SEC Info - Alta Mesa Resources, Inc./DE

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		Alternative Formats (Word, et al.) Accounts Payable and Accrued Liabilities Adoption of ASU No. 2016-02, Leases Asset Retirement Obligations Business Business Segment Information Cautionary Statement Regarding Forward-Looking Statements Certain Relationships and Related Transactions, and Director Independence Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Chapter 11 Proceedings Commitments and Contingencies Consolidated Balance Sheets Consolidated Statement of Changes in Partners' Capital Consolidated Statements of Cash Flows Consolidated Statements of Changes in Stockholders' Equity Consolidated Statements of Operations Controls and Procedures Derivatives Description of Business Directors, Executive Officers and Corporate Governance Discontinued Operations (Predecessor) Earnings Per Share Employee Benefit Plans Equity-Based Compensation (Successor) Equity Method Investment Executive Compensation Exhibits, Financial Statement Schedules Fair Value Measurements Financial Statements and Supplementary Data Form 10-K Summary Glossary Impairment of Assets Income Taxes Index to Financial Statements Intangible Assets Legal Proceedings Long-Term Debt, Net Management's Discussion and Analysis of Financial Condition and Results of Operations Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Mine Safety Disclosures Note 10 -- Property and Equipment Note 11 -- Discontinued Operations (Predecessor) Note 12 -- Fair Value Measurements Note 13 -- Derivatives Note 14 -- Intangible Assets Note 15 -- Equity Method Investment Note 16 -- Asset Retirement Obligations Note 17 -- Long-Term Debt, Net Note 18 -- Accounts Payable and Accrued Liabilities Note 19 -- Commitments and Contingencies Note 1 -- Description of Business Note 20 -- Employee Benefit Plans Note 21 -- Significant Concentrations Note 22 -- Stockholders' Equity and Partners' Capital Note 23 -- Equity-Based Compensation (Successor) Note 24 -- Income Taxes Note 25 -- Related Party Transactions Note 26 -- Business Segment Information Note 27 -- Supplemental Oil and Natural Gas Disclosures (Unaudited) Note 2 -- Summary of Significant Accounting Policies Note 3 -- Chapter 11 Proceedings Note 4 -- Impairment of Assets Note 5 -- Adoption of ASU No. 2016-02, Leases Note 6 -- Receivables Note 7 -- Earnings Per Share Note 8 -- Supplemental Cash Flow Information Note 9 -- Significant Acquisitions and Divestitures Notes to Consolidated Financial Statements Other Information Part I Part Ii Part Iii Part Iv Principal Accounting Fees and Services Properties Property and Equipment Quantitative and Qualitative Disclosures about Market Risk Receivables Related Party Transactions Report of Independent Registered Public Accounting Firm Risk Factors Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Signatures Significant Acquisitions and Divestitures Significant Concentrations Stockholders' Equity and Partners' Capital Summary of Significant Accounting Policies Supplemental Cash Flow Information Supplemental Oil and Natural Gas Disclosures (Unaudited) Table of Contents Unresolved Staff Comments 102 103
1	1st Page – Filing Submission
"	Table of Contents
"	Glossary
"	Cautionary Statement Regarding Forward-Looking Statements
"	Part I
"	Business
"	Risk Factors
"	Unresolved Staff Comments
"	Properties
"	Legal Proceedings
"	Mine Safety Disclosures
"	Part Ii
"	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
"	Management's Discussion and Analysis of Financial Condition and Results of Operations
"	Quantitative and Qualitative Disclosures about Market Risk
"	Financial Statements and Supplementary Data
"	Index to Financial Statements
"	Report of Independent Registered Public Accounting Firm
"	Consolidated Statements of Operations
"	Consolidated Balance Sheets
"	Consolidated Statements of Cash Flows
"	Consolidated Statements of Changes in Stockholders' Equity
"	Consolidated Statement of Changes in Partners' Capital
"	Notes to Consolidated Financial Statements
"	Note 1 -- Description of Business
"	Note 2 -- Summary of Significant Accounting Policies
"	Note 3 -- Chapter 11 Proceedings
"	Note 4 -- Impairment of Assets
"	Note 5 -- Adoption of ASU No. 2016-02, Leases
"	Note 6 -- Receivables
"	Note 7 -- Earnings Per Share
"	Note 8 -- Supplemental Cash Flow Information
"	Note 9 -- Significant Acquisitions and Divestitures
"	Note 10 -- Property and Equipment
"	Note 11 -- Discontinued Operations (Predecessor)
"	Note 12 -- Fair Value Measurements
"	Note 13 -- Derivatives
"	Note 14 -- Intangible Assets
"	Note 15 -- Equity Method Investment
"	Note 16 -- Asset Retirement Obligations
"	Note 17 -- Long-Term Debt, Net
"	Note 18 -- Accounts Payable and Accrued Liabilities
"	Note 19 -- Commitments and Contingencies
"	Note 20 -- Employee Benefit Plans
"	Note 21 -- Significant Concentrations
"	Note 22 -- Stockholders' Equity and Partners' Capital
"	Note 23 -- Equity-Based Compensation (Successor)
"	Note 24 -- Income Taxes
"	Note 25 -- Related Party Transactions
"	Note 26 -- Business Segment Information
"	Note 27 -- Supplemental Oil and Natural Gas Disclosures (Unaudited)
"	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
"	Controls and Procedures
"	Other Information
"	Part Iii
"	Directors, Executive Officers and Corporate Governance
"	Executive Compensation
"	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
"	Certain Relationships and Related Transactions, and Director Independence
"	Principal Accounting Fees and Services
"	Part Iv
"	Exhibits, Financial Statement Schedules
"	Form 10-K Summary
"	102
"	Signatures
"	103

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_______________________________________

FORM i 10-K

_______________________________________

(Mark One)

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

For the fiscal year ended: i December 31, 2019

i ☐ 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: i 001-38040

_______________________________________

ALTA MESA RESOURCES, INC.

(Exact name of registrant as specified in its charter)

_______________________________________



i Delaware				i 81-4433840
(State or other jurisdiction of incorporation or organization)				(I.R.S. Employer Identification No.)

i 15021 Katy Freeway,	i Suite 400,	i Houston,	i Texas	i 77094
(Address of principal executive offices)				(Zip Code)

Registrant’s telephone number, including area code: i 281- i 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 ☐ i 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 ☐ i 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. i 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.) i 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	☐	i Non-accelerated filer	☐
Smaller reporting company	i ☒	Emerging growth company	i ☐

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 i ☐ 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 $ i 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 i 182,791,388 shares of Class A Common Stock and i 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

໿




		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

Table of Contents

Index to Financial Statements

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

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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.

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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,

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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

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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

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.

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.

(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

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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.

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

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.

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:

໿



	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

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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

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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.

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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

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

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Index to Financial Statements

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.

