	249,955			77,612			—				327,567
Total assets at period end	396,041			112,825			(10,286		)		498,580

	February 9, 2018 Through December 31, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations				Total
Revenue
Oil	$	323,299		$	—		$	—			$	323,299
Natural gas	43,407			—			—				43,407
Natural gas liquids	43,039			—			—				43,039
Sales of gathered production	—			31,506			—				31,506
Midstream revenue	—			68,519			(41,059		)		27,460
Segment sales revenue	409,745			100,025			(41,059		)		468,711
Other revenue	4,762			—			—				4,762
Operating revenue	414,507			100,025			(41,059		)		473,473
Gain on sale of assets	4,751			—			—				4,751
Gain (loss) on derivatives	(10,247		)	—			—				(10,247		)
Total revenue	409,011			100,025			(41,059		)		467,977
Operating expenses
Lease operating	60,547			—			(3,720		)		56,827
Transportation, processing and marketing	50,038			9,911			(40,656		)		19,293
Midstream operating	—			15,221			—				15,221
Cost of sales for purchased gathered production	—			31,247			—				31,247
Production taxes	16,865			—			—				16,865
Workovers	5,563			—			—				5,563
Exploration	34,085			—			—				34,085
Depreciation, depletion, and amortization	133,554			27,388			—				160,942
Impairment of assets	2,033,712			1,171,339			—				3,205,051
General and administrative	114,735			14,025			2,292				131,052
Total operating expenses	2,449,099			1,269,131			(42,084		)		3,676,146
Operating income	(2,040,088		)	(1,169,106		)	1,025				(3,208,169		)
Other income (expense)
Interest expense	(38,265		)	(5,031		)	—				(43,296		)
Interest income and other	1,983			6			60				2,049
Total other income (expense)	(36,282		)	(5,025		)	60				(41,247		)
Income (loss) from continuing operations before income taxes	(2,076,370		)	(1,174,131		)	1,085			(1)	(3,249,416		)
Interest expense	38,265			5,031			—				43,296
Depreciation, depletion and amortization	133,554			27,388			—				160,942
Gain on unrealized hedges	(28,714		)	—			—				(28,714		)
Loss on sale of fixed assets	388			—			—				388
Impairment of assets	2,033,712			1,171,339			—				3,205,051
Provision for uncollectible related party receivables	22,438			—			—				22,438
Equity-based compensation	20,000			1,190			835				22,025
Exploration	34,085			—			—				34,085
Business Combination	23,717			—			—				23,717
Adjusted EBITDAX	$	201,075		$	30,817		$	1,920			$	233,812
Equity method investment	$	—		$	1,100		$	—			$	1,100
Capital expenditures	700,953			61,807			—				762,760
Total assets at period end	935,719			437,721			(15,610		)		1,357,830

_________________

(1)

Includes $3,316 for elimination of intercompany deferred revenue resulting from the adoption of ASC 606.

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DERIVATIVES (Additional Information) (Details) - USD ($) $ in Millions	1 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Contracts To be Settled January 2019
Derivative [Line Items]
Derivative contracts		$ 1.3
Alta Mesa RBL
Derivative [Line Items]
Derivative net proceeds	$ 4.0

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SIGNIFICANT ACQUISITIONS AND DIVESTITURES (Narrative) (Details) - USD ($)		1 Months Ended		3 Months Ended	11 Months Ended	12 Months Ended		24 Months Ended
	Feb. 09, 2018	Oct. 31, 2018	Feb. 08, 2018	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019
Business Acquisition [Line Items]
Proceeds from stock issued			$ 0		$ 400,000,000	$ 0
Common stock par value (in dollars per share)					$ 0.0001	$ 0.0001	$ 0.0001	$ 0.0001
SRII Opco, LP
Business Acquisition [Line Items]
Economic interests						47.75%		47.75%
SRII Opco, LP | Common Units
Business Acquisition [Line Items]
Shares issued to acquire business (in shares)	59,871,031
Common Class A
Business Acquisition [Line Items]
Shares sold (in shares)							3,101,510
Common Class C
Business Acquisition [Line Items]
Shares issued during period (in shares)						213,402,398
Common stock par value (in dollars per share)	$ 0.0001
SRII Opco, LP
Business Acquisition [Line Items]
Ownership interest						44.20%		44.20%
KFM Credit Facility
Business Acquisition [Line Items]
Payment towards acquisition of all working interests	$ 809,812,000
KFM Credit Facility | SRII Opco, LP
Business Acquisition [Line Items]
Shares issued to acquire business (in shares)	55,000,000
Common stock par value (in dollars per share)	$ 7.90
Alta Mesa | SRII Opco, LP
Business Acquisition [Line Items]
Common stock par value (in dollars per share)	$ 7.90
SRII Opco, LP
Business Acquisition [Line Items]
Percentage of ownership acquired	44.20%
Payment towards acquisition of all working interests	$ 1,338,000,000
Number of shares acquired (in shares)	169,371,730
Number of warrants acquired (in shares)	62,966,651
Alta Mesa, Alta Mesa GP, And Kingfisher | SRII Opco, LP
Business Acquisition [Line Items]
Shares issued to acquire business (in shares)	213,402,398
Percentage of outstanding shares issued	55.80%
Alta Mesa Holdings GP, LLC
Business Acquisition [Line Items]
Contribution to affiliates	$ 560,000,000.0
Alta Mesa Holdings GP, LLC | SRII Opco, LP
Business Acquisition [Line Items]
Economic interests	100.00%
Percentage of ownership acquired	90.00%
Fenter Energy, LLC
Business Acquisition [Line Items]
Cash		$ 22,300,000
SRII Opco, LP | Common Class A
Business Acquisition [Line Items]
Conversion of common shares (in shares)						2,181,600	12,341,076	14,522,676
SRII Opco, LP | KFM Credit Facility
Business Acquisition [Line Items]
Economic interests	100.00%
SRII Opco, LP | Alta Mesa
Business Acquisition [Line Items]
Percentage of ownership acquired	90.00%
Riverstone VI SR II Holdings, L.P. | Common Class A
Business Acquisition [Line Items]
Shares issued during period (in shares)	40,000,000
Warrants issued (in shares)	13,333,333
Proceeds from stock issued	$ 400,000,000
KFM Contributor
Business Acquisition [Line Items]
Shares issued to acquire business (in shares)				89,680
KFM Contributor | SRII Opco, LP
Business Acquisition [Line Items]
Contribution to affiliates	$ 814,800,000
Minority Voting Interest Holders In Alta Mesa GP
Business Acquisition [Line Items]
Percentage of ownership acquired	10.00%
AM Contributor
Business Acquisition [Line Items]
Shares issued to acquire business (in shares)				1,197,934
AM Contributor | Alta Mesa | SRII Opco, LP
Business Acquisition [Line Items]
Shares issued to acquire business (in shares)	138,402,398

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RECEIVABLES (Allowance for Doubtful Accounts) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Trade receivables
Allowance for Doubtful Accounts Receivable [Roll Forward]
Balance at beginning of period	$ 415	$ 415	$ 95
Charged to expense	0	25	332
Deductions	0	(345)	(10)
Balance at end of period	415	95	417
Related party receivables
Allowance for Doubtful Accounts Receivable [Roll Forward]
Balance at beginning of period	0	0	22,438
Charged to expense	0	22,438	3,196
Deductions	0	0	(87)
Balance at end of period	$ 0	$ 22,438	$ 25,547

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DISCONTINUED OPERATIONS (Predecessor) (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest on notes payable to founder	$ 103	$ 0	$ 0
Notes payable to founder
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Effective rate of interest				10.00%
Notes payable to founder				$ 28,300
Interest on notes payable to founder	$ 100

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SIGNIFICANT ACQUISITIONS AND DIVESTITURES (Purchase Consideration) (Details) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended	3 Months Ended	11 Months Ended	12 Months Ended
	Feb. 09, 2018	Feb. 08, 2018	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2019
Business Acquisition [Line Items]
SRII Opco Common Units issued		$ 0		$ 2,067,393	$ 0
Common stock par value (in dollars per share)				$ 0.0001	$ 0.0001
KFM Credit Facility
Business Acquisition [Line Items]
Cash	$ 809,812
SRII Opco Common Units issued	433,931
Estimated fair value of contingent earn-out purchase consideration	88,105
Settlement of preexisting relationship at fair value	(5,476)
Total purchase price consideration	$ 1,326,372
Silver Run Acquisition Corporation Opco Lp | Alta Mesa
Business Acquisition [Line Items]
Percentage of ownership acquired	90.00%
Silver Run Acquisition Corporation Opco Lp | KFM Credit Facility
Business Acquisition [Line Items]
Economic interests	100.00%
AM Contributor
Business Acquisition [Line Items]
Common units (in shares)			1,197,934
KFM Contributor
Business Acquisition [Line Items]
Closing adjustments			$ 5,000
Common units (in shares)			89,680
Silver Run Acquisition Corporation Opco Lp
Business Acquisition [Line Items]
Economic interests					47.75%
Redeemable days after closing	7 years
Silver Run Acquisition Corporation Opco Lp | Alta Mesa
Business Acquisition [Line Items]
SRII Opco Common Units issued	$ 1,261,249
Estimated fair value of contingent earn-out purchase consideration	284,109
Settlement of preexisting relationship at fair value	5,476
Total purchase price consideration	$ 1,550,834
Common stock par value (in dollars per share)	$ 7.90
Silver Run Acquisition Corporation Opco Lp | Alta Mesa Holdings GP, LLC
Business Acquisition [Line Items]
Economic interests	100.00%
Percentage of ownership acquired	90.00%
Silver Run Acquisition Corporation Opco Lp | KFM Credit Facility
Business Acquisition [Line Items]
Common units (in shares)	55,000,000
Common stock par value (in dollars per share)	$ 7.90
Silver Run Acquisition Corporation Opco Lp | AM Contributor | Alta Mesa
Business Acquisition [Line Items]
Common units (in shares)	138,402,398
Silver Run Acquisition Corporation Opco Lp | Riverstone Contributor Agreement | Alta Mesa
Business Acquisition [Line Items]
Common units (in shares)	20,000,000

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RECEIVABLES (Schedule of Accounts Receivable) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Receivables [Abstract]
Production and processing sales and fees	$ 40,858	$ 51,004
Joint interest billings	12,845	18,147
Pooling interest	7,901	18,786
Allowance for doubtful accounts	(417)	(95)
Total accounts receivable, net	$ 61,187	$ 87,842

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COMMITMENTS AND CONTINGENCIES (Narrative) (Details) Mcfe in Thousands, $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2019 USD ($) Mcfe $ / MMcf
Commitment And Contingencies [Line Items]
General and administrative	$ 21,234	$ 131,052	$ 107,655
Performance Shares
Commitment And Contingencies [Line Items]
General and administrative		$ 10,900
KFM Credit Facility
Commitment And Contingencies [Line Items]
Commitment amount			$ 128
Natural gas | KFM Credit Facility
Commitment And Contingencies [Line Items]
Processing commitment | Mcfe			3,650
Shortfall volume commitment amount | $ / MMcf			0.85

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CHAPTER 11 PROCEEDINGS

12 Months Ended

Dec. 31, 2019

Reorganizations [Abstract]

CHAPTER 11 PROCEEDINGS

CHAPTER 11 PROCEEDINGS

Voluntary Reorganization Under Chapter 11

On September 11, 2019, the Initial Debtors filed for reorganization under the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court granted a motion seeking joint administration of the Chapter 11 cases.

In January 2020, the Additional Debtors filed for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Chapter 11 cases. The Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court.

The filing of the Debtors’ bankruptcy petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors to recover, collect or secure a claim arising prior to the bankruptcy filings. Accordingly, although the bankruptcy filing triggered defaults of the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, the creditors are generally stayed from taking any actions as a result of such defaults. Absent an order of the Bankruptcy Court, substantially all of the Initial Debtors’ prepetition liabilities are subject to compromise under the Bankruptcy Code at December 31, 2019 and substantially all of the Additional Debtors’ prepetition liabilities became subject to compromise under the Bankruptcy Code beginning in January 2020.

In September 2019, an official committee of unsecured creditors was appointed. In October 2019, the Bankruptcy Court approved proposed bidding procedures and the dates for an auction and a hearing to approve the sale or sales of assets under Section 363 of the Bankruptcy Code. The auction was held on January 15, 2020, at which a winning bid was selected for substantially all of Alta Mesa and KFM’s assets totaling $320.0 million before certain direct sales costs. The Sale Transactions are expected to close no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

Initial Orders and Other Filings

In September 2019, the Bankruptcy Court approved measures that allow the Initial Debtors to stabilize their businesses and operations. Similar orders requested by the Additional Debtors were approved by the Bankruptcy Court in January 2020. The Debtors are authorized to use cash collateral of their lenders, but the Debtors must adhere to a budget and meet certain milestones.

Liabilities Subject to Compromise

Liabilities subject to compromise at December 31, 2019 represented the Initial Debtors’ remaining prepetition liabilities that have been allowed or that the Initial Debtors anticipate will be allowed as claims in its Chapter 11 cases. The amounts represent the estimated obligations to be resolved in connection with their Chapter 11 proceedings. The differences between the estimate and the claims filed will be evaluated and resolved in connection with the claims resolution process during the pendency of Chapter 11 proceedings.

Following are the components of liabilities subject to compromise:

(in thousands)	December 31, 2019
Alta Mesa RBL	$	355,943
2024 Notes	500,000
Accounts payable and accrued liabilities	20,315
Accrued interest payable on 2024 Notes	9,516
Operating lease liabilities	11,088
Liabilities subject to compromise	$	896,862

Reorganization Items

The Initial Debtors have incurred and, along with the Additional Debtors, are expected to continue to incur significant costs associated with the bankruptcy.

Components of reorganization items, net included are:

(in thousands)	Year Ended December 31, 2019
Unamortized deferred financing fees and premiums	$	24,725
Terminated contracts	1,435
Legal and other professional advisory fees	(26,357		)
Reorganization items, net	$	(197	)

Interest Expense

The Company did not record interest expense on its 2024 Notes after the Initial Debtors’ filing for bankruptcy. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.

Executory Contracts

Under the Bankruptcy Code, the Debtors may reject certain executory contracts with the approval of the Bankruptcy Court. Generally, the rejection of an executory contract is treated as a prepetition breach of that contract, therefore the Debtors are relieved of performing their future obligations under such executory contract, but the contract counterparty is entitled to file a general unsecured claim for damages.

Combined Financial Information of Initial Debtors

Combined Statement of Operations

(in thousands)	Year Ended December 31, 2019
Revenue
Oil	$	328,386
Natural gas	53,693
Natural gas liquids	40,026
Other	1,471
Operating revenue	423,576
Gain on sale of assets	1,488
Loss on derivatives	(11,744		)
Total revenue	413,320
Operating expenses
Lease operating	79,884
Transportation and marketing	70,324
Production taxes	19,455
Workovers	2,652
Exploration	52,354
Depreciation, depletion and amortization	120,617
Impairment of assets	556,427
General and administrative	71,823
Total operating expenses	973,536
Operating income	(560,216		)
Other income (expenses)
Interest expense	(49,823		)
Interest income	154
Reorganization items, net	(197		)
Total other income (expense), net	(49,866		)
Loss from continuing operations before income taxes	(610,082		)
Income tax provision (benefit)	—
Net loss	$	(610,082	)

Combined Balance Sheet

(in thousands)	December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	81,669
Restricted cash	681
Accounts receivable, net	49,256
Other receivables	1,311
Related party receivables, net	17,586
Prepaid expenses and other current assets	6,340
Total current assets	156,843
Property and equipment, net
Oil and gas properties, successful efforts method	215,352
Other property and equipment	23,210
Total property and equipment, net	238,562
Other assets
Investment in subsidiary	1,505,533
Operating lease right-of-use assets, net	—
Deferred financing costs, net	—
Deposits and other long-term assets	6,116
Total other assets	1,511,649
Total assets	$	1,907,054
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	58,858
Accounts payable - related parties	19,425
Advances from non-operators	811
Advances from related party	3,175
Asset retirement obligations, current portion	34
Total current liabilities	82,303
Long-term liabilities
Asset retirement obligations, net of current portion	12,995
Total long-term liabilities	12,995
Liabilities subject to compromise	896,862
Total liabilities	992,160
Partners’ capital	914,894
Total liabilities and partners’ capital	$	1,907,054

Combined Statement of Cash Flows

(in thousands)	Year Ended December 31, 2019
Cash flows from operating activities:
Net loss	$	(610,082	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	120,617
Non-cash lease expense	2,981
Provision for uncollectible receivables	1,218
Impairment of assets	556,427
Non-cash reorganization items, net	(26,160		)
Amortization of deferred financing costs	195
Amortization of debt premium	(3,432		)
Equity-based compensation expense	5,718
Non-cash exploration expense	43,412
(Gain) loss on derivatives	11,744
Cash settlements of derivatives	7,642
Cash paid for derivatives	(1,906		)
Impact on cash from changes in:
Accounts receivable	18,783
Other receivables	4,957
Related party receivables	3,651
Prepaid expenses and other assets	(25,716		)
Advances from related party	(6,647		)
Settlement of asset retirement obligations	(234		)
Accounts payable, accrued liabilities and other liabilities	22,373
Operating lease obligations	(2,636		)
Cash from operating activities	122,905
Cash flows from investing activities:
Capital expenditures	(249,955		)
Distribution received from subsidiary	691
Cash from investing activities	(249,264		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	199,362
Repayments of long-term debt	(4,496		)
Payment of taxes withheld on equity-based compensation awards	(142		)
Cash from financing activities	194,724
Net increase in cash, cash equivalents and restricted cash	68,365
Cash, cash equivalents and restricted cash, beginning of period	13,985
Cash, cash equivalents and restricted cash, end of period	$	82,350

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

(in thousands, except shares and per share data)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018
Net loss attributable to AMR Class A common stockholders	$	(450,538	)	$	(1,524,699	)
Weighted average Class A common shares outstanding (Basic and Diluted)	181,636,795			175,151,969
Basic and diluted loss per common share attributable to AMR common stockholders	$	(2.48	)	$	(8.71	)

During 2019, approximately 201.0 million shares of Class C Common Stock, 63.0 million of warrants and 5.1 million of aggregate stock options, restricted stock and restricted stock units, were excluded from the calculation of diluted earnings per share as their effect would have been anti-dilutive.