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Index to Financial Statements

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

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Index to Financial Statements

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

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Index to Financial Statements

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

i 328,386

i 323,299

i 30,972

Natural gas

i 53,693

i 43,407

i 4,276

Natural gas liquids

i 40,026

i 43,039

i 4,000

Sales of gathered production

i 37,195

i 31,506

i —

Midstream revenue

i 30,590

i 27,460

i —

Other

i 10,330

i 4,762

i 888

Operating revenue

i 500,220

i 473,473

i 40,136

Gain on sale of assets

i 1,382

i 4,751

i 840

Gain (loss) on derivatives

( i 11,744

)

( i 10,247

)

i 6,663

Total revenue

i 489,858

i 467,977

i 47,639

Operating expenses

Lease operating

i 63,755

i 56,827

i 4,408

Transportation, processing and marketing

i 21,042

i 19,293

i 3,725

Midstream operating

i 24,719

i 15,221

i —

Cost of sales for purchased gathered production

i 34,529

i 31,247

i —

Production taxes

i 19,455

i 16,865

i 953

Workovers

i 3,189

i 5,563

i 423

Exploration

i 52,354

i 34,085

i 7,003

Depreciation, depletion and amortization

i 132,292

i 160,942

i 11,670

Impairment of assets

i 905,293

i 3,205,051

i —

General and administrative

i 107,655

i 131,052

i 21,234

Total operating expenses

i 1,364,283

i 3,676,146

i 49,416

Operating income

( i 874,425

)

( i 3,208,169

)

( i 1,777

)

Other income (expense)

Interest expense

( i 61,459

)

( i 43,296

)

( i 5,511

)

Interest income and other

i 243

i 2,049

i 172

Equity in earnings of unconsolidated subsidiaries

i 6,216

i —

Reorganization items, net

( i 197

)

i —

Total other income (expense), net

( i 55,197

)

( i 41,247

)

( i 5,339

)

Loss from continuing operations before income taxes

( i 929,622

)

( i 3,249,416

)

( i 7,116

)

Income tax expense (benefit)

i —

( i 69

)

i —

Loss from continuing operations

( i 929,622

)

( i 3,249,347

)

( i 7,116

)

Loss from discontinued operations, net of tax

i —

( i 7,746

)

Net loss

( i 929,622

)

( i 3,249,347

)

( i 14,862

)

Net loss attributable to non-controlling interest

( i 479,084

)

( i 1,724,648

)

Net loss attributable to Alta Mesa Resources, Inc. stockholders

( i 450,538

)

( i 1,524,699

)

Net loss per common share attributable to Alta Mesa Resources, Inc. stockholders:

Basic and diluted

( i 2.48

)

( i 8.71

)

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

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Index to Financial Statements

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

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

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Index to Financial Statements



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

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

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Index to Financial Statements

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

( i 929,622

)

( i 3,249,347

)

( i 14,862

)

Adjustments to reconcile net loss to cash from operating activities:

Depreciation, depletion and amortization

i 132,292

i 160,942

i 12,554

Non-cash lease expense

i 3,122

i —

Provision for uncollectible receivables

i 3,528

i 22,438

i —

Impairment of assets

i 905,293

i 3,205,051

i 5,560

Non-cash reorganization items, net

( i 26,160

)

i —

Amortization of deferred financing costs

i 658

i 526

i 171

Amortization of debt premium

( i 3,432

)

( i 4,512

)

i —

Equity-based compensation expense

i 6,412

i 22,025

i —

Non-cash exploration expense

i 43,412

i 26,055

i 4,575

(Gain) loss on derivatives

i 11,744

i 10,247

( i 6,663

)

Cash settlements of derivatives

i 7,642

( i 38,961

)

( i 2,296

)

Premium paid on derivatives

( i 1,906

)

i —

Interest converted into debt related to Founder notes

i —

i 103

Interest added to notes receivable from related party

i —

( i 949

)

( i 85

)

Loss on sale of property and equipment

i 106

i 388

i 1,923

Equity in earnings of unconsolidated subsidiaries

( i 6,216

)

i —

Impact on cash from changes in:

Accounts receivable

i 26,323

i 18,011

( i 21,184

)

Other receivables

i 4,988

( i 4,045

)

( i 662

)

Related party receivables and payables

i 145

( i 11,468

)

( i 117

)

Prepaid expenses and other assets

( i 29,078

)

i 11,149

( i 591

)

Advances from related party

( i 6,664

)

( i 37,668

)

i 24,116

Settlement of asset retirement obligations

( i 234

)

( i 1,610

)

( i 63

)

Accounts payable, accrued liabilities and other liabilities

i 4,216

( i 41,463

)

i 23,857

Operating lease obligations

( i 2,771

)

i —

Cash from operating activities

i 143,798

i 86,809

i 26,336

Cash flows from investing activities:

Capital expenditures

( i 327,567

)

( i 762,760

)

( i 36,695

)

Acquisitions, net of cash acquired

i —

( i 823,778

)

( i 1,218

)

Proceeds withdrawn from Trust Account

i —

i 1,042,742

i —

Proceeds from (Contribution to) equity method investment and other

i 7,238

( i 17,063

)

i —

Proceeds from sale of assets

i —

i 312

i —

Cash from investing activities

( i 320,329

)

( i 560,547

)

( i 37,913

)

Cash flows from financing activities:

Proceeds from long-term debt borrowings

i 254,362

i 431,500

i 60,000

Repayments of long-term debt

( i 9,496

)

( i 273,565

)

( i 43,000

)

Payment of taxes withheld on equity-based compensation awards

( i 142

)

i —

Deferred financing costs paid

i —

( i 3,722

)

i —

Purchase and retirement of Class A common shares

i —

( i 14,750

)

i —

Capital contributions (distributions)

i —

( i 68

)

Proceeds from issuance of Class A shares

i —

i 400,000

i —

Repayment of sponsor note

i —

( i 2,000

)

i —

Repayment of deferred underwriting compensation

i —

( i 36,225

)

i —

Redemption of Class A common shares

i —

( i 33

)

i —

Cash from financing activities

i 244,724

i 501,205

i 16,932

Net increase in cash, cash equivalents and restricted cash

i 68,193

i 27,467

i 5,355

Cash, cash equivalents and restricted cash, beginning of period

i 27,855

i 388

i 4,990

Cash, cash equivalents and restricted cash, end of period

i 96,048

i 27,855

i 10,345

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

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Index to Financial Statements

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

Amount

Capital

Deficit

Equity

Interests

Equity

Balance at February 8, 2018

i 3,862

—

i 25,875

i 3

—

i 3,106

( i 8,114

)

( i 5,005

)

—

( i 5,005

)

Conversion of common shares from Class B to Class A at closing of Business Combination

i 25,875

i 3

( i 25,875

)

( i 3

)

—

Class A common shares released from possible redemption

i 99,638

i 10

—

i 996,374

—

i 996,384

—

i 996,384

Class A common shares redeemed

( i 3

)