During the 2018 Successor Period, approximately 99.9 million shares of Class C Common Stock, 63.0 million of warrants and 6.2 million of aggregate stock options, restricted stock and restricted stock units, were excluded from the calculation of diluted earnings per share as their effect would have been anti-dilutive.

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EQUITY-BASED COMPENSATION (Successor) (Narrative) (Details) - USD ($)	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized under plan (in shares)			50,000,000
Equity-based compensation expense	$ 0	$ 22,025,000	$ 6,412,000
Vesting period			3 years
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option expiration period			7 years
Unrecognized compensation cost			$ 3,500,000
Period for unrecognized compensation cost			9 months 18 days
Stock options | Tranche one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage			33.33%
Stock options | Tranche two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage			33.33%
Stock options | Tranche three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage			33.33%
Restricted Stock Units, Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (shares)		98,199
Restricted Stock Units, Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (shares)		2,140,160
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost			$ 2,100,000
Period for unrecognized compensation cost			1 year 4 months 24 days
Granted (shares)		2,238,359	70,093
Restricted Stock Awards | Tranche one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage			33.33%
Restricted Stock Awards | Tranche two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage			33.33%
Restricted Stock Awards | Tranche three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage			33.33%
PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost			$ 0
Granted (shares)		2,093,453	1,220,490
Vesting period		3 years
Percentage of shares that may be earned			199.00%
PSUs | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned		0.00%
PSUs | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned		200.00%
PSUs | Tranche one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		20.00%
PSUs | Tranche two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		30.00%
PSUs | Tranche three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		50.00%

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INCOME TAXES (Schedule Of Components Of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Current taxes:
Federal		$ (69)	$ 0
State		0	0
Current taxes		(69)	0
Deferred taxes:
Federal		0	0
State		0	0
Deferred taxes		0	0
Income tax expense (benefit)	$ 0	$ (69)	$ 0

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DISCONTINUED OPERATIONS (Predecessor)

12 Months Ended

Dec. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

DISCONTINUED OPERATIONS (Predecessor)

DISCONTINUED OPERATIONS (Predecessor)

Alta Mesa distributed its remaining non-STACK oil and gas assets and liabilities to High Mesa just prior to the closing of the Business Combination. We have determined that these non-STACK oil and gas assets and liabilities are discontinued operations during the Predecessor Periods and we have segregated their financial information in the financial statements.

Prior to the Business Combination, Alta Mesa had notes payable to its founder (“Founder Notes”) that bore simple interest at 10%. The Founder Notes were 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.  Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period.

(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 income (expense)
Interest expense	(103		)
Total other expense	(103		)
Loss from discontinued operations, net of state income taxes	$	(7,746	)

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

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IMPAIRMENT OF ASSETS (Tables)

12 Months Ended

Dec. 31, 2019

Other Income and Expenses [Abstract]

Impairment Expense

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Upstream
Impairment of unproved properties	$	31,023	$	742,065	$	—
Impairment of proved properties	484,830		1,291,647		—
Impairment of operating lease right-of-use assets	13,245		—		—
Impairment of other long-term assets	27,329		—		—
Total Upstream impairment of assets	556,427		2,033,712		—
Midstream
Impairment of Cimarron investment	—		15,963		—
Impairment of property and equipment	348,597		68,407		—
Impairment of operating lease right-of-use assets	269		—		—
Impairment of intangible assets	—		394,999		—
Impairment of goodwill	—		691,970		—
Total Midstream impairment of assets	348,866		1,171,339		—
Total impairment of assets	$	905,293	$	3,205,051	$	—

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BUSINESS SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION

Following the Business Combination, we have two reportable segments: (i) Upstream and (ii) Midstream.  Each segment is ultimately led by our Chief Executive Officer, who is also the Chief Operating Decision Maker (“CODM”).  The CODM evaluates segment performance using Adjusted EBITDAX and Adjusted EBITDA. 

We believe Adjusted EBITDAX and Adjusted EBITDA are 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 and Adjusted EBITDA should not be considered as an alternative to net income (loss), operating income (loss) or any other performance measure derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports.

	Year Ended December 31, 2019
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations				Total
Revenue
Oil	$	328,386		$	—		$	—			$	328,386
Natural gas	53,693			—			—				53,693
Natural gas liquids	40,026			—			—				40,026
Sales of gathered production	—			37,195			—				37,195
Midstream revenue	—			84,763			(54,173		)		30,590
Segment sales revenue	422,105			121,958			(54,173		)		489,890
Other revenue	1,471			24,988			(16,129		)		10,330
Operating revenue	423,576			146,946			(70,302		)		500,220
Gain (loss) on sale of assets	1,488			(106		)	—				1,382
Gain (loss) on derivatives	(11,744		)	—			—				(11,744		)
Total revenue	413,320			146,840			(70,302		)		489,858
Operating expenses
Lease operating	79,884			—			(16,129		)		63,755
Transportation, processing and marketing	70,324			9,659			(58,941		)		21,042
Midstream operating	—			24,719			—				24,719
Cost of sales for purchased gathered production	—			34,529			—				34,529
Production taxes	19,455			—			—				19,455
Workovers	2,652			537			—				3,189
Exploration	52,354			—			—				52,354
Depreciation, depletion, and amortization	120,617			11,675			—				132,292
Impairment of assets	556,427			348,866			—				905,293
General and administrative	59,897			35,427			12,331				107,655
Total operating expenses	961,610			465,412			(62,739		)		1,364,283
Operating income	(548,290		)	(318,572		)	(7,563		)		(874,425		)
Other income (expense)
Interest expense	(49,823		)	(11,636		)	—				(61,459		)
Interest income and other	154			17			72				243
Equity in earnings of unconsolidated subsidiaries	—			6,216			—				6,216
Reorganization items, net	449			—			(646		)		(197		)
Total other income (expense)	(49,220		)	(5,403		)	(574		)		(55,197		)
Income (loss) from continuing operations before income taxes	(597,510		)	(323,975		)	(8,137		)	—	(929,622		)
Interest expense	49,823			11,636			—				61,459
Depreciation, depletion and amortization	120,617			11,675			—				132,292
Loss on unrealized hedges	19,386			—			—				19,386
Loss on sale of property and equipment	—			106			—				106
Impairment assets	556,427			348,866			—				905,293
Provision for uncollectible related party receivables	886			2,310			—				3,196
Equity-based compensation	5,718			694			—				6,412
Exploration	52,354			—			—				52,354
Severance costs	4,865			2,162			—				7,027
Strategic costs	8,116			11,479			2,025				21,620
Non-cash lease operating expense	3,835			—			—				3,835
Gain on equity method investment	—			(5,503		)	—				(5,503		)
Reorganization items, net	(449		)	—			646				197
Adjusted EBITDAX	$	224,068		$	59,450		$	(5,466	)		$	278,052
Equity method investment	$	—		$	—		$	—			$	—
Capital expenditures	249,955			77,612			—				327,567
Total assets at period end	396,041			112,825			(10,286		)		498,580

	February 9, 2018 Through December 31, 2018
(in thousands)	Exploration & Production			Midstream			Corporate and Eliminations				Total
Revenue
Oil	$	323,299		$	—		$	—			$	323,299
Natural gas	43,407			—			—				43,407
Natural gas liquids	43,039			—			—				43,039
Sales of gathered production	—			31,506			—				31,506
Midstream revenue	—			68,519			(41,059		)		27,460
Segment sales revenue	409,745			100,025			(41,059		)		468,711
Other revenue	4,762			—			—				4,762
Operating revenue	414,507			100,025			(41,059		)		473,473
Gain on sale of assets	4,751			—			—				4,751
Gain (loss) on derivatives	(10,247		)	—			—				(10,247		)
Total revenue	409,011			100,025			(41,059		)		467,977
Operating expenses
Lease operating	60,547			—			(3,720		)		56,827
Transportation, processing and marketing	50,038			9,911			(40,656		)		19,293
Midstream operating	—			15,221			—				15,221
Cost of sales for purchased gathered production	—			31,247			—				31,247
Production taxes	16,865			—			—				16,865
Workovers	5,563			—			—				5,563
Exploration	34,085			—			—				34,085
Depreciation, depletion, and amortization	133,554			27,388			—				160,942
Impairment of assets	2,033,712			1,171,339			—				3,205,051
General and administrative	114,735			14,025			2,292				131,052
Total operating expenses	2,449,099			1,269,131			(42,084		)		3,676,146
Operating income	(2,040,088		)	(1,169,106		)	1,025				(3,208,169		)
Other income (expense)
Interest expense	(38,265		)	(5,031		)	—				(43,296		)
Interest income and other	1,983			6			60				2,049
Total other income (expense)	(36,282		)	(5,025		)	60				(41,247		)
Income (loss) from continuing operations before income taxes	(2,076,370		)	(1,174,131		)	1,085			(1)	(3,249,416		)
Interest expense	38,265			5,031			—				43,296
Depreciation, depletion and amortization	133,554			27,388			—				160,942
Gain on unrealized hedges	(28,714		)	—			—				(28,714		)
Loss on sale of fixed assets	388			—			—				388
Impairment of assets	2,033,712			1,171,339			—				3,205,051
Provision for uncollectible related party receivables	22,438			—			—				22,438
Equity-based compensation	20,000			1,190			835				22,025
Exploration	34,085			—			—				34,085
Business Combination	23,717			—			—				23,717
Adjusted EBITDAX	$	201,075		$	30,817		$	1,920			$	233,812
Equity method investment	$	—		$	1,100		$	—			$	1,100
Capital expenditures	700,953			61,807			—				762,760
Total assets at period end	935,719			437,721			(15,610		)		1,357,830

_________________

(1) Includes $3,316 for elimination of intercompany deferred revenue resulting from the adoption of ASC 606.

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SIGNIFICANT CONCENTRATIONS

12 Months Ended

Dec. 31, 2019

Risks and Uncertainties [Abstract]

SIGNIFICANT CONCENTRATIONS

SIGNIFICANT CONCENTRATIONS

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

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	123,000	$	336,248	$	28,757
Marketing and management fees paid to ARM	$	1,715	$	—	$	—
Fees paid to ARM for services relating to our derivatives	496		784		66
Total fees paid to ARM	$	2,211	$	784	$	66

Receivables from ARM for sales on our behalf were $6.8 million and $43.8 million as of December 31, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

For the year ended December 31, 2019, one customer accounted for 40.5% of our total operating revenue for the period.

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.

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DERIVATIVES

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

DERIVATIVES

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

The following summarizes the fair value and classification of our derivatives at 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 summarizes the effect of our derivatives in our statements of operations (in thousands):

	Successor						Predecessor
				February 9, 2018			January 1, 2018
Derivatives not	Year Ended			Through			Through
designated as hedges	December 31, 2019			December 31, 2018			February 8, 2018
Gain (loss) on derivatives -
Oil commodity contracts	$	(16,013	)	$	(3,559	)	$	4,796
Natural gas commodity contracts	4,269			(6,688		)	1,867
Total gain (loss) on derivatives	$	(11,744	)	$	(10,247	)	$	6,663

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

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LONG-TERM DEBT, NET

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

LONG-TERM DEBT, NET

LONG-TERM DEBT, NET

(in thousands)	December 31, 2019			December 31, 2018
Alta Mesa RBL	$	355,943		$	161,000
KFM Credit Facility	224,000			174,000
2024 Notes	500,000			500,000
Unamortized premium on 2024 notes	—			29,123
Total debt, net	1,079,943			864,123
Less: Liabilities subject to compromise	(855,943		)	—
Less: Current portion	(224,000		)	(690,123		)
Long-term debt, net	$	—		$	174,000

Alta Mesa RBL

In connection with the Business Combination, we entered into the Alta Mesa RBL which has a face amount of $1.0 billion and had an initial $350.0 million borrowing base, which was subsequently increased to $400.0 million in April 2018. The facility matures in February 2023 and was subject to semiannual redeterminations, as well as an additional optional redetermination between semiannual redeterminations either by us or the lender group. As of December 31, 2019, we had $355.9 million in outstanding borrowings under the Alta Mesa RBL, plus $1.9 million in outstanding letters of credit.

Amounts outstanding under the Alta Mesa RBL are secured by first priority liens on substantially all of our upstream oil and gas properties and all of our equity of our wholly owned guarantor subsidiaries. Upon closing of the expected AMH Sale Transaction, these outstanding amounts will be secured by the proceeds from such sale and all of the equity of our wholly

owned guarantor subsidiaries. Additionally, SRII Opco and Alta Mesa GP, both of which are under bankruptcy protection at the time of this filing, had pledged their respective partner interests as security.

In August 2019, the lenders exercised their option to conduct an optional redetermination, pursuant to which they established a revised borrowing base of $200.0 million, a reduction from the prior $370.0 million established in April 2019. As a condition to the borrowing base reduction, we were required to make monthly installments of $32.5 million for five months, beginning in September 2019, to reduce our outstanding borrowings to the revised borrowing base. AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments.

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

Prior to default, we had the ability to designate borrowings in either Eurodollars or at a reference rate. Subsequent to our default, all Eurodollar loans were converted into reference rate loans at maturity, which bear interest at a rate per annum equal to the greater of (i) the agent bank’s prime rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus a margin ranging from 1.00% to 2.00%. At December 31, 2019, outstanding borrowings bore interest at a rate of 10.75%, which consisted of the Prime Rate plus additional penalty margins of 2.00% due to our borrowing base deficiency and 2.00% due to our default.

Prior to our default, restrictive covenants generally limited our ability to incur additional indebtedness, sell assets, guarantee or make loans to others, make investments, enter into mergers, make certain payments and distributions in excess of specific amounts, enter into or be party to hedge agreements outside of hedge requirements, amend organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. Subsequent to the AMH Debtors’ bankruptcy filing, we currently operate under cash collateral orders issued by the Bankruptcy Court that allow us to use our cash collateral, with restrictions on our ability to dispose of assets or settle liabilities. The terms and conditions of the cash collateral orders include, without limitation, adherence to a budget with an agreed upon variance and provide for certain monthly reporting obligations.

The Alta Mesa RBL had two covenants that no longer require quarterly testing as a result of our bankruptcy filing.

KFM Credit Facility  

Effective May 30, 2018, KFM entered into the KFM Credit Facility with an aggregate committed amount of $300.0 million. The KFM Credit Facility matures in May 2023. As of December 31, 2019, outstanding borrowings totaled $224.0 million and there were no outstanding letters of credit.

Amounts outstanding under the KFM Credit Facility are secured by first priority liens on substantially all of KFM’s assets and are guaranteed by KFM’s wholly owned subsidiaries. Upon closing of the expected KFM Sale Transaction these outstanding amounts will be secured by the proceeds from such sale and all of the equity of our wholly owned guarantor subsidiaries. Additionally, SRII Opco, LP had pledged its membership interests in KFM as collateral.

In September 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility alleged a potential event of default in respect of liens placed on KFM’s assets. As a result, KFM was unable to borrow additional funds under the KFM Credit Facility after September 2019.

On January 12, 2020, the KFM Debtors filed for protection under the Bankruptcy Code. This filing constituted an event of default under the KFM Credit Facility that accelerated KFM’s obligations thereunder.

Prior to the alleged default, we had the ability to designate borrowings under the KFM Credit Facility in either Eurodollars or at a reference rate. Subsequent to the alleged default, all Eurodollar loans were converted into reference rate loans at maturity, which bear interest at a rate per annum equal to the greater of (i) the agent bank’s prime rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus an applicable margin ranging from 1.00% to 2.25%. At December 31, 2019, outstanding borrowings bore interest at a rate of 6.5%.

Prior to our default, restrictive covenants limited our ability to incur additional indebtedness, dispose of assets, make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge

agreements, amend organizational documents, incur liens, hold cash in excess of $15.0 million and engage in certain other transactions. Subsequent to the KFM Debtors bankruptcy filing in January 2020, we currently operate under cash collateral orders issued by the Bankruptcy Court that allow us to use our cash collateral, with restrictions on our ability to dispose of assets or settle liabilities. The terms and conditions of the cash collateral orders include, without limitation, adherence to a budget with an agreed upon variance and provide for certain monthly reporting obligations.

The KFM Credit Facility also had two maintenance covenants that no longer require quarterly testing as a result of the cash collateral orders issued in January 2020.

2024 Notes

Our 2024 Notes have a face value of $500 million and bear interest at 7.875% per annum, payable semi-annually each June 15 and December 15. The 2024 Notes mature in December 2024.

Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default including acceleration. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.

The 2024 Notes are guaranteed by each of Alta Mesa’s subsidiaries and rank equal in right of payment to all of Alta Mesa’s existing senior indebtedness; senior in right of payment to all of Alta Mesa’s existing and future subordinated indebtedness; effectively subordinated to all of Alta Mesa’s existing secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Alta Mesa RBL; and structurally subordinated to all existing and future indebtedness and obligations of any of Alta Mesa’s subsidiaries that do not guarantee the 2024 Notes.

The terms of the 2024 Notes originally provided for early redemption over certain periods at their principal amount plus an applicable make-whole premium and contained covenants restricting our ability to enter into certain transactions or to sell or otherwise dispose of assets, among other things.

Bond Premium  

The fair value of the 2024 Notes as of the Business Combination was $533.6 million, yielding a bond premium of $33.6 million. Amortization of the premium reduced our interest expense by $3.4 million and $4.5 million during the year ended December 31, 2019 and the 2018 Successor Period, respectively. Upon filing for bankruptcy protection, the remaining unamortized premium was written off as part of reorganization items, net.

Scheduled Maturities of Debt

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Fiscal Year	(in thousands)
2023	$	579,943
2024	500,000
	$	1,079,943

Based on the defaults associated with Alta Mesa’s and KFM’s bankruptcy filings and the reporting requirements for entities under bankruptcy protection, we have classified all of the indebtedness under the Alta Mesa RBL as liabilities subject to compromise and all of the indebtedness under the KFM Credit Facility as current liabilities at December 31, 2019 despite the scheduled maturities shown above. At December 31, 2018, all of the indebtedness under the Alta Mesa RBL and the related bond premium were classified as current liabilities due to our expectations at that time the indebtedness would become accelerated during 2019.