—

( i 33

)

—

( i 33

)

—

( i 33

)

Sale of Class A common shares

i 40,000

i 4

—

i 399,996

—

i 400,000

—

i 400,000

Class C common shares issued in connection with the closing of the Business Combination

—

i 213,402

i 21

( i 21

)

—

Noncontrolling interest in SRII Opco issued in the Business Combination

—

i 2,058,635

Balance at February 9, 2018

i 169,372

i 17

—

i 213,402

i 21

i 1,399,422

( i 8,114

)

i 1,391,346

i 2,058,635

i 3,449,981

Additional Class C common shares issued in connection with the settlement of the purchase consideration in the business combination

—

i 1,109

—

Noncontrolling interest in SRII Opco assumed in the business combination

—

i 8,758

Redemption of noncontrolling interests and Class C common shares for Class A common shares

i 12,341

i 1

—

( i 12,341

)

( i 1

)

i 105,593

—

i 105,593

( i 105,599

)

( i 6

)

Purchase and retirement of Class A common shares and related sale of SRII Opco Common Units

( i 3,102

)

—

( i 25,589

)

—

( i 25,589

)

i 10,839

( i 14,750

)

Restricted stock awards vested

i 1,944

—

i 2,465

—

i 2,465

( i 2,465

)

i —

Equity-based compensation expense

—

i 22,025

—

i 22,025

—

i 22,025

Shares withheld/retired for taxes on equity awards

( i 483

)

—

( i 534

)

—

( i 534

)

—

( i 534

)

Net loss

—

( i 1,524,699

)

( i 1,524,699

)

( i 1,724,648

)

( i 3,249,347

)

Balance at December 31, 2018

i 180,072

i 18

—

i 202,170

i 20

i 1,503,382

( i 1,532,813

)

( i 29,393

)

i 245,520

i 216,127

Conversion of commons shares from Class C shares to Class A shares

i 2,182

—

( i 2,182

)

—

i 2,756

—

i 2,756

( i 2,756

)

—

Restricted stock awards vested, net of taxes

i 521

—

i 166

—

i 166

( i 308

)

( i 142

)

Equity-based compensation expense

—

i 6,412

—

i 6,412

—

i 6,412

Net loss

—

( i 450,538

)

( i 450,538

)

( i 479,084

)

( i 929,622

)

Balance at December 31, 2019

i 182,775

i 18

—

i 199,988

i 20

i 1,512,716

( i 1,983,351

)

( i 470,597

)

( i 236,628

)

( i 707,225

)

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

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Index to Financial Statements

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

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(in thousands)

໿



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

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

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Index to Financial Statements

ALTA MESA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2019

NOTE 1 — i DESCRIPTION OF BUSINESS

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 $ i 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 $ i 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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Index to Financial Statements

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 — i 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.

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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

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.

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Segment Reporting (Successor)

We operate in i 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.

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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

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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 i 35 years for our produced water disposal assets, processing plant and pipelines and i 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 i three years to i 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

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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 i 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 i 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 $ i 500.0 million 2024 Notes at $ i 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 $ i 3.4 million and $ i 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 i 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.

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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 - i 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 $ i 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	$	i 355,943
2024 Notes	i 500,000
Accounts payable and accrued liabilities	i 20,315
Accrued interest payable on 2024 Notes	i 9,516
Operating lease liabilities	i 11,088
Liabilities subject to compromise	$	i 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	$	i 24,725
Terminated contracts	i 1,435
Legal and other professional advisory fees	( i 26,357		)
Reorganization items, net	$	( i 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 $ i 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	$	i 328,386
Natural gas	i 53,693
Natural gas liquids	i 40,026
Other	i 1,471
Operating revenue	i 423,576
Gain on sale of assets	i 1,488
Loss on derivatives	( i 11,744		)
Total revenue	i 413,320
Operating expenses
Lease operating	i 79,884
Transportation and marketing	i 70,324
Production taxes	i 19,455
Workovers	i 2,652
Exploration	i 52,354
Depreciation, depletion and amortization	i 120,617
Impairment of assets	i 556,427
General and administrative	i 71,823
Total operating expenses	i 973,536
Operating income	( i 560,216		)
Other income (expenses)
Interest expense	( i 49,823		)
Interest income	i 154
Reorganization items, net	( i 197		)
Total other income (expense), net	( i 49,866		)
Loss from continuing operations before income taxes	( i 610,082		)
Income tax provision (benefit)	i —
Net loss	$	( i 610,082	)

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Combined Balance Sheet



(in thousands)	December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	i 81,669
Restricted cash	i 681
Accounts receivable, net	i 49,256
Other receivables	i 1,311
Related party receivables, net	i 17,586
Prepaid expenses and other current assets	i 6,340
Total current assets	i 156,843
Property and equipment, net
Oil and gas properties, successful efforts method	i 215,352
Other property and equipment	i 23,210
Total property and equipment, net	i 238,562
Other assets
Investment in subsidiary	i 1,505,533
Operating lease right-of-use assets, net	i —
Deferred financing costs, net	i —
Deposits and other long-term assets	i 6,116
Total other assets	i 1,511,649
Total assets	$	i 1,907,054

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	i 58,858
Accounts payable - related parties	i 19,425
Advances from non-operators	i 811
Advances from related party	i 3,175
Asset retirement obligations, current portion	i 34
Total current liabilities	i 82,303
Long-term liabilities
Asset retirement obligations, net of current portion	i 12,995
Total long-term liabilities	i 12,995
Liabilities subject to compromise	i 896,862
Total liabilities	i 992,160
Partners’ capital	i 914,894
Total liabilities and partners’ capital	$	i 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	$	( i 610,082	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	i 120,617
Non-cash lease expense	i 2,981
Provision for uncollectible receivables	i 1,218
Impairment of assets	i 556,427
Non-cash reorganization items, net	( i 26,160		)
Amortization of deferred financing costs	i 195
Amortization of debt premium	( i 3,432		)
Equity-based compensation expense	i 5,718
Non-cash exploration expense	i 43,412
(Gain) loss on derivatives	i 11,744
Cash settlements of derivatives	i 7,642
Cash paid for derivatives	( i 1,906		)
Impact on cash from changes in:
Accounts receivable	i 18,783
Other receivables	i 4,957
Related party receivables	i 3,651
Prepaid expenses and other assets	( i 25,716		)
Advances from related party	( i 6,647		)
Settlement of asset retirement obligations	( i 234		)
Accounts payable, accrued liabilities and other liabilities	i 22,373
Operating lease obligations	( i 2,636		)
Cash from operating activities	i 122,905
Cash flows from investing activities:
Capital expenditures	( i 249,955		)
Distribution received from subsidiary	i 691
Cash from investing activities	( i 249,264		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	i 199,362
Repayments of long-term debt	( i 4,496		)
Payment of taxes withheld on equity-based compensation awards	( i 142		)
Cash from financing activities	i 194,724
Net increase in cash, cash equivalents and restricted cash	i 68,365
Cash, cash equivalents and restricted cash, beginning of period	i 13,985
Cash, cash equivalents and restricted cash, end of period	$	i 82,350