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Estimated Quantities of Proved Reserves) (Details) MMcf in Thousands, MMBoe in Thousands, MBbls in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018 MMBoe MBbls MMcf	Dec. 31, 2018 MMBoe MBbls MMcf	Dec. 31, 2019 MMBoe MBbls MMcf	Dec. 31, 2017 MBbls MMcf
Revisions of previous quantity estimates and other:
Proved Developed Reserves, Beginning of Period | MMBoe		51,731
Proved Undeveloped Reserves, Beginning of Period | MMBoe		124,685
Total, Proved Developed and Undeveloped Reserves, Beginning of Period | MMBoe		176,416
Proved Developed Reserves, Production | MMBoe		(10,140)
Proved Undeveloped Reserves, Production | MMBoe		0
Total, Production | MMBoe		(10,140)
Proved Developed Reserves, Purchases in place, discoveries and extensions | MMBoe		35,096
Proved Undeveloped Reserves, Purchases in place, discoveries and extensions | MMBoe		47,092
Total, Purchases in place, discoveries and extensions | MMBoe		82,188
Proved Developed Reserves, Lower estimated recoveries identified as a result of 2018 drilling program | MMBoe		(31,964)
Proved Undeveloped Reserves, Lower estimated recoveries identified as a result of 2018 drilling program | MMBoe		(69,534)
Total, Lower estimated recoveries identified as a result of 2018 drilling program | MMBoe		(101,498)
Proved Developed Reserves, Higher average commodity prices in Successor Period compared to 2017 | MMBoe		5,367
Proved Undeveloped Reserves, Higher average commodity prices in Successor Period compared to 2017 | MMBoe		5,829
Total, Higher average commodity prices in Successor Period compared to 2017 | MMBoe		11,196
Proved Developed Reserves, Transfers of PUDs to proved developed reserves | MMBoe		18,999
Proved Undeveloped Reserves, Transfers of PUDs to proved developed reserves | MMBoe		(18,999)
Total, Transfers of PUDs to proved developed reserves | MMBoe		0
Proved Developed Reserves, Derecognition of PUDs due to significant concerns about ability to fund development of those reserves | MMBoe		0
Proved Undeveloped Reserves, Derecognition of PUDs due to significant concerns about ability to fund development of those reserves | MMBoe		(89,073)
Total, Proved Undeveloped Reserves, Derecognition of PUDs due to significant concerns about ability to fund development of those reserves | MMBoe		(89,073)
Proved Developed Reserves, End of Period | MMBoe	51,731		69,089
Proved Undeveloped Reserves, End of Period | MMBoe	124,685		0
Total, Proved Developed and Undeveloped Reserves, End of Period | MMBoe	176,416		69,089
Oil
Total Proved Reserves:
Proved Reserves, Beginning Balance	73,518	71,705	25,272
Production	(521)	(5,053)	(5,885)
Purchases in place		2,658
Discoveries and extensions		30,026	4,265
Sales of reserves in place	(1,667)
Revisions of previous quantity estimates and other	375	(74,064)	(6,736)
Proved Reserves, Ending Balance	71,705	25,272	16,916
Proved Developed Reserves	19,345	25,272	16,916	20,347
Proved Undeveloped Reserve	52,360	0	0	53,171
Natural gas
Total Proved Reserves:
Proved Reserves, Beginning Balance | MMcf	433,519	410,802	144,148
Production | MMcf	(1,984)	(16,913)	(24,802)
Purchases in place | MMcf		13,331
Discoveries and extensions | MMcf		155,306	24,351
Sales of reserves in place | MMcf	(24,239)
Revisions of previous quantity estimates and other | MMcf	3,506	(418,378)	(29,254)
Proved Reserves, Ending Balance | MMcf	410,802	144,148	114,443
Proved Developed Reserves | MMcf	126,231	144,148	114,443	150,183
Proved Undeveloped Reserve | MMcf	284,571	0	0	283,336
Natural gas liquids
Total Proved Reserves:
Proved Reserves, Beginning Balance	36,887	36,244	19,792
Production	(161)	(2,268)	(2,760)
Purchases in place		1,751
Discoveries and extensions		19,646	2,835
Sales of reserves in place	(771)
Revisions of previous quantity estimates and other	289	(35,581)	(9,352)
Proved Reserves, Ending Balance	36,244	19,792	10,515
Proved Developed Reserves	11,348	19,792	10,515	12,180
Proved Undeveloped Reserve	24,896	0	0	24,707
BOE
Total Proved Reserves:
Proved Reserves, Beginning Balance	182,658	176,416	69,089
Production	(1,012)	(10,140)	(12,779)
Purchases in place		6,631
Discoveries and extensions		75,557	11,159
Sales of reserves in place	(6,478)
Revisions of previous quantity estimates and other	1,248	(179,375)	(20,964)
Proved Reserves, Ending Balance	176,416	69,089	46,505
Proved Developed Reserves	51,731	69,089	46,505	57,557
Proved Undeveloped Reserve	124,685	0	0	125,101

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INCOME TAXES (Narrative) (Details) - USD ($) $ in Thousands	11 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019
Income Tax Contingency [Line Items]
Change in valuation allowance	$ 3,135	$ 136,568
Percent of tax benefit under tax receivable agreement	85.00%	85.00%
Benefit retained of the remaining cash savings (percent)		15.00%
Alta Mesa Contributor | Common Class A
Income Tax Contingency [Line Items]
Conversion of common shares (in shares)	2,752,312	2,181,600

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CHAPTER 11 PROCEEDINGS (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019	Jan. 15, 2020
Debt Instrument [Line Items]
Interest expense	$ 5,511	$ 43,296	$ 61,459
2024 Notes
Debt Instrument [Line Items]
Interest expense			$ 12,000
Subsequent Event
Debt Instrument [Line Items]
Unadjusted purchase price				$ 320,000

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INTANGIBLE ASSETS (Schedule Of Finite-Lived Customer Relationships) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
Customer contracts and relationships acquired	$ 414,150
Accumulated amortization and impairment	(414,150)
Intangibles, net	$ 0

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LONG-TERM DEBT, NET (Long-Term Debt, Net) (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Total debt, net	$ 1,079,943,000	$ 864,123,000
Less: Liabilities subject to compromise	(855,943,000)	0
Less: Current portion	(224,000,000)	(690,123,000)
Long-term debt, net	0	174,000,000
KFM Credit Facility
Debt Instrument [Line Items]
Credit facility amount outstanding	224,000,000	174,000,000
7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
2024 Notes	500,000,000	500,000,000
Unamortized premium on 2024 notes	0	29,123,000
Less: Liabilities subject to compromise	(500,000,000)
7.875% Senior Unsecured Notes Due 2024 | Alta Mesa RBL
Debt Instrument [Line Items]
2024 Notes	500,000,000.0
Alta Mesa RBL | Alta Mesa RBL
Debt Instrument [Line Items]
Credit facility amount outstanding	355,943,000	$ 161,000,000
Less: Liabilities subject to compromise	$ (355,943,000)

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IMPAIRMENT OF ASSETS (Schedule of Impairments) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Impairment of Cimarron investment		$ 15,963
Total impairment of assets	$ 0	3,205,051	$ 905,293
Upstream
Segment Reporting Information [Line Items]
Impairment of unproved properties	0	742,065	31,023
Impairment of proved properties	0	1,291,647	484,830
Impairment of operating lease right-of-use assets			13,245
Impairment of other long-term assets	0	0	27,329
Total impairment of assets	0	2,033,712	556,427	$ 2,000,000
Midstream
Segment Reporting Information [Line Items]
Impairment of operating lease right-of-use assets			269
Impairment of property and equipment	0	68,407	348,597	68,400
Impairment of Cimarron investment	0	15,963	0
Impairment of intangible assets	0	394,999	0	$ 395,000
Impairment of goodwill	0	691,970	0
Total impairment of assets	$ 0	$ 1,171,339	$ 348,866

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Nonrecurring Measurements

	December 31, 2019						December 31, 2018
(in thousands)	Carrying Value Before Assessment		Estimated Fair Value		Impairment		Carrying Value Before Assessment		Estimated Fair Value		Impairment
Unproved oil and gas properties	$	31,023	$	—	$	31,023	$	816,282	$	74,217	$	742,065
Proved oil and gas properties	700,182		215,352		484,830		1,895,670		604,023		1,291,647
Operating lease right-of-use assets	13,514		—		13,514		—		—		—
Other long-term assets(1)	51,518		24,189		27,329		—		—		—
Equity method investment	—		—		—		17,063		1,100		15,963
Midstream property and equipment(1)	432,415		83,818		348,597		474,529		406,122		68,407
Intangible assets	—		—		—		394,999		—		394,999
Goodwill	—		—		—		691,970		—		691,970
Total	$	1,228,652	$	323,359	$	905,293	$	4,290,513	$	1,085,462	$	3,205,051

_________________

(1) Amounts reflect only those assets that were impaired.

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosures To The Consolidated Statements Of Cash Flows

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	56,683		$	52,017		$	1,145
Cash paid for income taxes	706			1,573			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	853			5,665			—
Increase (decrease) in accruals or payables for capital expenditures	(155,681		)	39,997			4,896
Increase in withholding tax accruals for share-based compensation	142			534			—
Distribution of non-STACK assets, net of liabilities	—			—			43,482
Equity issued in Business Combination	—			2,067,393			—
Release of common stock from possible redemption	—			996,384			—
Other	78			(6		)	—

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL $ in Thousands	USD ($)
Balance at Dec. 31, 2017	$ 154,445
Increase (Decrease) in Partners' Capital [Roll Forward]
Distribution of non-STACK oil and gas assets, net of associated liabilities	43,482
Net loss	(14,862)
Balance at Feb. 08, 2018	183,065
Increase (Decrease) in Partners' Capital [Roll Forward]
Net loss	(1,524,699)
Balance at Dec. 31, 2018	245,520
Increase (Decrease) in Partners' Capital [Roll Forward]
Net loss	(450,538)
Balance at Dec. 31, 2019	$ (236,628)

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ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Summary Of Changes In Asset Retirement Obligations

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Balance, beginning of period	$	11,552		$	—		$	10,469
Liabilities assumed in Business Combination(1)	—			5,998			—
Liabilities incurred	859			2,676			—
Liabilities settled	(234		)	(1,610		)	(63		)
Liabilities transferred in sale of properties	—			(19		)	—
Revisions to estimates	26			3,766			63
Accretion expense	980			741			40
Balance, end of period	13,183			11,552			10,509
Less: current portion	34			2,079			33
Long-term portion	$	13,149		$	9,473		$	10,476

_________________

(1)

Represents the same wells as under the Predecessor Period but valued at a higher interest rate of 10.2% compared to Predecessor interest rates ranging between 4.4% and 8.8%.

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 95,367	$ 26,854
Restricted cash	681	1,001
Accounts receivable, net	61,187	87,842
Other receivables	1,344	6,331
Related party receivables	0	3,341
Prepaid expenses and other	8,047	1,125
Derivatives	0	16,423
Total current assets	166,626	142,917
Property and equipment
Oil and gas properties, successful efforts method, net	215,352	763,337
Other property and equipment, net	107,028	444,269
Total property and equipment, net	322,380	1,207,606
Other assets
Operating lease right-of-use assets, net	0
Equity method investment	0	1,100
Deferred financing costs, net	1,581	3,195
Deposits and other long-term assets	7,993	65
Derivatives	0	2,947
Total other assets	9,574	7,307
Total assets	498,580	1,357,830
Current liabilities
Current portion of debt	224,000	690,123
Accounts payable and accrued liabilities	64,137	247,439
Advances from non-operators	811	5,193
Advances from related party	3,175	9,839
Asset retirement obligations, current portion	34	2,079
Operating lease liability, current portion	88
Derivatives	0	1,710
Total current liabilities not subject to compromise	292,245	956,383
Long-term liabilities
Asset retirement obligations, net of current portion	13,149	9,473
Long-term debt, net	0	174,000
Operating lease liabilities, net of current portion	189
Derivatives	0	180
Other long-term liabilities	3,360	1,667
Total long-term liabilities not subject to compromise	16,698	185,320
Liabilities subject to compromise	896,862	0
Total liabilities	1,205,805	1,141,703
Commitments and contingencies (Note 19)
Stockholders’ equity
Additional paid in capital	1,512,716	1,503,382
Accumulated deficit	(1,983,351)	(1,532,813)
Total stockholders’ equity	(470,597)	(29,393)
Noncontrolling interest	(236,628)	245,520
Total equity	(707,225)	216,127
Total liabilities and stockholders’ equity	498,580	1,357,830
Preferred Class A
Long-term liabilities
Preferred stock, $0.0001 par value	0	0
Preferred Class B
Long-term liabilities
Preferred stock, $0.0001 par value	0	0
Common Class A
Stockholders’ equity
Common stock, $0.0001 par value	18	18
Common Class C
Stockholders’ equity
Common stock, $0.0001 par value	$ 20	$ 20

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EARNINGS PER SHARE (Narrative) (Details) - shares shares in Millions	11 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019
Common Class C
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded (in shares)	99.9	201.0
Warrant
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded (in shares)	63.0	63.0
Stock Options, Restricted Stock And Restricted Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded (in shares)	6.2	5.1

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

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PROPERTY AND EQUIPMENT (Depreciation and Depletion) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Oil and gas properties depletion	$ 11,021	$ 129,579	$ 118,003
Midstream tangible asset depreciation	0	8,235	11,663
Other property and equipment depreciation	609	3,236	1,646
Total depletion and depreciation	$ 11,630	$ 141,050	$ 131,312

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RECEIVABLES (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Sep. 29, 2017
Related Party Transaction [Line Items]
Accounts receivable, net	$ 61,187	$ 87,842
Senior Notes Two
Related Party Transaction [Line Items]
Allowance for uncollectible accounts	13,400
Affiliated Entity
Related Party Transaction [Line Items]
Accounts receivable, net	2,300
Affiliated Entity | High Mesa Agreement
Related Party Transaction [Line Items]
Accounts receivable, net	23,200
Long-term note receivable	9,800	10,100
Allowance for uncollectible accounts	9,800	9,000
NWGP
Related Party Transaction [Line Items]
Due from related parties	1,700	1,700	$ 1,500
Stated interest rate of senior notes			8.00%
HMS | Senior Notes Two
Related Party Transaction [Line Items]
Long-term note receivable	$ 11,700	$ 11,700
Stated interest rate of senior notes	8.00%

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DESCRIPTION OF BUSINESS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 segment	Jan. 01, 2020 USD ($)
Subsequent Event [Line Items]
Number of operating units | segment	2
Disposed of by Sale | Upstream Assets | Subsequent Event
Subsequent Event [Line Items]
Unadjusted purchase price		$ 232.0
Disposed of by Sale | Midstream Assets | Subsequent Event
Subsequent Event [Line Items]
Unadjusted purchase price		$ 88.0

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LONG-TERM DEBT, NET (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Long-term Debt, Net

(in thousands)	December 31, 2019			December 31, 2018
Alta Mesa RBL	$	355,943		$	161,000
KFM Credit Facility	224,000			174,000
2024 Notes	500,000			500,000
Unamortized premium on 2024 notes	—			29,123
Total debt, net	1,079,943			864,123
Less: Liabilities subject to compromise	(855,943		)	—
Less: Current portion	(224,000		)	(690,123		)
Long-term debt, net	$	—		$	174,000

Summary of Future Maturities of Long-Term Debt

Scheduled Maturities of Debt

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Fiscal Year	(in thousands)
2023	$	579,943
2024	500,000
	$	1,079,943

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EQUITY-BASED COMPENSATION (Successor) (Tables)

12 Months Ended

Dec. 31, 2019

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

Schedule of Outstanding Stock Options

	Stock Options		Weighted Average Exercise Price		Weighted Average Grant-Date Fair Value		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of February 9, 2018	—		$	—	$	—	—	$	—
Granted	5,283,224		8.80		4.33		—	—
Exercised	—		—		—		—	—
Forfeited or expired	(139,319	)	9.38		4.55		—	—
Outstanding as of December 31, 2018	5,143,905		$	8.79	$	4.33	5.3	$	—
Granted	157,710		$	1.07	$	0.61	—	$	—
Exercised	—		—		—		—	—
Forfeited or expired	(1,498,328	)	8.44		4.20		—	—
Outstanding as of December 31, 2019	3,803,287		$	4.80	$	4.22	3.19	$	—
Exercisable as of December 31, 2019	2,260,388		$	9.21	$	4.49	5.15	—

Summary of Assumptions Used to Determine the Fair Value of Options

The following assumptions were used to determine the fair value of our 2019 and 2018 option grants:

໿

	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Expected term (in years)	4.5		4.5
Expected stock volatility	69.8	%	64.6	%
Dividend yield	—		—
Risk-free interest rate	2.4	%	2.5	%

Schedule of Restricted Stock Awards Granted

The following table provides information about activity in our restricted stock awards during the 2018 Successor Period and year ended December 31, 2019:

໿

	Restricted Stock Awards		Weighted Average Grant Date Fair Value per share
Outstanding as of February 9, 2018	—		$	—
Granted	2,238,359		7.54
Vested(1)	(384,413	)	8.40
Forfeited or expired	(61,935	)	8.80
Outstanding as of December 31, 2018	1,792,011		7.32
Granted	70,093		0.96
Vested(1)	(619,061	)	7.04
Forfeited or expired	(719,766	)	7.36
Outstanding as of December 31, 2019	523,277		$	6.74

_________________

(1) To satisfy minimum tax withholding, 130,432 and 94,576 shares were withheld in 2019 and during the 2018 Successor Period.

Summary of PSUs Granted

The following table provides information about activity in our PSUs granted during the 2018 Successor Period and year ended December 31, 2019:

	PSUs		Weighted Average Grant Date Fair Value per unit
Outstanding as of February 9, 2018	—		$	—
Granted	2,093,453		4.07
Vested (1)	(1,559,749	)	2.53
Forfeited or expired	(533,704	)	8.54
Outstanding as of December 31, 2018	—		—
Granted	1,220,490		0.32
Vested	(100,870	)	0.96
Forfeited or expired	(54,112	)	0.27
Outstanding as of December 31, 2019	1,065,508		$	0.27

_________________

(1) To satisfy minimum tax withholding, 32,481 and 388,655 shares were withheld in 2019 and during the 2018 Successor Period.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Bankruptcy Accounting

Bankruptcy Accounting

As discussed further in Note 3, on September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Initial Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on our statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy process have been classified as “liabilities subject to compromise” on our balance sheet at December 31, 2019. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. The accompanying financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on stockholders’ deficit accounts of any changes that may be made to our capitalization; or (iv) the effect on operations of any changes that may be made to our business. While operating as debtor-in-possession under Chapter 11 of the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected on its consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications on our historical financial statements.