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NOTE 4 — i 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

i 31,023

i 742,065

i —

Impairment of proved properties

i 484,830

i 1,291,647

i —

Impairment of operating lease right-of-use assets

i 13,245

—

Impairment of other long-term assets

i 27,329

i —

Total Upstream impairment of assets

i 556,427

i 2,033,712

i —

Midstream

Impairment of Cimarron investment

i —

i 15,963

i —

Impairment of property and equipment

i 348,597

i 68,407

i —

Impairment of operating lease right-of-use assets

i 269

—

Impairment of intangible assets

i —

i 394,999

i —

Impairment of goodwill

i —

i 691,970

i —

Total Midstream impairment of assets

i 348,866

i 1,171,339

i —

Total impairment of assets

i 905,293

i 3,205,051

i —

Impairment of Proved and Unproved Properties

The Initial Debtors filed for bankruptcy protection in September 2019. The sales price per the AMH PSA is $ i 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 $ i 515.9 million for our proved and unproved oil and gas properties and $ i 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 $ i 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 $ i 13.2 million and $ i 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 $ i 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 $ i 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 i 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 $ i 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 $ i 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 $ i 68.4 million to reduce the carrying value of our Midstream property and equipment to fair value and $ i 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 — i 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 $ i 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 i 8.0 years and the weighted-average discount rate applied was i 14.5%.

Lease Costs



(in thousands)	Year Ended December 31, 2019
Operating lease cost	$	i 3,122
Variable lease cost	i 1,250
Short-term lease cost	i 4,410
Total lease cost	$	i 8,782

Reported in:
Lease operating expense	$	i 4,241
General and administrative expense	i 4,541
Total lease cost	$	i 8,782

Remaining Operating Lease Liability Payments as of December 31, 2019

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

Current portion of operating lease liabilities	$	i 88
Operating lease liabilities, net of current portion	i 189
Present value of operating lease liabilities	$	i 277

NOTE 6 — i RECEIVABLES

Accounts Receivable



(in thousands)	December 31, 2019			December 31, 2018
Production and processing sales and fees	$	i 40,858		$	i 51,004
Joint interest billings	i 12,845			i 18,147
Pooling interest⁽¹⁾	i 7,901			i 18,786
Allowance for doubtful accounts	( i 417		)	( i 95		)
Total accounts receivable, net	$	i 61,187		$	i 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	$	i 12,144		$	i 12,376
Allowance for doubtful accounts	( i 12,144		)	( i 9,035		)
Related party receivables, net	i —			i 3,341

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

At December 31, 2019, we had receivables, including notes receivable from HMI totaling approximately $ i 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 $ i 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	$	i 10,066
Additions	i 832
Payments	( i 1,073		)
HMI related party receivable at December 31, 2019	i 9,825
Allowance for doubtful accounts⁽¹⁾	( i 9,825		)
Balance at December 31, 2019, net	$	i —

_________________


(1)	$ i 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 $ i 9.8 million and $ i 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 $ i 9.8 million and $ i 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 $ i 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 i 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 $ i 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

i 95

i 415

Charged to expense

i 332

i 25

i —

Deductions

( i 10

)

( i 345

)

i —

Balance at end of period

i 417

i 95

i 415

Related party receivables:

Balance at beginning of period

i 22,438

i —

Charged to expense

i 3,196

i 22,438

i —

Deductions

( i 87

)

i —

Balance at end of period

i 25,547

i 22,438

i —

NOTE 7 — i 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	$	( i 450,538	)	$	( i 1,524,699	)

Weighted average Class A common shares outstanding (Basic and Diluted)	i 181,636,795			i 175,151,969

Basic and diluted loss per common share attributable to AMR common stockholders	$	( i 2.48	)	$	( i 8.71	)

During 2019, approximately i 201.0 million shares of Class C Common Stock, i 63.0 million of warrants and i 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 i 99.9 million shares of Class C Common Stock, i 63.0 million of warrants and i 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 — i 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

i 56,683

i 52,017

i 1,145

Cash paid for income taxes

i 706

i 1,573

i —

Non-cash investing and financing activities:

Increase in asset retirement obligations

i 853

i 5,665

i —

Increase (decrease) in accruals or payables for capital expenditures

( i 155,681

)

i 39,997

i 4,896

Increase in withholding tax accruals for share-based compensation

i 142

i 534

i —

Distribution of non-STACK assets, net of liabilities

i —

i 43,482

Equity issued in Business Combination

i —

i 2,067,393

i —

Release of common stock from possible redemption

i —

i 996,384

i —

Other

i 78

( i 6

)

i —

NOTE 9 — i 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) i 100% of the economic interests and i 90% of the voting interests in Alta Mesa GP, ((i) and (ii) collectively, the “AM Contribution”) and (b) i 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 i 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) i 40,000,000 shares of our Class A Common Stock and (ii) warrants to purchase i 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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Index to Financial Statements

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

•

we contributed $ i 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) i 169,371,730 of the common units (approximately i 44.2%) representing limited partner interests in SRII Opco (the “SRII Opco Common Units”) and (ii) i 62,966,651 warrants to purchase SRII Opco Common Units (“SRII Opco Warrants”);


•	we caused SRII Opco to issue i 213,402,398 SRII Opco Common Units (approximately i 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 i 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 $ i 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 $ i 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 i 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 i 2,181,600 and i 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 i 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 i 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 i 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”):

໿



20-Day VWAP	Earn-Out Consideration Payable to AM Contributor	Earn-Out Consideration Payable to KFM Holdco, LLC
$ i 14.00	10,714,285 SRII Opco Common Units	7,142,857 SRII Opco Common Units
$ i 16.00	9,375,000 SRII Opco Common Units	6,250,000 SRII Opco Common Units
$ i 18.00	13,888,889 SRII Opco Common Units	—
$ i 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 $ i 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⁾	$	i 1,261,249
Estimated fair value of contingent earn-out purchase consideration ⁽³⁾	i 284,109
Settlement of preexisting working capital	i 5,476
Total purchase price consideration	$	i 1,550,834

_________________


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

(2)

At closing, the Riverstone Contributor received i 20,000,000 SRII Opco Common Units and High Mesa received i 138,402,398 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, High Mesa received an additional i 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 $ i 7.90 per unit and reflects discounts for holding requirements and liquidity.

(3)

For a period of i 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 $ i 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.

/ i

Purchase Price for KFM



(in thousands)	February 9, 2018
Purchase Consideration:
Cash ⁽¹⁾	$	i 809,812
SRII Opco Common Units issued ⁽²⁾	i 433,931
Estimated fair value of contingent earn-out purchase consideration ⁽³⁾	i 88,105
Settlement of preexisting working capital	( i 5,476		)
Total purchase price consideration	$	i 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 $ i 5.0 million in cash.


(2)	At closing, KFM Holdco, LLC received i 55,000,000 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, KFM Holdco remitted back i 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 $ i 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 $ i 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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Index to Financial Statements

RBL.

NOTE 10 — i PROPERTY AND EQUIPMENT



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

i 118,003

i 129,579

i 11,021

Midstream tangible asset depreciation

i 11,663

i 8,235

i —

Other property and equipment depreciation

i 1,646

i 3,236

i 609

Total depletion and depreciation

i 131,312

i 141,050

i 11,630

Sale of Produced Water Assets

In November 2018, Alta Mesa sold its produced water assets, consisting of over i 200 miles of produced water gathering pipelines and i 20 disposal wells, surface leases, easements and other agreements, to a subsidiary of KFM for approximately $ i 99 million, including approximately $ i 90 million in cash at closing and $ i 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 — i 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 i 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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Index to Financial Statements

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



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



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

NOTE 12 — i 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 $ i 45.3 million at December 31, 2019 ($ i 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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Index to Financial Statements

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

i 31,023

i —

i 31,023

i 816,282

i 74,217

i 742,065

Proved oil and gas properties

i 700,182

i 215,352

i 484,830

i 1,895,670

i 604,023

i 1,291,647

Operating lease right-of-use assets

i 13,514

i —

i 13,514

i —

Other long-term assets⁽¹⁾

i 51,518

i 24,189

i 27,329

i —

Equity method investment

i —

i 17,063

i 1,100

i 15,963

Midstream property and equipment⁽¹⁾

i 432,415

i 83,818

i 348,597

i 474,529

i 406,122

i 68,407

Intangible assets

i —

i 394,999

i —

i 394,999

Goodwill

i —

i 691,970

i —

i 691,970

Total

i 1,228,652

i 323,359

i 905,293

i 4,290,513

i 1,085,462

i 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 — i 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 $ i 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

i 22,512

( i 6,089

)

i 16,423

Derivatives, long-term assets

i 7,910

( i 4,963

)

i 2,947

Total

i 30,422

( i 11,052

)

i 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

i 7,799

( i 6,089

)

i 1,710

Derivatives, long-term liabilities

i 5,143

( i 4,963

)

i 180

Total

i 12,942

( i 11,052

)

i 1,890

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Index to Financial Statements

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

designated as hedges

December 31, 2019

December 31, 2018

February 8, 2018

Gain (loss) on derivatives -

Oil commodity contracts

( i 16,013

)

( i 3,559

)

i 4,796

Natural gas commodity contracts

i 4,269

( i 6,688

)

i 1,867

Total gain (loss) on derivatives

( i 11,744

)

( i 10,247

)

i 6,663

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

NOTE 14 — i INTANGIBLE ASSETS

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

໿



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

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

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

/ i

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

NOTE 16 — i 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

i 11,552

i —

i 10,469

Liabilities assumed in Business Combination⁽¹⁾

i —

i 5,998

i —

Liabilities incurred

i 859

i 2,676

i —

Liabilities settled

( i 234

)

( i 1,610

)

( i 63

)

Liabilities transferred in sale of properties

i —

( i 19

)

i —

Revisions to estimates

i 26

i 3,766

i 63

Accretion expense

i 980

i 741

i 40

Balance, end of period

i 13,183

i 11,552

i 10,509

Less: current portion

i 34

i 2,079

i 33

Long-term portion

i 13,149

i 9,473

i 10,476

_________________


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

NOTE 17 — i LONG-TERM DEBT, NET



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

Alta Mesa RBL

In connection with the Business Combination, we entered into the Alta Mesa RBL which has a face amount of $ i 1.0 billion and had an initial $ i 350.0 million borrowing base, which was subsequently increased to $ i 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 $ i 355.9 million in outstanding borrowings under the Alta Mesa RBL, plus $ i 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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Index to Financial Statements

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 $ i 200.0 million, a reduction from the prior $ i 370.0 million established in April 2019. As a condition to the borrowing base reduction, we were required to make monthly installments of $ i 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 i 1.00% to i 2.00%. At December 31, 2019, outstanding borrowings bore interest at a rate of i 10.75%, which consisted of the Prime Rate plus additional penalty margins of i 2.00% due to our borrowing base deficiency and i 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 $ i 300.0 million. The KFM Credit Facility matures in May 2023. As of December 31, 2019, outstanding borrowings totaled $ i 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 i 1.00%, plus an applicable margin ranging from i 1.00% to i 2.25%. At December 31, 2019, outstanding borrowings bore interest at a rate of i 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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Index to Financial Statements

agreements, amend organizational documents, incur liens, hold cash in excess of $ i 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 $ i 500 million and bear interest at i 7.875% per annum, payable semi-annually each June 15 and December 15. The 2024 Notes mature in December 2024.

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 $ i 533.6 million, yielding a bond premium of $ i 33.6 million. Amortization of the premium reduced our interest expense by $ i 3.4 million and $ i 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

໿



Fiscal Year	(in thousands)
2023	$	i 579,943
2024	i 500,000
	$	i 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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Index to Financial Statements

NOTE 18 — i ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

໿



	Successor
(in thousands)	December 31, 2019			December 31, 2018
Accounts payable	$	i 27,349		$	i 20,422

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

NOTE 19 — i 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

i 12,236

i 6,116

i 18,352

2021

i 12,236

i 6,116

i 18,352

2022

i 12,236

i 5,859

i 18,095

2023

i 12,236

i 5,676

i 17,912

2024

i 5,666

i 5,676

i 11,342

Thereafter

i 19,358

i 64,328

i 83,686

i 73,968

i 93,771

i 167,739

_________________


(1)	Total cash payments required for committed capacity in MMBtus of i 45,750,000 in 2020, i 45,625,000 in 2021, i 40,275,000 in 2022, i 36,500,000 in 2023, i 36,600,000 in 2024 and i 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 i 3,650,000 mcf of processing volumes that runs through December 31, 2021. KFM is required to pay $ i 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 $ i 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 $ i 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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Index to Financial Statements

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

Litigation

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Index to Financial Statements

SEC Investigation

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 $ i 10.9 million as strategic costs in G&A during the 2018 Successor Period.

NOTE 20 — i EMPLOYEE BENEFIT PLANS

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

NOTE 21 — i 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

i 123,000

i 336,248

i 28,757

Marketing and management fees paid to ARM

i 1,715

i —

Fees paid to ARM for services relating to our derivatives

i 496

i 784

i 66

Total fees paid to ARM

i 2,211

i 784

i 66

Receivables from ARM for sales on our behalf were $ i 6.8 million and $ i 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 i 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 — i STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL

Class A Common Stock

Holders of our Class A Common Stock are entitled to i 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 i 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 i 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 $ i 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 i 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 $ i 14.8 million in additional paid in capital. To fund the repurchase of our Class A shares of Common Stock, the Company sold i 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 $ i 10.8 million.