Also, as described further in Note 3, on January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases. The Additional Debtors also continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

Ability to Continue as a Going Concern

Ability to Continue as a Going Concern

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.

As described further in Note 1, we expect to sell substantially all of our assets no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.

Basis of Accounting and Presentation

Basis of Accounting and Presentation

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  We had no items of other comprehensive income during any period presented. Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation, but had no impact on net income (loss), stockholders’ equity or partners’ capital.  

As a result of the Business Combination, we are the acquirer for accounting purposes and Alta Mesa and KFM are the acquirees. The identifiable assets acquired and liabilities assumed were recorded at their estimated fair values, which were pushed down to each entity. As a result, our financial statements and certain footnotes separate our presentation into two distinct periods, the periods before the consummation of the Business Combination (“Predecessor Periods”) and the period after that date (the “Successor Period”). Our financial statements reflect Alta Mesa as the “Predecessor” for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, reflecting the consolidation of Alta Mesa and KFM beginning on February 9, 2018. The period January 1, 2018 to February 8, 2018 is referred to as the 2018 Predecessor Period. The 2018 Predecessor Period and the periods prior to January 1, 2018 are collectively referred to as the “Predecessor Periods”.

As noted above, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa in connection with the closing of the Business Combination. We determined the non-STACK oil and gas assets and related liabilities are discontinued operations during the Predecessor Periods and have segregated their financial information from ours in the financial statements.

Principles of Consolidation

Principles of Consolidation

The financial statements include the accounts of the Company and its subsidiaries, and eliminate all intercompany transactions and balances. The Company’s interests in oil and gas upstream ventures and partnerships are proportionately consolidated. Noncontrolling interest (“NCI”) represents third-party ownership interests in SRII Opco and is presented as a component of equity. The portion of SRII Opco earnings that are not attributable to the Company are separately presented in our statements of operations.

Segment Reporting (Successor)

Segment Reporting (Successor) 

We operate in two reportable business segments: (i) Upstream and (ii) Midstream. Alta Mesa conducts our Upstream activities and owns proved and unproved oil and gas properties. KFM operates our Midstream segment and owns gas gathering, processing and produced water disposal assets and crude oil gathering and transportation assets. Both segments are conducted in the United States and all revenue was derived from customers located in the United States. 

Use of Estimates

Use of Estimates

Preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported revenue and expenses during the reporting period. Estimates of reserves and their value are used to determine depletion and to conduct impairment analysis of oil and gas properties and can significantly affect future estimated cash flows utilized to assess goodwill and intangible assets for impairment. Estimating reserves has inherent uncertainty, including the projection of future rates of production and the timing of development expenditures.

Other significant estimates are utilized to determine amounts reported under GAAP related to collectibility of receivables, asset retirement obligations, federal and state taxes and contingencies. We base certain of our estimates on historical experience and various other assumptions that we believe to be reasonable. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. We regularly maintain cash balances that exceed federally insured amounts, but we have experienced no losses associated with these amounts.

Restricted Cash

Restricted Cash

Cash balances that are legally, contractually or otherwise restricted as to withdrawal or usage are considered restricted cash. As of December 31, 2019, and 2018, our restricted cash represents cash received for production where the final division of ownership is in dispute or there is unclaimed property for pooling orders in Oklahoma. 

Accounts Receivable

Accounts Receivable

Our receivables arise primarily from (i) the sale of our production, (ii) joint interest owners’ portion of operating costs for properties in which we are the operator, and (iii) for midstream services provided to third-party customers. The purchasers of our production and our midstream customers are concentrated in the oil and gas industry and therefore they are similarly affected by prevailing industry conditions.  Accounts receivable are generally not collateralized.  We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties we operate and market the production.

We routinely assess the recoverability of our receivables to determine their collectibility. We establish a valuation allowance to reduce receivables to their estimated collectible amounts, based upon several factors including, our historical experience, the length of time a receivable has been outstanding, communication with customers and the current and projected financial condition of specific customers.

Property and Equipment and Exploration Expense

Property and Equipment 

Our oil and gas property is accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts to obtain a mineral interest or right in a property, including related broker and other fees. These costs are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties

and become subject to depletion, or when we abandon plans to develop leases are impaired, at which time the costs are expensed as exploration costs. Unproved properties are not subject to depletion.

Proved Oil and Gas Properties — We capitalize costs incurred to drill, complete and equip proved reserves. Proved property costs include all costs incurred to drill and equip successful exploratory wells, development wells (regardless of success), development-type stratigraphic test wells and service wells, plus costs transferred from unproved properties.

Accounting policies for Midstream and other assets include:

Other Property and Equipment — Other property and equipment, such as land, buildings, plant equipment, assets associated with produced water disposal, vehicles, office furniture and office equipment, are recorded at cost.  Maintenance, repairs and minor renewals are expensed as incurred.  Plant and equipment also includes costs for our cryogenic gas processing facility along with gas gathering pipelines and compression, including rights of way, and a crude oil gathering system and crude oil storage facility.

Other important accounting policies affecting property and equipment include:

Depreciation and Depletion — Depletion of proved oil and gas properties is computed using the unit-of-production method based upon produced volumes and estimated proved reserves. Because all of our oil and gas properties are located in a single basin, we apply depletion on a single cost center. We deplete leasehold acquisition costs and the cost to acquire proved properties (generally proved undeveloped costs) based upon total estimated proved reserves. We deplete costs to drill, complete and equip wells plus the related lease costs (generally proved developed costs) over estimated proved developed reserves. 

Through December 31, 2019, we depreciated our Midstream property and equipment using the straight-line method over the estimated useful lives of the assets, which included 35 years for our produced water disposal assets, processing plant and pipelines and 25 years for our compressors. Leasehold improvements were depreciated over the shorter of their useful lives or the term of the lease. Vehicles and office furniture and office equipment were depreciated over their estimated useful lives, ranging from three years to seven years.  As a result of the expected sale of substantially all of our assets no later than mid-April 2020, we will depreciate any assets that are not to be acquired by the Buyer over our expected wind-down period, expected to be less than one year.

Impairment — Because proved reserves have not been ascribed to unproved property, in determining whether it is impaired, we consider numerous factors including recent leasing activity, recent drilling results in the area, our geologists’ evaluation and the remaining lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated proved and unproved reserves and, combined with a market approach, estimate fair value. Our cash flow estimates for unproved reserves are reduced by additional risk-weighting factors. We then reduce the carrying amount, if higher, to estimated fair value.

We review proved oil and gas properties at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows to the carrying value. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value, which we estimate by discounting the projected future cash flows using an appropriate risk-adjusted rate.

We evaluate whether the value of all other long-lived assets, including our midstream assets, is impaired when circumstances indicate the carrying value of those assets may not be recoverable. Such circumstances could result from events such as changes in the condition of an asset, changes to planned throughput or a change in our intent to utilize the asset. The determination of recovery is based on undiscounted cash flow projections or the likely cash flow from sale of the assets compared to the carrying value of the assets. If the carrying amount exceeds undiscounted future net cash flows, we adjust the carrying amount of the assets to their estimated fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent comparable sales, estimated replacement cost, an internally-developed, market participant-based discounted cash flow analysis, an analysis from outside professional advisors or, if the long-lived asset is to be sold, utilizing the likely cash flow from sale as the best estimate of fair value.

Exploration Expense

Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired or expiring leases with no expected development, delay rentals, gains or losses on settlement of asset retirement obligations, salaries for geologically-focused employees and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well yields commercial reserves.  If the exploratory well is determined to be unsuccessful, the cost is expensed as exploration expense in the period of that determination. If the exploratory well yields commercial reserves, it is transferred to proved oil and gas properties. Exploratory well costs may continue to be capitalized for several reporting periods if the assessment of commerciality is ongoing.

Equity Method Investment

Equity Method Investment

We account for investments that we do not control, but in which we can exercise significant influence, using the equity method of accounting. Such investments are originally recorded at our acquisition cost. The investment is adjusted by our proportionate share of the investee’s net income, increased by contributions made and decreased by distributions received.

We assess the carrying value of our equity method investments for impairment when indicators exist indicating an impairment may be other-than-temporary. If an impairment is deemed to be other-than-temporary, we adjust the carrying value to fair value, if lower.

Deferred Financing Costs

Deferred Financing Costs

Deferred financing costs reflect fees paid to lenders and third parties that are directly related to our establishment of our long term debt. Prior to the bankruptcy filing by the Initial Debtors, the costs associated with the Alta Mesa RBL were amortized over the term of the Alta Mesa RBL as additional interest expense, with the remaining unamortized costs written off to “reorganization items, net” in our statement of operations upon the bankruptcy filing. The costs associated with the KFM Credit Facility are reported as non-current assets and are amortized over the term of the KFM Credit Facility as additional interest expense but were written off in January after it filed for bankruptcy. During the Predecessor Periods, costs associated with the issuance of our 7.875% senior unsecured notes maturing in December 2024 (the “2024 Notes”) were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense. These Predecessor defined financing costs were eliminated with the Business Combination’s adjustment to 2024 Notes to fair value.

Acquisitions

Acquisitions

Business combinations are accounted for using the acquisition method. The results of operations of any acquired businesses are included in our results of operations from the closing date. The total cost of each acquisition is allocated to tangible and intangible assets acquired and liabilities assumed based on their estimated fair values at the time of the acquisition.

Intangible Assets

Intangible Assets 

In connection with the acquisition of KFM, we recognized the estimated fair value of acquired customer contracts and related customer relationships as intangible assets, which were valued using the income approach. These intangible assets, all of which related to the Midstream segment, had finite lives and were subject to amortization utilizing an accelerated attrition method to approximate the benefit received over their economic lives.

Goodwill

Goodwill

We recognized goodwill as the excess of the purchase price over the estimated fair value of the identified assets and liabilities acquired in the Business Combination. Goodwill was not amortized but was subject to periodic impairment assessment at least annually, or whenever events and circumstances indicated an impairment may exist. 

Asset Retirement Obligations

Asset Retirement Obligations 

We recognize liabilities for the anticipated future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets by increasing the carrying amount of the related long-lived asset at the time it is legally incurred.  The

fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The asset retirement cost is recognized as depletion or depreciation over the life of the asset.  Accretion expense represents the increase to the discounted liability toward its expected settlement value and is included in “Depreciation, depletion and amortization” in the statements of operations.  Asset retirement obligations are subject to revision primarily for changes related to the estimated timing and cost of abandonment.

There are no material legal or contractual obligations relating to dismantlement, decommissioning or removal of our Midstream assets, other than for certain of our produced water assets, for which asset retirement obligations have been established as of December 31, 2019.

Bond Premium on 2024 Notes

Bond Premium on 2024 Notes  

In connection with the Business Combination, we estimated the fair value of our $500.0 million 2024 Notes at $533.6 million.  The excess fair value above the face value was recognized as a bond premium, which was being amortized as a reduction in interest expense over the remaining term of the notes prior to the time of the bankruptcy filing by the Initial Debtors. The remaining unamortized premium was written off to “reorganization items, net” in our consolidated statement of operations upon the Initial Debtors’ bankruptcy filing.

Derivatives

Derivatives 

We present our derivatives as assets or liabilities at estimated fair value. Changes in fair value of our derivatives, along with realized gains or losses from settlements, are recognized as “Gain (loss) on derivatives” in the statements of operations. Settlements of derivatives are classified as operating cash flows. Where master netting agreements are in place, we net the value of our derivative assets and liabilities with the same counterparty.

Income Taxes

Income Taxes

Successor

Deferred income taxes are provided for the temporary differences between the basis of assets and liabilities for financial reporting and income tax purposes. We classify deferred tax assets and liabilities as noncurrent.

We assess the ability to realize our deferred tax assets on a quarterly basis. Deferred tax assets may be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. A valuation allowance is established to reduce deferred tax assets to the amount expected to be realized when we determine that it is more likely than not that some or all of the deferred tax assets are not realizable.

We are also subject to the Texas margin tax, which is considered an income-based tax. We recognize tax (current and deferred) based on taxable income, as determined using the rules for the margin tax as a component of our income tax provision.

We assess uncertain tax positions using a two-step process. If we determine it is more likely than not that the income tax position will be sustained upon examination by the taxing authorities, we recognize the largest amount that is greater than 50% likely to be realized upon ultimate settlement. We have considered our exposure under the standard at both the federal and state tax levels. We did not record any liabilities for uncertain tax positions as of December 31, 2019 or December 31, 2018.

We record interest and penalties for the taxation, as a component of income tax expense. We did not incur any material tax interest or penalties for any period presented.

Alta Mesa’s tax returns for the years ended December 31, 2016 and forward remain open for examination, but none are currently under examination by the relevant authorities.

Predecessor

Alta Mesa historically elected to be treated as an individual partnership for tax purposes. Accordingly, its items of income, expense, gains and losses flowed through to the partners and were taxed at the partner level. Accordingly, no tax provision for federal income taxes was recognized by the Predecessor.

Predecessor net income (loss) for financial statement purposes differed significantly from taxable income (loss) reported to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under Alta Mesa’s amended and restated partnership agreement.  As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes could not be readily determined due to some tax basis differences being determined at the partner level and Alta Mesa’s lack of information about each unitholder’s tax attributes in Alta Mesa.

Revenue Recognition

Revenue Recognition

Predecessor -

Oil, natural gas, and NGL revenue were recognized when production was sold to a purchaser at a fixed or determinable price, when delivery had occurred and title had transferred, and collectibility of the revenue was reasonably assured. During the Predecessor Periods, we followed the sales method of accounting for revenue. Under this method of accounting, revenue was recognized based on volumes sold. There were no material gas imbalances during the periods presented.

Successor (Upstream) -

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU and the associated subsequent amendments (collectively, “ASC 606”), superseded virtually all of the revenue recognition guidance under GAAP. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services.

Our revenue from contracts with customers includes the sale of crude oil, natural gas, and NGLs. These sales are recognized as revenue when production is sold to a customer in fulfillment of performance obligations under the terms of the underlying contracts. Performance obligations primarily comprise delivery of our production at a delivery point, as negotiated within each contract. Each unit of oil, natural gas, and NGL is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.

Performance obligations are satisfied once control of the product has been transferred to the customer. We consider a variety of facts and circumstances in assessing the point control is transferred, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, our right to payment, and transfer of legal title. Moreover, as part of the process of applying the five-step model, we also evaluated AMH’s and KFM’s arrangement in following the principal-versus-agent guidance under ASC 606. As a principal seller to the customer, revenues are recognized on a gross basis, and as an agent, revenue are recognized on a net basis.

Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price or at purchaser posted prices for the producing area. For oil contracts, AMH is considered to be the principal seller to its customers, and we record sales and related expenses on a gross basis upon satisfaction of our performance obligations.

Our natural gas production is primarily sold to purchasers at prevailing market prices. We evaluate the contract terms of our gas processing arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis based on the assessment of control and, when applicable, principal versus agent guidance under ASC 606. During the Successor Period, we determined that we controlled the products during processing (i.e., control transfers at the tailgate of the processing plant) or until the processor’s sale to the end customers in downstream markets (i.e., the processor is our agent and we are the principal selling party). Accordingly, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the customer and the gathering and processing services are rendered, similar to the accounting treatment required under previous revenue accounting guidance. However, instances in which all or a significant percentage of the proceeds from the sale must be returned to the producer, we are deemed to be the agent. As a result, the purchase and sale are presented as a net transaction with our margin included in gathering and processing revenue. When evaluating the principal-versus-agent guidance under ASC 606 and its impact on AMH and KFM, all facts and circumstances are considered and judgment is often required in making this determination.

Customers are invoiced once our performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30-60 days. There are no significant judgments that

affect the amount or timing of revenue from contracts with customers. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities, apart from production receivables.

Our receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates, as well as for unbilled costs for wells subject to Oklahoma’s forced pooling process in which mineral owners have the option to participate in the drilling of pooled wells. Depending on the mineral owner’s decision, these costs will be billed to them or added to our oil and gas properties or lease operating expense. Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts.

We have concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors and have reflected this disaggregation of revenue for all periods presented.

We do not have material unsatisfied performance obligations for contracts as all contracts have either an original expected length of one year or less or the entire future consideration is variable and allocated entirely to a wholly unsatisfied performance obligation.

Midstream -

We have the following significant revenue sources each of which we consider to be a distinct service and each of which possesses a single performance obligation:

• Natural gas gathering, processing and sale of residue gas and NGLs for Alta Mesa and third parties;

• Crude oil gathering for Alta Mesa; and

• Produced water gathering and disposal for Alta Mesa and third parties.

We provide our services pursuant to a variety of contracts that set forth our fees, including in certain contracts, the percentage of the proceeds from the sale of our customers’ products in addition to the specified fee. Our services are typically billed on a monthly basis in the month following services or delivery of the product with payment typically due within 30 days. We do not offer extended payment terms and we have no contracts with financing components. Our gathering contracts have initial terms that span multiple years up to the life of the dedicated properties. Our most significant produced water contract has an initial term of 15 years.

We recognize revenue principally under contracts that contain one or more of the following arrangements:

Fee-based arrangements

Revenue for fee-based arrangements are recognized over the contract term with revenue recognized for each month of service based on the volumes delivered by the customer. Both natural gas gathering and processing plus crude oil gathering services are recognized in gathering and processing revenues. Produced water services are recognized as produced water disposal fees.

For service rates that are unchanged over the contract term or escalate only due to inflation, we recognize revenue at the rate in effect during the month of service. We have instances where we also charge supplemental fees for an early period of time during the contract term and this revenue is recognized over the expected period of customer benefit, which is generally the remaining term of the contract. The difference between the amount billed and collected for such early term fees billed during the initial contract term and the amount recorded as revenue is deferred and recognized as contract liabilities. At December 31, 2019 and 2018, we had recognized a deferral of $3.4 million and $1.7 million, respectively, of these early term fees which is included in other long-term liabilities.

Percent-of-proceeds arrangements

Under our percent-of-proceeds arrangements, we generally receive natural gas from producers at or near the wellhead, move it through our gathering system, process it to separate the gas and liquid products and sell the resulting gas and NGLs to third parties. We then remit to the producers an agreed-upon percentage of the actual proceeds received from sales. The margins we earn are directly related to the volumes that flow through our system and the price at which we are able to sell the products.