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Index to Financial Statements

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 i 213,402,398 shares of Class C Common Stock to the Contributors, i 199,987,976 of which remain outstanding at December 31, 2019 ( i 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 i 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 i 2,181,600 of our Class C Common Stock. During the 2018 Successor Period, we issued i 2,752,312 and i 9,588,764 shares of our Class A Common Stock to equity owners of High Mesa and KFM Holdco, LLC, respectively, and canceled i 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 i one of the i 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 i two directors to our board of directors for a period of up to i 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 i three directors to our board of directors for a period of up to i 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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Index to Financial Statements

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

Each Public Warrant entitles the holder to purchase i one share of our Class A Common Stock for $ i 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 i 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 i 52.25% at December 31, 2019 ( i 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 i 100% of the economic rights in Alta Mesa GP and (ii) Class B Units, which hold i 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 i 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 i 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 — i EQUITY-BASED COMPENSATION (Successor)

We have adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”). A total of i 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 $ i 6.4 million and $ i 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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Index to Financial Statements

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

i —

—

Granted

i 5,283,224

i 8.80

i 4.33

—

Exercised

i —

—

Forfeited or expired

( i 139,319

)

i 9.38

i 4.55

—

Outstanding as of December 31, 2018

i 5,143,905

i 8.79

i 4.33

i 5.3

—

Granted

i 157,710

i 1.07

i 0.61

—

Exercised

i —

—

Forfeited or expired

( i 1,498,328

)

i 8.44

i 4.20

—

Outstanding as of December 31, 2019

i 3,803,287

i 4.80

i 4.22

i 3.19

—

Exercisable as of December 31, 2019

i 2,260,388

i 9.21

i 4.49

i 5.15

—

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)	i 4.5		i 4.5
Expected stock volatility	i 69.8	%	i 64.6	%
Dividend yield	i —		i —
Risk-free interest rate	i 2.4	%	i 2.5	%

Unrecognized compensation cost related to non-vested stock options at December 31, 2019 was $ i 3.5 million, with a remaining weighted average vesting period of i 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 i 98,199 shares to certain of our directors, all which vested immediately, and granted i 2,140,160 restricted stock awards to employees. All 2019 grants were to employees.

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Index to Financial Statements

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	i —		$	i —
Granted	i 2,238,359		i 7.54
Vested⁽¹⁾	( i 384,413	)	i 8.40
Forfeited or expired	( i 61,935	)	i 8.80
Outstanding as of December 31, 2018	i 1,792,011		i 7.32
Granted	i 70,093		i 0.96
Vested⁽¹⁾	( i 619,061	)	i 7.04
Forfeited or expired	( i 719,766	)	i 7.36
Outstanding as of December 31, 2019	i 523,277		$	i 6.74

_________________

(1) To satisfy minimum tax withholding, i 130,432 and i 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 $ i 2.1 million, with a remaining weighted average vesting period of i 1.4 years.

Restricted stock units

Our PSUs granted in 2018 generally vested over i three years at i 20% during the first year, i 30% during the second year and i 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 i 0% to i 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 i 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	i —		$	i —
Granted	i 2,093,453		i 4.07
Vested ⁽¹⁾	( i 1,559,749	)	i 2.53
Forfeited or expired	( i 533,704	)	i 8.54
Outstanding as of December 31, 2018	i —		i —
Granted	i 1,220,490		i 0.32
Vested	( i 100,870	)	i 0.96
Forfeited or expired	( i 54,112	)	i 0.27
Outstanding as of December 31, 2019	i 1,065,508		$	i 0.27

_________________

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

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Index to Financial Statements

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

NOTE 24 — i 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:

໿



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

( i 195,221

)

i 21.00

( i 682,378

)

i 21.00%

State income taxes - net of federal income tax benefit

( i 44,064

)

i 4.74

( i 154,022

)

i 4.74

Non-controlling interest

i 123,316

( i 13.27

)

i 833,239

( i 25.64

)

Return to provision

( i 1,690

)

i 0.18

( i 71

)

i —

Change in valuation allowance

i 136,568

( i 14.69

)

i 3,135

( i 0.1

)

Permanent items

i —

i 25

i —

Other

( i 18,909

)

i 2.04

i 3

i —

Income tax expense (benefit)

i —

( i 69

)

i —

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Index to Financial Statements

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	$	i 424,086		$	i 269,846
59(e) capitalized IDC	i 53,814			i —
NOL carryforward	i 29,866			i 101,337
Organizational/startup costs	i 144			i 154
Other	i 7			i 11
Total deferred tax assets	i 507,917			i 371,348
Less: valuation allowance	( i 507,917		)	( i 371,348		)
Net deferred tax assets	i —			i —

Deferred tax liability	i —			i —
Total net deferred tax assets/(liabilities)	$	i —		$	i —

The change in our valuation allowance during the year ended December 31, 2019 was $ i 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 i 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 i 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 i 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 i 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 — i 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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Index to Financial Statements

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 $ i 769,000, $ i 1,158,000, and $ i 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 i 60 wells in three tranches, and provided opportunities for the parties to potentially agree to an additional i 20 wells. Pursuant to the JDA, BCE committed to fund i 100% of Alta Mesa’s working interest share up to a maximum average well cost of $ i 3.2 million in drilling and completion costs per well for any tranche. In exchange for funding the drilling and completion costs, BCE received i 80% of our working interest in each wellbore, which BCE interest would be reduced to i 20% of our initial working interest upon BCE achieving a i 15% internal rate of return on the wells within a tranche and automatically further reduced to i 12.5% of our initial interest upon BCE achieving a i 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 $ i 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, i 61 joint wells have been drilled or spudded. As of December 31, 2019 and December 31, 2018, $ i 3.2 million and $ i 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 $ i 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 i 8% per annum and matured in February 2019. At December 31, 2019 and 2018, amounts due under the promissory note totaled $ i 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 $ i 8.5 million promissory note receivable from HMS which matures on December 31, 2019, and bears interest at i 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 $ i 11.7 million. HMI disputes its obligations under the $ i 1.5 million note and $ i 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 $ i 13.4 million, the expense for which is included in general and administrative expense in 2018.

Table of Contents

Index to Financial Statements

Interest income on the promissory notes amounted to approximately $ i 0.9 million and $ i 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 i 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 i 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least i 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 $ i 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 $ i 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 $ i 9.8 million and $ i 10.1 million, respectively, for costs and expenses incurred on HMI’s behalf. During 2019, we billed HMI $ i 0.8 million for incremental costs incurred and have received approximately $ i 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 $ i 9.8 million and $ i 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 — i BUSINESS SEGMENT INFORMATION

Following the Business Combination, we have i 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.