We evaluate our percent-of-proceeds arrangements with customers against the principal/agent provisions of the underlying contract. For those arrangements where we possess control of the commodity after processing and act as principal in the sale, we record sales revenue equal to the gross price received and we recognize the cost paid to the purchaser as cost of sales of

gathered purchased production. For those percent-of-proceeds arrangements where we do not control the products after processing, because substantially all of the sales proceeds are paid to the producer, we act as an agent for the producer and only recognize the net margin that we earn within sales of gathered production.

In limited instances, we may also receive products as consideration under percent-of-proceeds agreements. We recognize revenue for the products received at their fair value in the month of service.

Sale of gathered production

We sell gas, NGLs and condensate purchased from our customers to third parties pursuant to short term arrangements at market-based prices adjusted for location and quality differentials. These sales are recognized at the point (i) when we satisfy our performance obligation by transferring control of the product to the purchaser at the specified delivery point, (ii) when amounts are determinable and (iii) when we determine that collectibility is probable. The determination of the point control is transferred relies upon a variety of facts and circumstances including: the purchaser’s ability to use the products, the transfer of significant risks and rewards, our right to payment and transfer of legal title. The cost to purchase the underlying products is recognized when we obtain control of the product, but is generally concurrent with their sale.

Also, we may sell products to other midstream companies pursuant to off-take agreements. Under these contracts, we evaluate whether we control the products during processing and whether the processor controls the products in their sale to the ultimate purchaser. For those contracts where we do not control the products during processing, we recognize revenue on their sale to the midstream company based on the price received net of processing fees earned by the midstream company. For those contracts where we control the products during processing and where we direct their sale, we recognize revenue on the gross price received within sales of gathered production and we recognize the fees paid to the midstream company as transportation, processing and marketing expense.

Equity-Based Compensation

Equity-Based Compensation 

In 2018, we granted various types of stock-based awards, including stock options, restricted stock and performance-based restricted stock units to certain of our employees.

The fair value of stock option awards is determined using the Black-Scholes option pricing model, which includes various assumptions. Expected volatilities utilized in the option pricing model are based on the re-levered asset volatility implied by a set of comparable companies.  Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date.  Dividend yield is based on our expectations of dividend payments during the expected term of the options granted and risk-free interest rates are based on U.S. Treasury rates in effect at the grant date.

Service-based restricted stock awards are valued using the market price of our Class A Common Stock on the grant date. Performance-based restricted stock awards are valued using the market price of Class A Common Stock at the later of grant date and when all performance-based criteria are determined.

We recognize the estimated fair value of stock option and restricted stock awards as compensation expense on a straight-line basis over the applicable vesting period, which generally is 3.0 years, except in the case of awards made to our directors, which vest immediately upon issuance. Awards of performance-based restricted stock units that contain tranches with multi-year performance targets are recognized over the vesting period for which performance criteria for each tranche have been determined. All awards to employees typically require continued employment to vest. Forfeitures of unvested awards are recognized when they occur and result in the reversal of previously recognized expense.

Fair Value Hierarchy

Fair Value Hierarchy

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date within our principal market.

There are three levels of the fair value hierarchy:

• Level 1 — Fair value is based on quoted prices in active markets for identical assets or liabilities.

• Level 2 — Fair value is determined using significant observable inputs, generally either quoted prices in active markets for similar assets or liabilities, or quoted prices in markets that are not active.

• Level 3 — Fair value is determined using one or more significant inputs that are unobservable in active markets at the measurement date. Such inputs are often used in pricing models, discounted cash flow calculations, or similar techniques.

We utilize fair value measurements to account for certain items, determine certain account balances and provide disclosures. Fair value measurements are also utilized in assessing the impairment of long-lived assets.

We consider the book values of our cash, accounts and notes receivable and current liabilities to approximate fair value due to their short-term nature. Our outstanding borrowings under the Alta Mesa RBL have been classified as liabilities subject to compromise at December 31, 2019 and the outstanding borrowings under the KFM Credit Facility will be classified similarly following the January 2020 bankruptcy filing by the Additional Debtors as full recovery by our lenders following the expected sale of substantially all of our assets is unlikely.

Earnings Per Share

Earnings Per Share 

Basic earnings per share is calculated by dividing earnings available to Class A common stockholders by the weighted average number of shares outstanding during each period. In periods where we report negative earnings, basic and diluted earnings per share are identical.

The Company uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding SRII Opco Common Units and corresponding shares of its outstanding Class C Common Stock, as well as outstanding warrants and the treasury stock method to determine the potential dilutive effect of restricted stock, restricted stock units and stock options.

Recent Issued Accounting Standards Applicable to Us

Recently Issued Accounting Standards Applicable to Us

Adopted

As described further in Note 5, we adopted Accounting Standards Update 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, effective January 1, 2019.

Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today and would have been effective for us beginning January 2023. We made no determination as to the impact of this new standard on our financial position or results of operations upon adoption.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard, on a prospective basis, beginning January 2020.

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

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INCOME TAXES

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

As a result of the Business Combination, our wholly owned subsidiary, SRII Opco GP, is the general partner of SRII Opco, which became the sole managing member of Alta Mesa GP and KFM, and as a result, we began consolidating the financial results of Alta Mesa and KFM. SRII Opco is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, SRII Opco is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by SRII Opco is passed through to and included in the taxable income or loss of its limited partners, including the Company, on a pro rata basis. The Company is subject to U.S. federal income taxes, in addition to state and local income taxes, with respect to its allocable share of any taxable income or loss of SRII Opco, as well as any stand-alone income or loss generated by the Company.

Income tax expense (benefit) included in the statements of operations is detailed below:

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(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Current taxes:
Federal	$	—	$	(69	)
State	—		—
	—		(69		)
Deferred taxes:
Federal	—		—
State	—		—
	—		—
Income tax expense (benefit)	$	—	$	(69	)

A reconciliation of the statutory federal income tax expense to the income tax expense from continuing operations is as follows:

(Amounts in thousands)	Year Ended December 31, 2019					February 9, 2018 Through December 31, 2018
Federal income tax expense (benefit) - at statutory rate	$	(195,221	)	21.00	%	$	(682,378	)	21.00%
State income taxes - net of federal income tax benefit	(44,064		)	4.74		(154,022		)	4.74
Non-controlling interest	123,316			(13.27	)	833,239			(25.64	)
Return to provision	(1,690		)	0.18		(71		)	—
Change in valuation allowance	136,568			(14.69	)	3,135			(0.1	)
Permanent items	—			—		25			—
Other	(18,909		)	2.04		3			—
Income tax expense (benefit)	$	—		—	%	$	(69	)	—	%

The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities are presented below:

(in thousands)	December 31, 2019			December 31, 2018
Deferred tax asset:
Investment in SRII Opco, LP	$	424,086		$	269,846
59(e) capitalized IDC	53,814			—
NOL carryforward	29,866			101,337
Organizational/startup costs	144			154
Other	7			11
Total deferred tax assets	507,917			371,348
Less: valuation allowance	(507,917		)	(371,348		)
Net deferred tax assets	—			—
Deferred tax liability	—			—
Total net deferred tax assets/(liabilities)	$	—		$	—

The change in our valuation allowance during the year ended December 31, 2019 was $136.6 million.

In connection with the Business Combination, we entered into the Tax Receivable Agreement with SRII Opco, High Mesa, and the Riverstone Contributor. This agreement generally provides for the payment by us of 85% of the amount of net cash savings, if any, in income tax that we actually realize (or are deemed to realize in certain circumstances) in periods after the Business Combination as a result of (i) tax basis increases resulting from the exchange of SRII Opco Common Units for AMR Class A Common Stock and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings.

The payment obligations under the Tax Receivable Agreement are obligations of the Company and not obligations of SRII Opco, and the payments required could have been substantial. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been entitled to any of the tax benefits subject to the Tax Receivable Agreement. In other words, we would calculate our federal, state and local income tax liabilities as if no tax attributes arising from a redemption or direct exchange of SRII Opco Common Units had been transferred to us. The term of the Tax Receivable Agreement continues until all such tax benefits have been utilized or have expired, unless we exercise our right to terminate the Tax Receivable Agreement or the Tax Receivable Agreement is otherwise terminated.

As of December 31, 2019, there has been one exchange of SRII Common Units which would trigger a payment under the TRA. This exchange occurred in November 2018 when 2,752,312 SRII Opco Common Units were converted into the same number of shares of AMR Class A Common Stock. We have calculated the tax basis increase resulting from this exchange, and the resulting potential future net cash income tax savings multiplied by 85% to arrive at a potential Tax Receivable Agreement liability. This amount would be due and payable by us if we actually realized these future cash tax savings. However, as of December 31, 2019 we have recorded a full valuation allowance on our other deferred tax assets determined in accordance with GAAP, and therefore we have not realized any savings and have recorded no liability for such at this time. We believe there is a very low likelihood that we will utilize these attributes in 2020 or future years, due to the expected outcome of our bankruptcy filing.

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Components Of The Standardized Measure Of Discounted Future Net Cash Flows) (Details) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018 USD ($) MMcf $ / bbl	Dec. 31, 2018 USD ($) MMcf $ / bbl	Dec. 31, 2019 USD ($) MMcf $ / bbl	Dec. 31, 2017 USD ($)
Components of the standardized measure of discounted future net cash flows
Future cash inflows	$ 5,798,886	$ 2,446,888	$ 1,326,490
Future production costs	(2,556,361)	(1,214,479)	(825,300)
Future development costs	(965,780)	(23,183)	(25,251)
Future income taxes	0	(146,632)	(26,707)
Future net cash flows	2,276,745	1,062,594	449,232
Discount to present value at 10 percent per annum	(1,096,859)	(348,311)	(122,321)
Standardized measure of discounted future net cash flows	$ 1,179,886	$ 714,283	$ 326,911	$ 1,105,922
Base price for crude oil, per barrel, in the above computation | $ / bbl	52.89	65.56	55.69
Base price for gas, per Mcf, in the above computation | MMcf	2.99	3.10	2.58
Realized price for NGLs, per barrel, in the above computation | MMcf	27.48	22.44	14.60

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RECEIVABLES (Tables)

12 Months Ended

Dec. 31, 2019

Receivables [Abstract]

Schedule of Accounts Receivable

(in thousands)	December 31, 2019			December 31, 2018
Production and processing sales and fees	$	40,858		$	51,004
Joint interest billings	12,845			18,147
Pooling interest (1)	7,901			18,786
Allowance for doubtful accounts	(417		)	(95		)
Total accounts receivable, net	$	61,187		$	87,842

_________________

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

Related Party Receivables

(in thousands)	December 31, 2019			December 31, 2018
Related party receivables	$	12,144		$	12,376
Allowance for doubtful accounts	(12,144		)	(9,035		)
Related party receivables, net	—			3,341
Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Related party receivables, net	$	—		$	3,341

Management Services Agreement with HMI

(in thousands)
HMI related party receivable at December 31, 2018	$	10,066
Additions	832
Payments	(1,073		)
HMI related party receivable at December 31, 2019	9,825
Allowance for doubtful accounts(1)	(9,825		)
Balance at December 31, 2019, net	$	—

_________________

(1)

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

Activity in our allowances for doubtful accounts for trade and related party receivables was as follows:

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Trade receivables:
Balance at beginning of period	$	95		$	415		$	415
Charged to expense	332			25			—
Deductions	(10		)	(345		)	—
Balance at end of period	$	417		$	95		$	415
Related party receivables:
Balance at beginning of period	$	22,438		$	—		$	—
Charged to expense	3,196			22,438			—
Deductions	(87		)	—			—
Balance at end of period	$	25,547		$	22,438		$	—

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SIGNIFICANT CONCENTRATIONS (Details) - USD ($) $ in Thousands	1 Months Ended	8 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2019
Concentration Risk [Line Items]
Revenue marketed by ARM on our behalf	$ 47,639		$ 467,977	$ 489,858
Customer Concentration Risk | Sales Revenue, Net | One Customer
Concentration Risk [Line Items]
Percent of operating revenue accounted for by customer				40.50%
AEM
Concentration Risk [Line Items]
Revenue marketed by ARM on our behalf	28,757	$ 336,248		$ 123,000
Amount paid for marketing fees	66	784		496
Total fees paid to ARM	66	784		2,211
Accounts receivable			$ 43,800	6,800
Marketing fees | AEM
Concentration Risk [Line Items]
Amount paid for marketing fees	$ 0	$ 0		$ 1,715

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ADOPTION OF ASU NO. 2016-02, LEASES ADOPTION OF ASU NO. 2016-02, LEASES

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

ADOPTION OF ASU NO. 2016-02, LEASES

ADOPTION OF ASU NO. 2016-02, LEASES

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

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

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

Upon adoption, we selected the following practical expedients:

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

As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At December 31, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.0 years and the weighted-average discount rate applied was 14.5%.

Lease Costs

(in thousands)	Year Ended December 31, 2019
Operating lease cost	$	3,122
Variable lease cost	1,250
Short-term lease cost	4,410
Total lease cost	$	8,782
Reported in:
Lease operating expense	$	4,241
General and administrative expense	4,541
Total lease cost	$	8,782

Remaining Operating Lease Liability Payments as of December 31, 2019

Fiscal year	(in thousands)
2020	$	2,256
2021	2,209
2022	2,329
2023	2,321
2024	2,367
Thereafter	8,219
Total lease payments	19,701
Less: imputed interest	(8,336		)
Less: reclassification to liabilities subject to compromise	(11,088		)
Present value of operating lease liabilities	$	277
Current portion of operating lease liabilities	$	88
Operating lease liabilities, net of current portion	189
Present value of operating lease liabilities	$	277

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SIGNIFICANT ACQUISITIONS AND DIVESTITURES

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

SIGNIFICANT ACQUISITIONS AND DIVESTITURES

SIGNIFICANT ACQUISITIONS AND DIVESTITURES

We made no acquisitions or divestitures during 2019.

2018 Activity

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

Pursuant to the Contribution Agreements, SRII Opco acquired (a) (i) all of the limited partner interests in Alta Mesa and (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa GP, ((i) and (ii) collectively, the “AM Contribution”) and (b) 100% of the economic interests in KFM (the “KFM Contribution”). SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco, is a wholly owned subsidiary of AMR.  As a result of the Business Combination, our only significant asset was our ownership at that time of an approximate 44.2% partnership interest in SRII Opco. SRII Opco owns all of the economic interests in each of Alta Mesa and KFM. SRII Opco was deemed to be a variable interest entity (“VIE”) and we were deemed to be the primary beneficiary of SRII Opco and have control of SRII Opco through our voting control of SRII Opco GP. Accordingly, we consolidate both SRII Opco and SRII Opco GP, including their consolidated subsidiaries, in our financial results.

Immediately prior to the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa. 

At the closing of the Business Combination:

• we issued (i) 40,000,000 shares of our Class A Common Stock and (ii) warrants to purchase 13,333,333 shares of our Class A Common Stock to Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”) pursuant to the terms of that certain

Forward Purchase Agreement, dated as of March 17, 2017 (the “Forward Purchase Agreement”) for cash proceeds of $400 million to us;

• we contributed $1,338 million in cash representing (i) the proceeds from the Forward Purchase Agreement and (ii) the net proceeds, after redemptions and payment of deferred underwriting compensation, of the Trust Account, less transaction fees, amounts due Silver Run Sponsor II, LLC. (our “Sponsor”) and reimbursement of seller transaction fees and costs to SRII Opco, in exchange for (i) 169,371,730 of the common units (approximately 44.2%) representing limited partner interests in SRII Opco (the “SRII Opco Common Units”) and (ii) 62,966,651 warrants to purchase SRII Opco Common Units (“SRII Opco Warrants”);

• we caused SRII Opco to issue 213,402,398 SRII Opco Common Units (approximately 55.8%) to the Contributors in exchange for the ownership interests in Alta Mesa, Alta Mesa GP and KFM;

• we agreed to cause SRII Opco to issue up to 59,871,031 SRII Opco Common Units to High Mesa and KFM Holdco if the earn-out conditions were met pursuant to the terms of the Contribution Agreements;

• the Company issued to each of the Contributors a number of shares of Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), equal to the number of the SRII Opco Common Units received by each such Contributor;

• SRII Opco distributed $814.8 million to KFM Holdco in partial payment for the ownership interests in KFM; and

• SRII Opco entered into an amended and restated voting agreement with the owners of the remaining 10% voting interests in Alta Mesa GP whereby such other owners agreed to vote their interests in Alta Mesa GP as directed by SRII Opco.

Holders of our Class C Common Stock, together with holders of Class A Common Stock, voting as a single class, have the right to vote on all matters properly submitted to a vote of the stockholders, but holders of Class C Common Stock are not entitled to any dividends or liquidating distributions from us. The Contributors generally have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. However, we may, at our option, effect a direct exchange of cash or Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption by SRII Opco. Upon the future redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be canceled.

During 2019 and 2018, the Contributors redeemed 2,181,600 and 12,341,076, respectively of SRII Opco Common Units for an equal number of shares of Class A Common Stock through a direct exchange, whereby the combined 14,522,676 SRII Opco Common Units are now owned by us, and we issued an equal number of shares of our Class A Common Stock to them and canceled the related shares of our Class C Common Stock. Additionally, during 2018 we sold 3,101,510 of our Common Units in SRII Opco to SRII Opco to fund purchases of an equivalent number of our Class A common shares. As a result of these and other transactions, at December 31, 2019, we own approximately 47.75% of the limited partner interests in SRII Opco.

Pursuant to the Contribution Agreements, until February 2025, the Contributors were entitled to receive additional SRII Opco Common Units as earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of our Class A Common Stock equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):

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

The Contributors were entitled to the earn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of our assets, if the consideration paid to holders of Class A Common Stock exceeds the above-specified 20-Day VWAP hurdles. The expected sale of substantially all of our assets by mid-April 2020 will not trigger any earn-out consideration.

We also contributed $560.0 million in cash to Alta Mesa at the closing of the Business Combination.  

Purchase Price for Alta Mesa

(in thousands)	February 9, 2018
Purchase Consideration: (1)
SRII Opco Common Units issued (2)	$	1,261,249
Estimated fair value of contingent earn-out purchase consideration (3)	284,109
Settlement of preexisting working capital	5,476
Total purchase price consideration	$	1,550,834

_________________

(1) The purchase price consideration was for 100% of the limited partner interests in Alta Mesa and 100% of the economic interests and 90% of the voting interests in Alta Mesa GP.  

(2) At closing, the Riverstone Contributor received 20,000,000 SRII Opco Common Units and High Mesa received 138,402,398 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, High Mesa received an additional 1,197,934 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity.

(3) For a period of seven years following Closing, High Mesa was to be entitled to receive earn-out consideration in the form of SRII Opco Common Units. We determined that the fair value of the earn-out consideration was approximately $284.1 million, which was classified as equity. The fair value of the contingent earn-out was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to the Company (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining term of the earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.

Purchase Price for KFM

(in thousands)	February 9, 2018
Purchase Consideration:
Cash (1)	$	809,812
SRII Opco Common Units issued (2)	433,931
Estimated fair value of contingent earn-out purchase consideration (3)	88,105
Settlement of preexisting working capital	(5,476		)
Total purchase price consideration	$	1,326,372

_________________

(1) The cash consideration paid at February 9, 2018 was net of estimated net working capital adjustments, transaction expenses, capital expenditures and banking fees. Pursuant to a final closing statement during the second quarter of 2018, KFM Holdco remitted back to the Company $5.0 million in cash.

(2) At closing, KFM Holdco, LLC received 55,000,000 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, KFM Holdco remitted back 89,680 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock. The SRII Common Units were valued at approximately $7.90 per unit, reflecting discounts for holding requirements and liquidity.

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

Acquisition of acreage

In October 2018, we completed a transaction to acquire certain unproved oil and gas properties for $22.3 million, net of customary post-closing purchase price adjustments.  The acquisition was funded utilizing borrowings under the Alta Mesa

RBL.

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EQUITY-BASED COMPENSATION (Successor) (Summary of Assumptions Used to Determine the Fair Value of Options) (Details) - Stock options	11 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)	4 years 6 months	4 years 6 months
Expected stock volatility	64.60%	69.80%
Dividend yield	0.00%	0.00%
Risk-free interest rate	2.50%	2.40%

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EARNINGS PER SHARE (Net Loss Attributable to Common Stockholders) (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (14,862)	$ (1,524,699)	$ (450,538)
Loss per common share attributable to AMR common stockholders:
Basic and diluted loss per common share attributable to AMR common stockholders (in dollars per share)		$ (8.71)	$ (2.48)
Common Class A
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss		$ (1,524,699)	$ (450,538)
Effect of dilutive securities:
Weighted average common shares outstanding (Basic and Diluted) (in shares)		175,151,969	181,636,795
Loss per common share attributable to AMR common stockholders:
Basic and diluted loss per common share attributable to AMR common stockholders (in dollars per share)		$ (8.71)	$ (2.48)

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DISCONTINUED OPERATIONS (Predecessor) (Schedule Of Operations And Other Items Reclassified In Discontinued Operations) (Details) - Non-Stack Assets - Weeks Island Field, Louisiana - Disposed of by Sale $ in Thousands	1 Months Ended
	Feb. 08, 2018 USD ($)
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 income (expense)
Interest expense	(103)
Total other expense	(103)
Loss from discontinued operations, net of state income taxes	$ (7,746)

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PROPERTY AND EQUIPMENT (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Unproved properties	$ 813,310	$ 816,282
Accumulated impairment of unproved properties	(813,310)	(742,065)
Unproved properties, net	0	74,217
Proved oil and gas properties	2,239,444	2,110,346
Accumulated depreciation, depletion, amortization and impairment	(2,024,092)	(1,421,226)
Proved oil and gas properties, net	215,352	689,120
Total oil and gas properties, net	215,352	763,337
Land	5,690	5,600
Fresh water wells	27,373	27,366
Produced water disposal system	108,966	104,498
Gas processing plant and gathering lines	414,615	380,470
Office furniture, equipment and vehicles	3,397	3,703
Accumulated depreciation and impairment	(453,013)	(77,368)
Other property and equipment, net	107,028	444,269
Total property and equipment, net	$ 322,380	$ 1,207,606

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RECEIVABLES (Schedule of Related Party Receivables) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Receivables [Abstract]
Related party receivables	$ 12,144	$ 12,376
Allowance for doubtful accounts	(12,144)	(9,035)
Related party receivables, net	0	3,341
Notes receivable from related parties	13,403	13,403
Allowance for doubtful accounts	(13,403)	(13,403)
Notes receivable from related parties, net	0	0
Related party receivables, net	$ 0	$ 3,341

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ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2019

Payables and Accruals [Abstract]

Detail of Accounts Payable and Accrued Liabilities

	Successor
(in thousands)	December 31, 2019			December 31, 2018
Accounts payable	$	27,349		$	20,422
Accruals for capital expenditures	1,244			139,904
Revenue and royalties payable	27,355			50,241
Accruals for operating expenses	25,131			21,830
Accrued interest	9,663			2,477
Derivative settlements	511			109
Other	1,716			12,456
Total accrued liabilities	65,620			227,017
Less: liabilities subject to compromise	(28,832		)	—
Accounts payable and accrued liabilities	$	64,137		$	247,439

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule Of Components Of Income Tax Expense (Benefit)

Income tax expense (benefit) included in the statements of operations is detailed below:

໿

(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Current taxes:
Federal	$	—	$	(69	)
State	—		—
	—		(69		)
Deferred taxes:
Federal	—		—
State	—		—
	—		—
Income tax expense (benefit)	$	—	$	(69	)

Schedule of Effective Income Tax Rate Reconciliation

A reconciliation of the statutory federal income tax expense to the income tax expense from continuing operations is as follows:

(Amounts in thousands)	Year Ended December 31, 2019					February 9, 2018 Through December 31, 2018
Federal income tax expense (benefit) - at statutory rate	$	(195,221	)	21.00	%	$	(682,378	)	21.00%
State income taxes - net of federal income tax benefit	(44,064		)	4.74		(154,022		)	4.74
Non-controlling interest	123,316			(13.27	)	833,239			(25.64	)
Return to provision	(1,690		)	0.18		(71		)	—
Change in valuation allowance	136,568			(14.69	)	3,135			(0.1	)
Permanent items	—			—		25			—
Other	(18,909		)	2.04		3			—
Income tax expense (benefit)	$	—		—	%	$	(69	)	—	%

Schedule of Deferred Tax Assets and Liabilities

The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities are presented below:

(in thousands)	December 31, 2019			December 31, 2018
Deferred tax asset:
Investment in SRII Opco, LP	$	424,086		$	269,846
59(e) capitalized IDC	53,814			—
NOL carryforward	29,866			101,337
Organizational/startup costs	144			154
Other	7			11
Total deferred tax assets	507,917			371,348
Less: valuation allowance	(507,917		)	(371,348		)
Net deferred tax assets	—			—
Deferred tax liability	—			—
Total net deferred tax assets/(liabilities)	$	—		$	—

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) segment	Nov. 30, 2019	Dec. 31, 2018 USD ($)	Feb. 08, 2018
Summary Of Significant Accounting Policies [Line Items]
Number of operating units | segment	2
Deferral included in other long-term liabilities	$ 3,360,000		$ 1,667,000
Vesting period	3 years
7.875% Senior Unsecured Notes Due 2024
Summary Of Significant Accounting Policies [Line Items]
Face value of senior notes issued	$ 500,000,000		$ 500,000,000
Alta Mesa | 7.875% Senior Unsecured Notes Due 2024
Summary Of Significant Accounting Policies [Line Items]
Stated interest rate of senior notes	7.875%			7.875%
Face value of senior notes issued	$ 500,000,000.0
Fair value of senior notes payable	$ 533,600,000
Cimarron Express Pipeline, LLC
Summary Of Significant Accounting Policies [Line Items]
Percentage of ownership acquired		50.00%
Processing Plant And Pipelines
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment	35 years
Compressors
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment	25 years
Property, Plant and Equipment, Other Types | Minimum
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment	3 years
Property, Plant and Equipment, Other Types | Maximum
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment	7 years

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ADOPTION OF ASU NO. 2016-02, LEASES (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Schedule of Practical Expedients

Upon adoption, we selected the following practical expedients:

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

Lease Cost

Lease Costs

(in thousands)	Year Ended December 31, 2019
Operating lease cost	$	3,122
Variable lease cost	1,250
Short-term lease cost	4,410
Total lease cost	$	8,782
Reported in:
Lease operating expense	$	4,241
General and administrative expense	4,541
Total lease cost	$	8,782

Maturities of Operating Lease Liabilities

Remaining Operating Lease Liability Payments as of December 31, 2019

Fiscal year	(in thousands)
2020	$	2,256
2021	2,209
2022	2,329
2023	2,321
2024	2,367
Thereafter	8,219
Total lease payments	19,701
Less: imputed interest	(8,336		)
Less: reclassification to liabilities subject to compromise	(11,088		)
Present value of operating lease liabilities	$	277
Current portion of operating lease liabilities	$	88
Operating lease liabilities, net of current portion	189
Present value of operating lease liabilities	$	277

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Label	Element	Value
Asset Retirement Obligation	us-gaap_AssetRetirementObligation	$ 0

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

12 Months Ended

Dec. 31, 2019

Supplemental Oil and Natural Gas Disclosures [Abstract]

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

We determined for 2018 reporting that it was not probable that we would have the necessary capital to develop our PUD reserves. Thus, we have concluded that we do not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our available drilling locations.

The unaudited reserve and other information presented below is provided as supplemental information.  The information presented during the 2018 Predecessor Period includes amounts related to discontinued operations.

Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Reserve estimates incorporate assumptions regarding future prices and costs at the date estimates are made. Actual future prices and costs may be materially higher or lower. Actual future net revenue will also be affected by factors such as actual production, supply and demand for oil and gas, curtailments or increases in consumption by gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.

Oil and gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

Estimated Quantities of Proved Reserves

The following table sets forth our net proved reserves as of December 31, 2019 and 2018 and February 8, 2018, and the changes therein during the periods then ended.

	Oil (Mbbls)		Gas (MMcf)		NGL’s (Mbbls)		Boe (Mbbls)
Total Proved Reserves:
Balance at December 31, 2017 (Predecessor)	73,518		433,519		36,887		182,658
Production	(521	)	(1,984	)	(161	)	(1,012	)
Sales of reserves in place (1)	(1,667	)	(24,239	)	(771	)	(6,478	)
Revisions of previous quantity estimates and other	375		3,506		289		1,248
Balance at February 8, 2018 (Predecessor)	71,705		410,802		36,244		176,416
Production(2)	(5,053	)	(16,913	)	(2,268	)	(10,140	)
Purchases in place(2)	2,658		13,331		1,751		6,631
Discoveries and extensions(2)	30,026		155,306		19,646		75,557
Revisions of previous quantity estimates and other(2)	(74,064	)	(418,378	)	(35,581	)	(179,375	)
Balance at December 31, 2018 (Successor)	25,272		144,148		19,792		69,089
Production	(5,885	)	(24,802	)	(2,760	)	(12,779	)
Discoveries and extensions	4,265		24,351		2,835		11,159
Revisions of previous quantity estimates and other(3)	(6,736	)	(29,254	)	(9,352	)	(20,964	)
Balance at December 31, 2019 (Successor)	16,916		114,443		10,515		46,505
Proved Developed Reserves:
Balance at December 31, 2017	20,347		150,183		12,180		57,557
Balance at February 8, 2018	19,345		126,231		11,348		51,731
Balance at December 31, 2018	25,272		144,148		19,792		69,089
Balance at December 31, 2019	16,916		114,443		10,515		46,505
Proved Undeveloped Reserves:
Balance at December 31, 2017	53,171		283,336		24,707		125,101
Balance at February 8, 2018	52,360		284,571		24,896		124,685
Balance at December 31, 2018	—		—		—		—
Balance at December 31, 2019	—		—		—		—

_________________

(1) Sales of reserves in place during the 2018 Predecessor Period represent amounts related to our non-STACK properties that were distributed to High Mesa and are classified as discontinued operations in our financial statements.

(2) An analysis of changes in our reserves from February 8, 2018 to December 31, 2018 follows:

	MBoe
Description	Proved Developed Reserves		Proved Undeveloped Reserves		Total
Balance at February 8, 2018	51,731		124,685		176,416
Production	(10,140	)	—		(10,140	)
Purchases in place, discoveries and extensions	35,096		47,092		82,188
Revisions of previous quantity estimates and other:
Lower estimated recoveries identified as a result of 2018 drilling program	(31,964	)	(69,534	)	(101,498	)
Higher average commodity prices in Successor Period compared to 2017	5,367		5,829		11,196
Transfers of PUDs to proved developed reserves	18,999		(18,999	)	—
Derecognition of PUDs due to significant concerns about ability to fund development of those reserves	—		(89,073	)	(89,073	)
Balance at December 31, 2018	69,089		—		69,089

(3) Revisions decreased our estimated recovery of proved reserves and is ratably due to lower average commodity prices in 2019 as compared to 2018, the decision to report ethane rejection rather than ethane recovery, and decreases in volume estimates based on the overall performance of our wells.

Results of Operations for Oil and Gas Producing Activities - Upstream Segment

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Operating revenue	$	423,576		$	414,507		$	40,136
Production expense (1)	232,212			247,748			30,743
Depreciation, depletion and amortization	120,617			133,554			11,670
Exploration expense	52,354			34,085			7,003
Impairment expense	556,427			2,033,712			—
Income tax expense (benefit)	—			4			—
Results of operations	$	(538,034	)	$	(2,034,596	)	$	(9,280	)

_________________

(1) Production expense consists of direct lease operating expense, transportation and marketing expense, production taxes, workover expense and allocated general and administrative expense.

Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
(in thousands)	2019			2018
Capitalized costs:
Proved properties	$	2,239,444		$	2,110,346
Unproved properties	813,310			816,282
Total	3,052,754			2,926,628
Accumulated depreciation, depletion, amortization and impairment	(2,837,402		)	(2,163,291		)
Net capitalized costs	$	215,352		$	763,337

Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities

Acquisition costs in the table below include costs incurred to purchase, lease or otherwise acquire property. Exploration expenses include additions to exploratory wells and other exploration expenses, such as geological and geophysical costs. Development costs include drilling and completion costs plus additions to production facilities and equipment.

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Costs incurred during the period: (1)
Property acquisition
Unproved (2)	$	—	$	54,587	$	4,240
Proved	—		16,300		327
Exploration	7,305		32,130		3,678
Development (3)	134,908		664,138		37,672
	$	142,213	$	767,155	$	45,917

_________________

(1) Costs incurred in the 2018 Predecessor Period include amounts related to non-STACK oil and gas assets, which were distributed in connection with the Business Combination.

(2) Property acquisition costs for unproved properties include the acquisition of unevaluated leasehold portion from an unaffiliated third party of approximately $22.3 million for the 2018 Successor Period.

(3) Includes asset retirement additions (revisions) of $0.9 million and $5.6 million for the 2019 and the 2018 Successor Period, respectively. For the 2018 Predecessor Period, there were no material asset retirement additions (revisions).

Standardized Measure of Discounted Future Net Cash Flows

The following information utilizes reserve and production data prepared by us. Future cash inflows were calculated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month, for the year ended December 31, 2019, the 2018 Successor Period, and for the 2018 Predecessor Period. Well costs, operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. 

The following table sets forth the components of the standardized measure of discounted future net cash flows:

	Successor						Predecessor
(in thousands, except per unit data)	December 31, 2019			December 31, 2018			February 8, 2018
Future cash inflows	$	1,326,490		$	2,446,888		$	5,798,886
Future production costs	(825,300		)	(1,214,479		)	(2,556,361		)
Future development costs	(25,251		)	(23,183		)	(965,780		)
Future income taxes	(26,707		)	(146,632		)	—
Future net cash flows(1)	449,232			1,062,594			2,276,745
Discount to present value at 10 percent per annum	(122,321		)	(348,311		)	(1,096,859		)
Standardized measure of discounted future net cash flows	$	326,911		$	714,283		$	1,179,886
Base price for crude oil, per barrel, in the above computation	$	55.69		$	65.56		$	52.89
Base price for gas, per Mcf, in the above computation	$	2.58		$	3.10		$	2.99
Realized price for NGLs, per barrel, in the above computation	$	14.60		$	22.44		$	27.48

Changes in Standardized Measure of Discounted Future Net Cash Flows

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Balance at beginning of period	$	714,283		$	1,179,886		$	1,105,922
Sales and transfers of oil and gas produced, net of production costs	(253,582		)	(278,091		)	(30,391		)
Net changes in prices and production costs	(270,712		)	38,963			71,334
Revisions of previous quantity estimates	(129,305		)	(1,120,097		)	10,887
Purchases of reserves in-place	—			24,376			—
Sales of reserves in-place(1)	—			—			(4,807		)
Current year discoveries and extensions, less related costs	134,451			684,700			—
Changes in estimated future development costs	473			(39,069		)	491
Development costs incurred during the period	84			160,583			—
Accretion of discount	81,285			117,989			110,592
Net change in income taxes	79,134			(98,568		)	—
Change in production rate (timing) and other	(29,200		)	43,611			(84,142		)
Net change	(387,372		)	(465,603		)	73,964
Balance at end of period	$	326,911		$	714,283		$	1,179,886

_________________

(1)

The sale of reserves in-place during the 2018 Predecessor Period includes the sale of non-STACK properties.

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EQUITY-BASED COMPENSATION (Successor)

12 Months Ended

Dec. 31, 2019

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

EQUITY-BASED COMPENSATION (Successor)

EQUITY-BASED COMPENSATION (Successor)

We have adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”).  A total of 50,000,000 shares of Class A Common Stock were initially reserved for issuance under the LTIP.  The LTIP provided for the grant of stock awards, including incentive stock options (“ISOs”), nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units and other awards in our Class A Common Stock. Prior to the Business Combination, we had no equity-based compensation programs. During 2019 and the 2018 Successor Period, we recognized stock-based compensation expense of $6.4 million and $22.0 million, respectively, in general and administrative expense including accelerated vesting in 2018 for separated executives related to the LTIP.  

On February 11, 2020, we filed a post-effective amendment to our registration statement on Form S-8 (Registration No. 333-224248) to deregister unissued and unsold shares of Class A Common Stock issuable to participants under the LTIP. Accordingly, we are no longer able to grant restricted stock or shares of our Class A Common Stock in satisfaction of our outstanding unexercised stock options, unvested restricted stock and unvested performance-based restricted stock units (“PSUs”) and we anticipate those outstanding stock awards will be canceled as a result of our bankruptcy filing.

Stock options 

Stock options previously granted were set to expire seven years from the grant date and generally were to vest in one-third increments each year, based on continued employment. Employees had 90 days after termination to exercise vested stock options, unless extended by an employment agreement.