Table of Contents

Index to Financial Statements

Year Ended December 31, 2019

(in thousands)

Exploration &

Production

Midstream

Corporate and Eliminations

Total

Revenue

Oil

i 328,386

i —

i 328,386

Natural gas

i 53,693

i —

i 53,693

Natural gas liquids

i 40,026

i —

i 40,026

Sales of gathered production

i —

i 37,195

i —

i 37,195

Midstream revenue

i —

i 84,763

( i 54,173

)

i 30,590

Segment sales revenue

i 422,105

i 121,958

( i 54,173

)

i 489,890

Other revenue

i 1,471

i 24,988

( i 16,129

)

i 10,330

Operating revenue

i 423,576

i 146,946

( i 70,302

)

i 500,220

Gain (loss) on sale of assets

i 1,488

( i 106

)

i —

i 1,382

Gain (loss) on derivatives

( i 11,744

)

i —

( i 11,744

)

Total revenue

i 413,320

i 146,840

( i 70,302

)

i 489,858

Operating expenses

Lease operating

i 79,884

i —

( i 16,129

)

i 63,755

Transportation, processing and marketing

i 70,324

i 9,659

( i 58,941

)

i 21,042

Midstream operating

i —

i 24,719

i —

i 24,719

Cost of sales for purchased gathered production

i —

i 34,529

i —

i 34,529

Production taxes

i 19,455

i —

i 19,455

Workovers

i 2,652

i 537

i —

i 3,189

Exploration

i 52,354

i —

i 52,354

Depreciation, depletion, and amortization

i 120,617

i 11,675

i —

i 132,292

Impairment of assets

i 556,427

i 348,866

i —

i 905,293

General and administrative

i 59,897

i 35,427

i 12,331

i 107,655

Total operating expenses

i 961,610

i 465,412

( i 62,739

)

i 1,364,283

Operating income

( i 548,290

)

( i 318,572

)

( i 7,563

)

( i 874,425

)

Other income (expense)

Interest expense

( i 49,823

)

( i 11,636

)

i —

( i 61,459

)

Interest income and other

i 154

i 17

i 72

i 243

Equity in earnings of unconsolidated subsidiaries

i —

i 6,216

i —

i 6,216

Reorganization items, net

i 449

i —

( i 646

)

( i 197

)

Total other income (expense)

( i 49,220

)

( i 5,403

)

( i 574

)

( i 55,197

)

Income (loss) from continuing operations before income taxes

( i 597,510

)

( i 323,975

)

( i 8,137

)

^—

( i 929,622

)

Interest expense

i 49,823

i 11,636

i —

i 61,459

Depreciation, depletion and amortization

i 120,617

i 11,675

i —

i 132,292

Loss on unrealized hedges

i 19,386

i —

i 19,386

Loss on sale of property and equipment

i —

i 106

i —

i 106

Impairment assets

i 556,427

i 348,866

i —

i 905,293

Provision for uncollectible related party receivables

i 886

i 2,310

i —

i 3,196

Equity-based compensation

i 5,718

i 694

i —

i 6,412

Exploration

i 52,354

i —

i 52,354

Severance costs

i 4,865

i 2,162

i —

i 7,027

Strategic costs

i 8,116

i 11,479

i 2,025

i 21,620

Non-cash lease operating expense

i 3,835

i —

i 3,835

Gain on equity method investment

i —

( i 5,503

)

i —

( i 5,503

)

Reorganization items, net

( i 449

)

i —

i 646

i 197

Adjusted EBITDAX

i 224,068

i 59,450

( i 5,466

)

i 278,052

Equity method investment

i —

Capital expenditures

i 249,955

i 77,612

i —

i 327,567

Total assets at period end

i 396,041

i 112,825

( i 10,286

)

i 498,580

Table of Contents

Index to Financial Statements

February 9, 2018 Through December 31, 2018

(in thousands)

Exploration &

Production

Midstream

Corporate and Eliminations

Total

Revenue

Oil

i 323,299

i —

i 323,299

Natural gas

i 43,407

i —

i 43,407

Natural gas liquids

i 43,039

i —

i 43,039

Sales of gathered production

i —

i 31,506

i —

i 31,506

Midstream revenue

i —

i 68,519

( i 41,059

)

i 27,460

Segment sales revenue

i 409,745

i 100,025

( i 41,059

)

i 468,711

Other revenue

i 4,762

i —

i 4,762

Operating revenue

i 414,507

i 100,025

( i 41,059

)

i 473,473

Gain on sale of assets

i 4,751

i —

i 4,751

Gain (loss) on derivatives

( i 10,247

)

i —

( i 10,247

)

Total revenue

i 409,011

i 100,025

( i 41,059

)

i 467,977

Operating expenses

Lease operating

i 60,547

i —

( i 3,720

)

i 56,827

Transportation, processing and marketing

i 50,038

i 9,911

( i 40,656

)

i 19,293

Midstream operating

i —

i 15,221

i —

i 15,221

Cost of sales for purchased gathered production

i —

i 31,247

i —

i 31,247

Production taxes

i 16,865

i —

i 16,865

Workovers

i 5,563

i —

i 5,563

Exploration

i 34,085

i —

i 34,085

Depreciation, depletion, and amortization

i 133,554

i 27,388

i —

i 160,942

Impairment of assets

i 2,033,712

i 1,171,339

i —

i 3,205,051

General and administrative

i 114,735

i 14,025

i 2,292

i 131,052

Total operating expenses

i 2,449,099

i 1,269,131

( i 42,084

)

i 3,676,146

Operating income

( i 2,040,088

)

( i 1,169,106

)

i 1,025

( i 3,208,169

)

Other income (expense)

Interest expense

( i 38,265

)

( i 5,031

)

i —

( i 43,296

)

Interest income and other

i 1,983

i 6

i 60

i 2,049

Total other income (expense)

( i 36,282

)

( i 5,025

)

i 60

( i 41,247

)

Income (loss) from continuing operations before income taxes

( i 2,076,370

)

( i 1,174,131

)

i 1,085

⁽¹⁾

( i 3,249,416

)

Interest expense

i 38,265

i 5,031

i —

i 43,296

Depreciation, depletion and amortization

i 133,554

i 27,388

i —

i 160,942

Gain on unrealized hedges

( i 28,714

)

i —

( i 28,714

)

Loss on sale of fixed assets

i 388

i —

i 388

Impairment of assets

i 2,033,712

i 1,171,339

i —

i 3,205,051

Provision for uncollectible related party receivables

i 22,438

i —

i 22,438

Equity-based compensation

i 20,000

i 1,190

i 835

i 22,025

Exploration

i 34,085

i —

i 34,085

Business Combination

i 23,717

i —

i 23,717

Adjusted EBITDAX

i 201,075

i 30,817

i 1,920

i 233,812

Equity method investment

i —

i 1,100

i —

i 1,100

Capital expenditures

i 700,953

i 61,807

i —

i 762,760

Total assets at period end

i 935,719

i 437,721

( i 15,610

)

i 1,357,830

_________________


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

NOTE 27 — i 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.