	Stock Options		Weighted Average Exercise Price		Weighted Average Grant-Date Fair Value		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of February 9, 2018	—		$	—	$	—	—	$	—
Granted	5,283,224		8.80		4.33		—	—
Exercised	—		—		—		—	—
Forfeited or expired	(139,319	)	9.38		4.55		—	—
Outstanding as of December 31, 2018	5,143,905		$	8.79	$	4.33	5.3	$	—
Granted	157,710		$	1.07	$	0.61	—	$	—
Exercised	—		—		—		—	—
Forfeited or expired	(1,498,328	)	8.44		4.20		—	—
Outstanding as of December 31, 2019	3,803,287		$	4.80	$	4.22	3.19	$	—
Exercisable as of December 31, 2019	2,260,388		$	9.21	$	4.49	5.15	—

The following assumptions were used to determine the fair value of our 2019 and 2018 option grants:

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	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Expected term (in years)	4.5		4.5
Expected stock volatility	69.8	%	64.6	%
Dividend yield	—		—
Risk-free interest rate	2.4	%	2.5	%

Unrecognized compensation cost related to non-vested stock options at December 31, 2019 was $3.5 million, with a remaining weighted average vesting period of 0.8 years.

Restricted stock 

Restricted stock granted to employees generally vested in one-third increments each year based on continued employment. Prior to vesting, unvested restricted stock may not be traded but was entitled to accumulate any dividend value. During the 2018 Successor Period, we granted 98,199 shares to certain of our directors, all which vested immediately, and granted 2,140,160 restricted stock awards to employees. All 2019 grants were to employees.

The following table provides information about activity in our restricted stock awards during the 2018 Successor Period and year ended December 31, 2019:

໿

	Restricted Stock Awards		Weighted Average Grant Date Fair Value per share
Outstanding as of February 9, 2018	—		$	—
Granted	2,238,359		7.54
Vested(1)	(384,413	)	8.40
Forfeited or expired	(61,935	)	8.80
Outstanding as of December 31, 2018	1,792,011		7.32
Granted	70,093		0.96
Vested(1)	(619,061	)	7.04
Forfeited or expired	(719,766	)	7.36
Outstanding as of December 31, 2019	523,277		$	6.74

_________________

(1) To satisfy minimum tax withholding, 130,432 and 94,576 shares were withheld in 2019 and during the 2018 Successor Period.

Unrecognized compensation cost related to unvested restricted shares at December 31, 2019 was $2.1 million, with a remaining weighted average vesting period of 1.4 years.

Restricted stock units

Our PSUs granted in 2018 generally vested over three years at 20% during the first year, 30% during the second year and 50% was schedule to vest during the third year. The number of PSUs vesting each year were based on the achievement of annual performance goals and objectives applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that vest could range from 0% to 200% of the target grant applicable to each vesting period. We only recognize expense for PSUs when the specified performance thresholds for future periods have been established. For PSUs granted during the 2018 Successor Period only the performance goals and objectives for 2018 had been established as of December 31, 2018. Those 2018 performance goals were not attained, and the 2018 award tranche was forfeited, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted. The targets for 2019 were established in March 2019. The 2019 award tranche vested at 199% of target. Due to our bankruptcy and the expected sale of substantially all of our assets, no performance targets will be established for the 2020 award tranche and we expect that tranche will be forfeited as part of our bankruptcy proceedings.

The following table provides information about activity in our PSUs granted during the 2018 Successor Period and year ended December 31, 2019:

	PSUs		Weighted Average Grant Date Fair Value per unit
Outstanding as of February 9, 2018	—		$	—
Granted	2,093,453		4.07
Vested (1)	(1,559,749	)	2.53
Forfeited or expired	(533,704	)	8.54
Outstanding as of December 31, 2018	—		—
Granted	1,220,490		0.32
Vested	(100,870	)	0.96
Forfeited or expired	(54,112	)	0.27
Outstanding as of December 31, 2019	1,065,508		$	0.27

_________________

(1) To satisfy minimum tax withholding, 32,481 and 388,655 shares were withheld in 2019 and during the 2018 Successor Period.

As of December 31, 2019, there was no unrecognized compensation cost related to unvested PSUs.

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Components of changes in standardized measure of discounted future net cash flows
Balance at beginning of period	$ 1,105,922	$ 1,179,886	$ 714,283
Sales and transfers of oil and gas produced, net of production costs	(30,391)	(278,091)	(253,582)
Net changes in prices and production costs	71,334	38,963	(270,712)
Revisions of previous quantity estimates	10,887	(1,120,097)	(129,305)
Purchases of reserves in-place	0	24,376	0
Sales of reserves-in-place	(4,807)	0	0
Current year discoveries and extensions, less related costs	0	684,700	134,451
Changes in estimated future development costs	491	(39,069)	473
Development costs incurred during the period	0	160,583	84
Accretion of discount	110,592	117,989	81,285
Net change in income taxes	0	(98,568)	79,134
Change in production rate (timing) and other	(84,142)	43,611	(29,200)
Net change	73,964	(465,603)	(387,372)
Balance at end of period	$ 1,179,886	$ 714,283	$ 326,911

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EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Defined Contribution Plan Disclosure [Line Items]
Percentage of matching contribution by company			100.00%
Maximum percentage of employee's salary deferral contribution			5.00%
Matching contributions to the plan	$ 0.3	$ 1.1	$ 1.2
Tranche one
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, vesting percentage			50.00%
Employer matching contribution, vesting term			2 years
Tranche two
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, vesting term			3 years

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RECEIVABLES

12 Months Ended

Dec. 31, 2019

Receivables [Abstract]

RECEIVABLES

RECEIVABLES

Accounts Receivable

(in thousands)	December 31, 2019			December 31, 2018
Production and processing sales and fees	$	40,858		$	51,004
Joint interest billings	12,845			18,147
Pooling interest (1)	7,901			18,786
Allowance for doubtful accounts	(417		)	(95		)
Total accounts receivable, net	$	61,187		$	87,842

_________________

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

Related Party Receivables

(in thousands)	December 31, 2019			December 31, 2018
Related party receivables	$	12,144		$	12,376
Allowance for doubtful accounts	(12,144		)	(9,035		)
Related party receivables, net	—			3,341
Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Related party receivables, net	$	—		$	3,341

At December 31, 2019, we had receivables, including notes receivable from HMI totaling approximately $23.2 million. Because HMI disputes its obligations under the promissory notes with us and challenges other amounts due us, we had fully reserved the outstanding receivables at December 31, 2019 based upon our assessment regarding collectibility.

Additionally, at December 31, 2019, we had receivables of $2.3 million from KFM’s former owner, KFM Holdco, LLC (“KFM Holdco”), relating to transaction costs paid on KFM Holdco’s behalf before the Business Combination. During 2019, we fully

reserved this receivable based upon our assessment regarding collectibility. We have filed suit against KFM Holdco to seek payment for this receivable.

Management Services Agreement with HMI

(in thousands)
HMI related party receivable at December 31, 2018	$	10,066
Additions	832
Payments	(1,073		)
HMI related party receivable at December 31, 2019	9,825
Allowance for doubtful accounts(1)	(9,825		)
Balance at December 31, 2019, net	$	—

_________________

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

Our management services agreement with HMI (the “HMI Agreement”) was terminated effective January 31, 2019. 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 HMI Agreement. As of December 31, 2019, and December 31, 2018, approximately $9.8 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes or amounts that may become due pursuant to indemnification obligations which became more uncertain when HMI filed for bankruptcy protection in January 2020. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.8 million and $9.0 million as of December 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 December 31, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.

Promissory notes receivable

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

In addition, we have a note receivable from HMS which matured on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount.  HMI disputes its obligations under the note. As of December 31, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods. We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes.

We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. 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 have responsibility to address any potential conflicts of interest with respect to this matter.

Activity in our allowances for doubtful accounts for trade and related party receivables was as follows:

	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Trade receivables:
Balance at beginning of period	$	95		$	415		$	415
Charged to expense	332			25			—
Deductions	(10		)	(345		)	—
Balance at end of period	$	417		$	95		$	415
Related party receivables:
Balance at beginning of period	$	22,438		$	—		$	—
Charged to expense	3,196			22,438			—
Deductions	(87		)	—			—
Balance at end of period	$	25,547		$	22,438		$	—

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PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

PROPERTY AND EQUIPMENT

PROPERTY AND EQUIPMENT

(in thousands)	December 31, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	813,310		$	816,282
Accumulated impairment of unproved properties	(813,310		)	(742,065		)
Unproved properties, net	—			74,217
Proved oil and gas properties	2,239,444			2,110,346
Accumulated depreciation, depletion, amortization and impairment	(2,024,092		)	(1,421,226		)
Proved oil and gas properties, net	215,352			689,120
Total oil and gas properties, net	215,352			763,337
Other property and equipment
Land	5,690			5,600
Fresh water wells	27,373			27,366
Produced water disposal system	108,966			104,498
Gas processing plant and gathering lines	414,615			380,470
Office furniture, equipment and vehicles	3,397			3,703
Accumulated depreciation and impairment	(453,013		)	(77,368		)
Other property and equipment, net	107,028			444,269
Total property and equipment, net	$	322,380		$	1,207,606

Depreciation and Depletion

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	118,003	$	129,579	$	11,021
Midstream tangible asset depreciation	11,663		8,235		—
Other property and equipment depreciation	1,646		3,236		609
Total depletion and depreciation	$	131,312	$	141,050	$	11,630

Sale of Produced Water Assets

In November 2018, Alta Mesa sold its produced water assets, consisting of over 200 miles of produced water gathering pipelines and 20 disposal wells, surface leases, easements and other agreements, to a subsidiary of KFM for approximately $99 million, including approximately $90 million in cash at closing and $9 million of purchase price adjustments which, in total, approximated the net book value of the produced water assets.  This transaction was accounted for as a transfer of assets among entities under common control and recorded at carrying value. Accordingly, no gain or loss was recognized. In conjunction with the sale, Alta Mesa entered into a new fifteen-year produced water disposal agreement with KFM.

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EQUITY-BASED COMPENSATION (Successor) (Schedule of Outstanding Stock Options) (Details) - $ / shares	11 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019
Stock Options
Outstanding, beginning balance (shares)	0	5,143,905
Granted (shares)	5,283,224	157,710
Exercised (shares)	0	0
Forfeited or expired (shares)	(139,319)	(1,498,328)
Outstanding, ending balance (shares)	5,143,905	3,803,287
Exercisable (shares)		2,260,388
Weighted Average Exercise Price
Balance (usd per share)	$ 0	$ 8.79
Granted (usd per share)	8.80	1.07
Exercised (usd per share)	0	0
Forfeited or expired (usd per share)	9.38	8.44
Balance (usd per share)	8.79	4.80
Exercisable (usd per share)		9.21
Weighted Average Grant-Date Fair Value
Outstanding, beginning balance (usd per share)	0	4.33
Granted (usd per share)	4.33	0.61
Forfeited or expired (usd per share)	4.55	4.20
Outstanding, ending balance (usd per share)	$ 4.33	4.22
Exercisable (usd per share)		$ 4.49
Outstanding, weighted average remaining term	5 years 3 months 18 days	3 years 2 months 8 days
Exercisable, weighted average remaining term		5 years 1 month 24 days

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INTANGIBLE ASSETS

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

INTANGIBLE ASSETS

INTANGIBLE ASSETS

Our intangible assets represented customer relationships within the Midstream segment acquired in the Business Combination.

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(in thousands)	December 31, 2018
Customer contracts and relationships acquired	$	414,150
Accumulated amortization and impairment	(414,150		)
Intangibles, net	$	—

Amortization expense was $19.2 million during the 2018 Successor Period.

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ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

12 Months Ended

Dec. 31, 2019

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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	Successor
(in thousands)	December 31, 2019			December 31, 2018
Accounts payable	$	27,349		$	20,422
Accruals for capital expenditures	1,244			139,904
Revenue and royalties payable	27,355			50,241
Accruals for operating expenses	25,131			21,830
Accrued interest	9,663			2,477
Derivative settlements	511			109
Other	1,716			12,456
Total accrued liabilities	65,620			227,017
Less: liabilities subject to compromise	(28,832		)	—
Accounts payable and accrued liabilities	$	64,137		$	247,439

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STOCKHOLDERS' EQUITY AND PARTNERS' CAPITAL

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

STOCKHOLDERS' EQUITY AND PARTNERS' CAPITAL

STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL

Class A Common Stock

Holders of our Class A Common Stock are entitled to one vote for each share held on all matters to be voted on by our stockholders. Holders of the Class A Common Stock and holders of the Class C Common Stock constitute a single class for all stockholder votes. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50% of the shares voted for the election of directors can elect all of the directors (subject to the right of the holders of our Series A Preferred Stock and Series B Preferred Stock to nominate and elect up to five directors in total).

In the event of our liquidation or dissolution, the holders of the Class A Common Stock are entitled to share ratably in all assets remaining after payment of liabilities and after provision is made for each class of stock, if any, having preference over the Class A Common Stock. Our stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the Class A Common Stock.

In August 2018, the Board of Directors authorized up to $50.0 million for the repurchase of our outstanding Class A Common Stock, exclusive of any fees, commissions or other expenses related to such repurchases. Repurchases could be made at the Company’s discretion in open market or private transactions. During 2018, we repurchased and retired 3,101,510 shares of Class A Common Stock, which remain authorized and are available for reissuance at a future date. The price paid for the shares repurchased, including commissions, that was in excess of par value has been recorded as a reduction of approximately $14.8 million in additional paid in capital. To fund the repurchase of our Class A shares of Common Stock, the Company sold 3,101,510 of its SRII Opco Common Units to SRII Opco for the same price paid to the market for the Class A shares repurchased. This resulted in an increase during the 2018 Successor Period in the ownership position of the noncontrolling interest holders in SRII Opco, and an offsetting reduction in the Company’s additional paid in capital, totaling approximately $10.8 million.

In February 2020, we filed a Form 15 with the Securities and Exchange Commission to deregister our Class A Common Stock under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.

Class C Common Stock

In connection with the Business Combination, we issued 213,402,398 shares of Class C Common Stock to the Contributors, 199,987,976 of which remain outstanding at December 31, 2019 (202,169,576 at December 31, 2018).

Holders of Class C Common Stock, voting as a separate class, are entitled to approve any amendment of our certificate of incorporation that would alter or change the rights and powers of the Class C Common Stock. Holders of Class C Common Stock are not entitled to any dividends and are not entitled to receive any of our assets in the event of our liquidation or dissolution.

Shares of Class C Common Stock may be issued only to the Contributors, their respective successors and assigns, as well as any permitted transferees of the Contributors. A holder of Class C Common Stock may transfer shares of Class C Common Stock to any transferee (other than the Company) only if such holder also simultaneously transfers an equal number of such holder’s SRII Opco Common Units to such transferee in compliance with the amended and restated limited partnership agreement of SRII Opco. The Contributors generally have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. The Company may, however, at its option, effect a direct exchange of cash or Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption by SRII Opco. Upon the future redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be canceled. During 2019, we issued 2,181,600 shares of our Class A Common Stock to an owner of SRII Opco Common Units in exchange for those units, and canceled 2,181,600 of our Class C Common Stock. During the 2018 Successor Period, we issued 2,752,312 and 9,588,764 shares of our Class A Common Stock to equity owners of High Mesa and KFM Holdco, LLC, respectively, and canceled 12,341,076 shares of our Class C Common Stock as a result of the direct exchange of SRII Opco Common Units redemption.

Redeemable Series A Preferred Stock 

As of December 31, 2019, Bayou City Energy Management LLC (“Bayou City”) and HPS Investment Partners, LLC (“HPS”) each own one of the two outstanding shares of our Series A Preferred Stock, and may not transfer the Series A Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate. AM Equity Holding, LP elected to redeem their one share for par value in December 2018. The holders of the Series A Preferred Stock are not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holders are not entitled to dividends. The Series A Preferred Stock is not convertible into any other of our securities, but will be redeemable by us for par value upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series A Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. If the Series A Preferred Stock remains outstanding, its holders are entitled to nominate and elect up to two directors to our board of directors for a period of up to five years following the closing of the Business Combination based on their and their affiliates’ beneficial ownership of common stock. 

Redeemable Series B Preferred Stock 

As of December 31, 2019, the Riverstone Contributor owns the only outstanding share of our Series B Preferred Stock, and may not transfer the Series B Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate (as defined in the limited partnership agreement of SRII Opco). The holder of the Series B Preferred Stock is not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holder is not entitled to dividends. The Series B Preferred Stock is not convertible into any other security of the Company, but will be redeemable by us for par value upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series B Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. If the Series B Preferred Stock remains outstanding, its holder is entitled to nominate and elect up to three directors to our board of directors for a period of up to five years following the closing of the Business Combination based on its and its affiliates’ beneficial ownership of common stock.

Warrants

As of December 31, 2019, we had 62,966,651 warrants outstanding, consisting of 34,499,985 public warrants originally sold in our IPO (“Public Warrants”), 15,133,333 Private Placement Warrants sold to our Sponsor and 13,333,333 Forward Purchase Warrants issued to Riverstone VI SR II Holdings, LP.

Each Public Warrant entitles the holder to purchase one share of our Class A Common Stock for $11.50 and expire in February 2023. 

The Private Placement Warrants are identical to the Public Warrants, except the Private Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees.

The Forward Purchase Warrants have terms and provisions that are identical to those of the Private Placement Warrants, except the Forward Purchase Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees. The Forward Purchase Warrants were sold in a private placement pursuant to a purchase agreement between us and our Sponsor.

In February 2020, we filed a Form 15 with the Securities and Exchange Commission to deregister our warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.

Noncontrolling Interest (“NCI”)

NCI relates to SRII Opco Common Units that were originally issued to the Contributors, in connection with the Business Combination and continue to be held by holders other than the Company. At the date of the Business Combination, the noncontrolling interest owners held 55.8% of the limited partner interests in SRII Opco. The non-controlling interest percentage is affected by Class C Common Stock conversions and the Class A Common Stock activities after which, the noncontrolling interest owners held 52.25% at December 31, 2019 (53.0% at December 31, 2018).

Partnership Management and Control

Alta Mesa’s amended and restated partnership agreement provides for interests to be divided into economic units held by the partners referred to as “LP Units” and non-economic general partner interests owned by Alta Mesa GP referred to as “GP Units”.  Alta Mesa GP owns all the GP Units and SRII Opco owns all the LP Units. 