Table of Contents

Index to Financial Statements

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)	i 73,518		i 433,519		i 36,887		i 182,658
Production	( i 521	)	( i 1,984	)	( i 161	)	( i 1,012	)
Sales of reserves in place ⁽¹⁾	( i 1,667	)	( i 24,239	)	( i 771	)	( i 6,478	)
Revisions of previous quantity estimates and other	i 375		i 3,506		i 289		i 1,248
Balance at February 8, 2018 (Predecessor)	i 71,705		i 410,802		i 36,244		i 176,416
Production⁽²⁾	( i 5,053	)	( i 16,913	)	( i 2,268	)	( i 10,140	)
Purchases in place⁽²⁾	i 2,658		i 13,331		i 1,751		i 6,631
Discoveries and extensions⁽²⁾	i 30,026		i 155,306		i 19,646		i 75,557
Revisions of previous quantity estimates and other⁽²⁾	( i 74,064	)	( i 418,378	)	( i 35,581	)	( i 179,375	)
Balance at December 31, 2018 (Successor)	i 25,272		i 144,148		i 19,792		i 69,089
Production	( i 5,885	)	( i 24,802	)	( i 2,760	)	( i 12,779	)
Discoveries and extensions	i 4,265		i 24,351		i 2,835		i 11,159
Revisions of previous quantity estimates and other⁽³⁾	( i 6,736	)	( i 29,254	)	( i 9,352	)	( i 20,964	)
Balance at December 31, 2019 (Successor)	i 16,916		i 114,443		i 10,515		i 46,505

Proved Developed Reserves:
Balance at December 31, 2017	i 20,347		i 150,183		i 12,180		i 57,557
Balance at February 8, 2018	i 19,345		i 126,231		i 11,348		i 51,731
Balance at December 31, 2018	i 25,272		i 144,148		i 19,792		i 69,089
Balance at December 31, 2019	i 16,916		i 114,443		i 10,515		i 46,505
Proved Undeveloped Reserves:
Balance at December 31, 2017	i 53,171		i 283,336		i 24,707		i 125,101
Balance at February 8, 2018	i 52,360		i 284,571		i 24,896		i 124,685
Balance at December 31, 2018	i —		i —		i —		i —
Balance at December 31, 2019	i —		i —		i —		i —

_________________


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

i 423,576

i 414,507

i 40,136

Production expense ⁽¹⁾

i 232,212

i 247,748

i 30,743

Depreciation, depletion and amortization

i 120,617

i 133,554

i 11,670

Exploration expense

i 52,354

i 34,085

i 7,003

Impairment expense

i 556,427

i 2,033,712

i —

Income tax expense (benefit)

i —

i 4

i —

Results of operations

( i 538,034

)

( i 2,034,596

)

( i 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	$	i 2,239,444		$	i 2,110,346
Unproved properties	i 813,310			i 816,282
Total	i 3,052,754			i 2,926,628
Accumulated depreciation, depletion, amortization and impairment	( i 2,837,402		)	( i 2,163,291		)
Net capitalized costs	$	i 215,352		$	i 763,337

Table of Contents

Index to Financial Statements

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⁾

i —

i 54,587

i 4,240

Proved

i —

i 16,300

i 327

Exploration

i 7,305

i 32,130

i 3,678

Development ⁽³⁾

i 134,908

i 664,138

i 37,672

i 142,213

i 767,155

i 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 $ i 22.3 million for the 2018 Successor Period.


(3)	Includes asset retirement additions (revisions) of $ i 0.9 million and $ i 5.6 million for the 2019 and the 2018 Successor Period, respectively. For the 2018 Predecessor Period, there were i 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.

Table of Contents

Index to Financial Statements

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

i 1,326,490

i 2,446,888

i 5,798,886

Future production costs

( i 825,300

)

( i 1,214,479

)

( i 2,556,361

)

Future development costs

( i 25,251

)

( i 23,183

)

( i 965,780

)

Future income taxes

( i 26,707

)

( i 146,632

)

i —

Future net cash flows⁽¹⁾

i 449,232

i 1,062,594

i 2,276,745

Discount to present value at 10 percent per annum

( i 122,321

)

( i 348,311

)

( i 1,096,859

)

Standardized measure of discounted future net cash flows

i 326,911

i 714,283

i 1,179,886

Base price for crude oil, per barrel, in the above computation

i 55.69

i 65.56

i 52.89

Base price for gas, per Mcf, in the above computation

i 2.58

i 3.10

i 2.99

Realized price for NGLs, per barrel, in the above computation

i 14.60

i 22.44

i 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

i 714,283

i 1,179,886

i 1,105,922

Sales and transfers of oil and gas produced, net of production costs

( i 253,582

)

( i 278,091

)

( i 30,391

)

Net changes in prices and production costs

( i 270,712

)

i 38,963

i 71,334

Revisions of previous quantity estimates

( i 129,305

)

( i 1,120,097

)

i 10,887

Purchases of reserves in-place

i —

i 24,376

i —

Sales of reserves in-place⁽¹⁾

i —

( i 4,807

)

Current year discoveries and extensions, less related costs

i 134,451

i 684,700

i —

Changes in estimated future development costs

i 473

( i 39,069

)

i 491

Development costs incurred during the period

i 84

i 160,583

i —

Accretion of discount

i 81,285

i 117,989

i 110,592

Net change in income taxes

i 79,134

( i 98,568

)

i —

Change in production rate (timing) and other

( i 29,200

)

i 43,611

( i 84,142

)

Net change

( i 387,372

)

( i 465,603

)

i 73,964

Balance at end of period

i 326,911

i 714,283

i 1,179,886

_________________


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

Table of Contents

Index to Financial Statements

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.

Table of Contents

Index to Financial Statements

•

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.

Table of Contents

Index to Financial Statements

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.

Table of Contents

Index to Financial Statements

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).

Table of Contents

Index to Financial Statements



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

Table of Contents

Index to Financial Statements



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

Table of Contents

Index to Financial Statements



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

Table of Contents

Index to Financial Statements

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

Alta Mesa Resources, Inc./DE – ‘10-K’ for 12/31/19

On: Thursday, 3/5/20, at 4:31pm ET · For: 12/31/19 · Accession #: 1690769-20-32 · File #: 1-38040

Previous ‘10-K’: ‘10-K’ on 8/27/19 for 12/31/18 · Next & Latest: ‘10-K/A’ on 4/15/20 for 3/4/20

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Alta Mesa Resources, Inc./DE – ‘10-K’ for 12/31/19

On: Thursday, 3/5/20, at 4:31pm ET · For: 12/31/19 · Accession #: 1690769-20-32 · File #: 1-38040

Previous ‘10-K’: ‘10-K’ on 8/27/19 for 12/31/18 · Next & Latest: ‘10-K/A’ on 4/15/20 for 3/4/20

Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34Filing Table of Contents

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