Since Alta Mesa is a limited partnership, its operations and activities are managed by the board of directors of its general partner, Alta Mesa GP.  The limited liability company agreement of Alta Mesa GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic rights in Alta Mesa GP and (ii) Class B Units, which hold 100% of the voting interests in Alta Mesa GP. 

SRII Opco is the sole owner of Alta Mesa GP’s Class A Units and owns 90% of the Class B Units.  Our former President and Chief Executive Officer and our former Chief Operating Officer—Upstream, along with certain affiliates of Bayou City and HPS, own an aggregate 10% of the Class B Units.  Alta Mesa GP’s board of directors are selected by the Class B members.  Notwithstanding the foregoing, voting control of Alta Mesa GP is vested in SRII Opco pursuant to a voting agreement.

Cancellation

We expect that our reorganization pursuant to the bankruptcy proceedings will result in the cancellation of all equity that existed at December 31, 2019.

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Results of Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Supplemental Oil and Natural Gas Disclosures [Abstract]
Operating revenue	$ 40,136	$ 414,507	$ 423,576
Production expense	30,743	247,748	232,212
Depreciation, depletion and amortization	11,670	133,554	120,617
Exploration expense	7,003	34,085	52,354
Impairment expense	0	2,033,712	556,427
Income tax expense (benefit)	0	4	0
Results of operations	$ (9,280)	$ (2,034,596)	$ (538,034)

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RELATED PARTY TRANSACTIONS (Details)			1 Months Ended	8 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018 USD ($)	Dec. 31, 2016 USD ($)	Feb. 08, 2018 USD ($)	Sep. 30, 2018 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2019 USD ($) well	Sep. 29, 2017 USD ($)	Jan. 13, 2016 well
Related Party Transaction [Line Items]
Advances from related party					$ 9,839,000	$ 3,175,000
8% long-term note receivable
Related Party Transaction [Line Items]
Allowance for uncollectible accounts						(13,400,000)
Joint Development Agreement
Related Party Transaction [Line Items]
Number of wells to be drilled in three tranches | well								60
Number of additional wells to be drilled | well								20
Reduced interest (percent)		12.50%
Internal rate of return		25.00%
BCE
Related Party Transaction [Line Items]
Advances from related party					9,800,000
BCE | Joint Development Agreement
Related Party Transaction [Line Items]
Percent committed to fund		100.00%
Drilling and completion costs (maximum)		$ 3,200,000
Working interest received (percent)		80.00%
Reduced interest (percent)		20.00%
Internal rate of return		15.00%
Advances from related party						$ 39,500,000
Number of wells drilled | well						61
NWGP
Related Party Transaction [Line Items]
Due from related parties					1,700,000	$ 1,700,000	$ 1,500,000
Stated interest rate of senior notes							8.00%
Promissory note receivable					1,700,000	1,700,000
High Mesa Services
Related Party Transaction [Line Items]
Promissory note receivable						$ 8,500,000
HMS | 8% long-term note receivable
Related Party Transaction [Line Items]
Stated interest rate of senior notes						8.00%
Long-term note receivable					11,700,000	$ 11,700,000
Long-term note receivable from HMS | HMS | 8% long-term note receivable
Related Party Transaction [Line Items]
Interest income note receivable	$ 100,000				900,000
High Mesa Agreement
Related Party Transaction [Line Items]
Incremental costs incurred and have received						832,000
Payments						(1,073,000)
High Mesa Agreement | Affiliated Entity
Related Party Transaction [Line Items]
Long-term note receivable					10,100,000	9,800,000
Allowance for uncollectible accounts					(9,000,000.0)	$ (9,800,000)
Initial term						180 days
Renewal term						180 days
Required notice period to terminate agreement						90 days
Management fee						$ 10,000
Costs incurred prior to 2018					$ 800,000
David McClure, VP of Facilities and Midstream | Compensation | Vice President
Related Party Transaction [Line Items]
Total compensation received			$ 29,000	$ 1,158,000		$ 769,000

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CHAPTER 11 PROCEEDINGS (Statement of Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Revenue
Operating revenue	$ 40,136	$ 473,473	$ 500,220
Gain on sale of assets	840	4,751	1,382
Gain (loss) on derivatives	6,663	(10,247)	(11,744)
Total revenue	47,639	467,977	489,858
Operating expenses
Lease operating	4,408	56,827	63,755
Transportation and marketing	3,725	19,293	21,042
Production taxes	953	16,865	19,455
Workovers	423	5,563	3,189
Exploration	7,003	34,085	52,354
Depreciation, depletion and amortization	11,670	160,942	132,292
Impairment of assets	0	3,205,051	905,293
General and administrative	21,234	131,052	107,655
Total operating expenses	49,416	3,676,146	1,364,283
Operating income	(1,777)	(3,208,169)	(874,425)
Other income (expense)
Interest expense	(5,511)	(43,296)	(61,459)
Interest income	172	2,049	243
Reorganization items, net	0	0	(197)
Total other income (expense), net	(5,339)	(41,247)	(55,197)
Loss from continuing operations before income taxes	(7,116)	(3,249,416)	(929,622)
Income tax expense (benefit)	0	(69)	0
Net loss	(14,862)	(3,249,347)	(929,622)
Oil
Revenue
Operating revenue	30,972	323,299	328,386
Natural gas
Revenue
Operating revenue	4,276	43,407	53,693
Natural Gas Liquids
Revenue
Operating revenue	4,000	43,039	40,026
Other
Revenue
Operating revenue	$ 888	$ 4,762	10,330
Debtor-In-Possession
Revenue
Operating revenue			423,576
Gain on sale of assets			1,488
Gain (loss) on derivatives			(11,744)
Total revenue			413,320
Operating expenses
Lease operating			79,884
Transportation and marketing			70,324
Production taxes			19,455
Workovers			2,652
Exploration			52,354
Depreciation, depletion and amortization			120,617
Impairment of assets			556,427
General and administrative			71,823
Total operating expenses			973,536
Operating income			(560,216)
Other income (expense)
Interest expense			(49,823)
Interest income			154
Reorganization items, net			(197)
Total other income (expense), net			(49,866)
Loss from continuing operations before income taxes			(610,082)
Income tax expense (benefit)			0
Net loss			(610,082)
Debtor-In-Possession | Oil
Revenue
Operating revenue			328,386
Debtor-In-Possession | Natural gas
Revenue
Operating revenue			53,693
Debtor-In-Possession | Natural Gas Liquids
Revenue
Operating revenue			40,026
Debtor-In-Possession | Other
Revenue
Operating revenue			$ 1,471

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INTANGIBLE ASSETS (Narrative) (Details) $ in Millions	11 Months Ended
	Dec. 31, 2018 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets, amortization expense	$ 19.2

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LONG-TERM DEBT, NET (Narrative) (Details) - USD ($)	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019	Aug. 31, 2019	Apr. 30, 2019	Apr. 30, 2018	Feb. 09, 2018
Debt Instrument [Line Items]
Interest expense	$ 5,511,000	$ 43,296,000	$ 61,459,000
Amortization of debt premium	$ 0	(4,512,000)	(3,432,000)
Senior Notes
Debt Instrument [Line Items]
Unamortized premium			33,600,000
7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
Face value of senior notes issued		500,000,000	500,000,000
Interest expense			12,000,000.0
Unamortized premium		29,123,000	0
Alta Mesa
Debt Instrument [Line Items]
Borrowing base						$ 400,000,000.0
Alta Mesa | 7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
Face value of senior notes issued			$ 500,000,000.0
Stated interest rate of senior notes	7.875%		7.875%
Fair value of senior notes payable			$ 533,600,000
KFM Credit Facility
Debt Instrument [Line Items]
Credit facility amount outstanding		174,000,000	224,000,000
Alta Mesa Credit Facility
Debt Instrument [Line Items]
Maximum credit				$ 200,000,000.0			$ 1,000,000,000.0
Borrowing base			355,900,000		$ 370,000,000.0		$ 350,000,000.0
Installment payment			32,500,000
Letter of credit outstanding			$ 1,900,000
Interest rate			10.75%
Interest rate due to borrowing base deficiency			2.00%
Interest rate due to default			2.00%
Alta Mesa Credit Facility | Eurodollar
Debt Instrument [Line Items]
Margin interest rate			1.00%
Alta Mesa Credit Facility | Eurodollar | Minimum
Debt Instrument [Line Items]
Margin interest rate			1.00%
Alta Mesa Credit Facility | Eurodollar | Maximum
Debt Instrument [Line Items]
Margin interest rate			2.00%
Alta Mesa Credit Facility | Federal funds rate
Debt Instrument [Line Items]
Margin interest rate			0.50%
Alta Mesa RBL | Alta Mesa
Debt Instrument [Line Items]
Credit facility amount outstanding		$ 161,000,000	$ 355,943,000
KFM Credit Facility
Debt Instrument [Line Items]
Interest rate			6.50%
Outstanding borrowings			$ 224,000,000.0
KFM Credit Facility | Eurodollar | Minimum
Debt Instrument [Line Items]
Margin interest rate			1.00%
KFM Credit Facility | Eurodollar | Maximum
Debt Instrument [Line Items]
Margin interest rate			2.25%
KFM Credit Facility | Federal funds rate
Debt Instrument [Line Items]
Margin interest rate			0.50%
KFM Credit Facility | KFM Credit Facility
Debt Instrument [Line Items]
Maximum credit			$ 300,000,000.0
Amendment to KFM Credit Facility
Debt Instrument [Line Items]
Maximum credit			$ 15,000,000.0

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IMPAIRMENT OF ASSETS (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Jan. 15, 2020	Jan. 01, 2020	Nov. 30, 2019
Goodwill [Line Items]
Impairment of assets	$ 0	$ 3,205,051	$ 905,293
Impairment of Cimarron investment		15,963
Upstream
Goodwill [Line Items]
Impairment of proved and unproved oil and gas properties			515,900
Impairment Expense, Excluding Proved and Unproved Properties			13,100
Impairment of assets	0	2,033,712	556,427	$ 2,000,000
Impairment of operating lease right-of-use assets			13,245
Impairment of other long-term assets	0	0	27,329
Upstream | Long-term Contract with Customer
Goodwill [Line Items]
Impairment of other long-term assets			14,200
Midstream
Goodwill [Line Items]
Impairment of assets	0	1,171,339	348,866
Impairment of operating lease right-of-use assets			269
Impairment of Cimarron investment	0	15,963	0
Impairment of property and equipment	0	68,407	348,597	68,400
Impairment of intangible assets	$ 0	$ 394,999	$ 0	$ 395,000
Subsequent Event
Goodwill [Line Items]
Unadjusted purchase price					$ 320,000
Subsequent Event | Upstream
Goodwill [Line Items]
Unadjusted purchase price						$ 232,000
Cimarron Express Pipeline, LLC
Goodwill [Line Items]
Percentage of ownership acquired							50.00%
Disposed of by Sale | Midstream Assets | Subsequent Event
Goodwill [Line Items]
Unadjusted purchase price						$ 88,000

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (Successor) - USD ($) $ in Thousands	Total	Common Class C	Common Stock Common Class A	Common Stock Common Class B	Common Stock Common Class C	Paid-In Capital	Accumulated Deficit	Total Stockholders' Equity	Noncontrolling Interests
Balance (in shares) at Feb. 08, 2018			3,862,000	25,875,000
Balance at Feb. 08, 2018	$ (5,005)			$ 3		$ 3,106	$ (8,114)	$ (5,005)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Conversion of common shares (in shares)			25,875,000	(25,875,000)
Conversion of common shares			$ 3	$ (3)
Class A common shares released from possible redemption (in shares)			99,638,000
Class A common shares released from possible redemption	996,384		$ 10			996,374		996,384
Common shares redeemed (in shares)			(3,000)
Common shares redeemed	(33)					(33)		(33)
Sale of Class A common shares (in shares)			40,000,000
Sale of Class A common shares	400,000		$ 4			399,996		400,000
Class C common shares issued in connection with the closing of the Business Combination (in shares)					213,402,000
Class C common shares issued in connection with the closing of the Business Combination					$ 21	(21)
Noncontrolling interest in SRII Opco issued in the Business Combination	2,058,635								$ 2,058,635
Balance (in shares) at Feb. 09, 2018			169,372,000		213,402,000
Balance at Feb. 09, 2018	3,449,981		$ 17		$ 21	1,399,422	(8,114)	1,391,346	2,058,635
Balance (in shares) at Feb. 08, 2018			3,862,000	25,875,000
Balance at Feb. 08, 2018	(5,005)			$ 3		3,106	(8,114)	(5,005)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Class A common shares released from possible redemption	996,384
Common shares redeemed (in shares)			12,341,000		(12,341,000)
Common shares redeemed	(6)		$ 1		$ (1)	105,593		105,593	(105,599)
Purchase and retirement of Class A common shares and related sale of SRII Opco Common Units (in shares)			(3,102,000)
Purchase and retirement of Class A common shares and related sale of SRII Opco Common Units	(14,750)					(25,589)		(25,589)	10,839
Restricted stock awards vested (in shares)			1,944,000
Restricted stock awards vested	0					2,465		2,465	(2,465)
Equity-based compensation expense	22,025					22,025		22,025
Shares withheld/retired for taxes on equity awards (in shares)			(483,000)
Shares withheld/retired for taxes on equity awards	(534)					(534)		(534)
Class C common shares issued in connection with the closing of the Business Combination (in shares)					1,109,000
Noncontrolling interest in SRII Opco issued in the Business Combination	8,758								8,758
Net loss	(3,249,347)						(1,524,699)	(1,524,699)	(1,724,648)
Balance (in shares) at Dec. 31, 2018			180,072,000		202,170,000
Balance at Dec. 31, 2018	216,127		$ 18		$ 20	1,503,382	(1,532,813)	(29,393)	245,520
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Conversion of common shares (in shares)			2,182,000		(2,182,000)
Conversion of common shares						2,756		2,756	(2,756)
Class A common shares released from possible redemption	0
Restricted stock awards vested (in shares)			521,000
Restricted stock awards vested	(142)					166		166	(308)
Equity-based compensation expense	6,412					6,412		6,412
Class C common shares issued in connection with the closing of the Business Combination (in shares)		213,402,398
Net loss	(929,622)						(450,538)	(450,538)	(479,084)
Balance (in shares) at Dec. 31, 2019			182,775,000		199,988,000
Balance at Dec. 31, 2019	$ (707,225)		$ 18		$ 20	$ 1,512,716	$ (1,983,351)	$ (470,597)	$ (236,628)

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EQUITY METHOD INVESTMENT (Tables)

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Activity in our equity method investment was as follows:

(in thousands)
Balance, as of February 9, 2018	$	—
Capital contributions	17,063
Impairment	(15,963		)
Balance, as of December 31, 2018	1,100
Equity in earnings through November 13, 2019	713
Adjustment of investment in Cimarron to fair value based on assets received	5,503
Ending balance before obtaining control	$	7,316

We obtained control of the following remaining assets and assumed the following liabilities of Cimarron as a result of execution of an agreement between Cimarron and our partner in November 2019:

(in thousands)
Cash	$	7,238
Land and rights-of-way	90
Accrued liabilities	(12		)
Net assets received upon consolidation of Cimarron	$	7,316

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

We obtained control of the following remaining assets and assumed the following liabilities of Cimarron as a result of execution of an agreement between Cimarron and our partner in November 2019:

(in thousands)
Cash	$	7,238
Land and rights-of-way	90
Accrued liabilities	(12		)
Net assets received upon consolidation of Cimarron	$	7,316

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 08, 2018	Dec. 31, 2018	Dec. 31, 2019
Revenue
Operating revenue	$ 40,136	$ 473,473	$ 500,220
Gain on sale of assets	840	4,751	1,382
Gain (loss) on derivatives	6,663	(10,247)	(11,744)
Total revenue	47,639	467,977	489,858
Operating expenses
Lease operating	4,408	56,827	63,755
Transportation, processing and marketing	3,725	19,293	21,042
Midstream operating	0	15,221	24,719
Cost of sales for purchased gathered production	0	31,247	34,529
Production taxes	953	16,865	19,455
Workovers	423	5,563	3,189
Exploration	7,003	34,085	52,354
Depreciation, depletion and amortization	11,670	160,942	132,292
Impairment of assets	0	3,205,051	905,293
General and administrative	21,234	131,052	107,655
Total operating expenses	49,416	3,676,146	1,364,283
Operating income	(1,777)	(3,208,169)	(874,425)
Other income (expense)
Interest expense	(5,511)	(43,296)	(61,459)
Interest income and other	172	2,049	243
Equity in earnings of unconsolidated subsidiaries	0	0	6,216
Reorganization items, net	0	0	(197)
Total other income (expense), net	(5,339)	(41,247)	(55,197)
Loss from continuing operations before income taxes	(7,116)	(3,249,416)	(929,622)
Income tax expense (benefit)	0	(69)	0
Loss from continuing operations	(7,116)	(3,249,347)	(929,622)
Loss from discontinued operations, net of tax	(7,746)	0	0
Net loss	(14,862)	(3,249,347)	(929,622)
Net loss attributable to non-controlling interest		(1,724,648)	(479,084)
Net loss attributable to Alta Mesa Resources, Inc. stockholders	(14,862)	$ (1,524,699)	$ (450,538)
Net loss per common share attributable to Alta Mesa Resources, Inc. stockholders:
Basic and diluted (in dollars per share)		$ (8.71)	$ (2.48)
Oil
Revenue
Operating revenue	30,972	$ 323,299	$ 328,386
Natural gas
Revenue
Operating revenue	4,276	43,407	53,693
Natural gas liquids
Revenue
Operating revenue	4,000	43,039	40,026
Sales of gathered production
Revenue
Operating revenue	0	31,506	37,195
Midstream revenue
Revenue
Operating revenue	0	27,460	30,590
Other
Revenue
Operating revenue	$ 888	$ 4,762	$ 10,330

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DISCONTINUED OPERATIONS (Predecessor) (Tables)

12 Months Ended

Dec. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Discontinued Operations

(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 income (expense)
Interest expense	(103		)
Total other expense	(103		)
Loss from discontinued operations, net of state income taxes	$	(7,746	)

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

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EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Schedule of Earnings per Share, Basic and Diluted

(in thousands, except shares and per share data)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018
Net loss attributable to AMR Class A common stockholders	$	(450,538	)	$	(1,524,699	)
Weighted average Class A common shares outstanding (Basic and Diluted)	181,636,795			175,151,969
Basic and diluted loss per common share attributable to AMR common stockholders	$	(2.48	)	$	(8.71	)