UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_____________________________________

FORM 10-K

_____________________________________

(Mark One)

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

For the fiscal year ended December 31, 2018

OR

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

For the transition period from             to             

Commission file number: 333-173751

_______________________________________

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

_______________________________________

Texas	20-3565150
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
15021 Katy Freeway, Suite 400, Houston, Texas	77094
(Address of principal executive offices)	(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
None	None	None

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    x  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:    x  Yes    ¨  No

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

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.   However, the registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant would have been required to file such reports) as if it were subject to such filing requirements.)

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

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

Large accelerated filer	¨	Accelerated filer	¨	Non-accelerated filer	¨
Smaller reporting company	¨	Emerging growth company	x

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

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

TABLE OFCONTENTS

		Page
	Glossary	ii
	Cautionary Statement Regarding Forward-Looking Statements	1
	PART I
Item 1.	Business	2
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	37
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	61
Item 8.	Financial Statements and Supplementary Data	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	102
Item 9A.	Controls and Procedures	102
Item 9B.	Other Information	106
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	106
Item 11.	Executive Compensation	108
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120
Item 13.	Certain Relationships and Related Transactions, and Director Independence	122
Item 14.	Principal Accounting Fees and Services	126
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	127
Item 16.	Form 10-K Summary	129
	Signatures	130

i

Glossary of Terms

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

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.
Alta Mesa RBL -	Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent. This credit agreement is a reserve based loan or RBL.
Alta Mesa Services	A wholly-owned subsidiary of Alta Mesa Holdings, LP.
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 -	(British Thermal Unit) The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion -	The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil.
Condensate -	A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
DD&A -	Depreciation, depletion and amortization.
Developed acreage -	The number of acres that are allocated or assignable to productive wells or wells capable of production.
Developed 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.
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.
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses

ii

Enhanced recovery -	The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.
Exploitation -	A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
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.
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
MMBbl -	One million barrels of crude oil, condensate or natural gas liquids.
Net acres -	The total acres a working interest owner has attributable to a particular number of acres, or a specified tract.
Net production -	Portion of production owned by us after production attributable to royalty and other owners.
Net revenue interest -	A working interest owner’s working interest in production after interest of 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.
NYMEX -	The New York Mercantile Exchange.
P&A	(Plug and Abandonment) 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.

iii

PDP -	Proved developed producing reserves.
2018 Predecessor Period	The period from January 1, 2018 through February 8, 2018
Predecessor Periods	The years ended December 31, 2017, 2016, 2015 and 2014
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 -	When used with respect to oil and natural gas reserves, PV-10 means 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 to a present value 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. Our PV-10 is the same as our standardized measure for the periods presented in this report.
Realized price -	The cash market price less all expected quality, transportation and demand adjustments.
Recompletion -	The process of treating an existing wellbore in an attempt to establish or increase existing production.
Reserves -	Estimated remaining quantities of oil and natural gas anticipated to be economically producible from known accumulations.
Reservoir -	A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Resources -	Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable.
Royalty -	An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage.
SEC -	United States Securities and Exchange Commission.
Service well -	A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, produced water disposal, water supply for injection, observation, or injection for in-situ combustion.
Spacing -	The distance between wells producing from the same reservoir. Spacing in horizontal development plays is often expressed in terms of feet, e.g., 1000 foot spacing, and is often established by regulatory agencies.
STACK -	An oilfield in the eastern portion of the Anadarko Basin; STACK is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area.

iv

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%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes. Our standardized measure is the same as our PV-10 for the periods presented in this report.
Stratigraphic test well -	A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
Success rate -	The percentage of wells drilled which produce hydrocarbons in commercial quantities.
Successor Period -	The period from February 9, 2018 through December 31, 2018
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
Waterflood -	The injection of water into an oil reservoir to “sweep” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically, an enhanced recovery process.
Working interest -	The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs.
Workover -	Operations on a producing well to restore or increase production.

v

Cautionary Statement Regarding Forward-Looking Statements

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

Forward-looking statements may include statements about:

• our ability to continue as a going concern;

• 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;

• the timing and amount of our future production;

• our hedging strategy and expected results;

• competition and government regulation;

• our ability to obtain permits and governmental approvals;

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

• pending legal and environmental matters;

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

• our marketing of our production;

• our leasehold or business acquisitions;

• our costs of developing our properties;

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

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

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

• general economic conditions;

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

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

• the costs, terms and availability of midstream services;

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

• our ability to collect receivables from High Mesa.

1

We caution you that any forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, the ability of the combined company to realize the anticipated benefits of the Business Combination, commodity price volatility, global economic conditions, including supply and demand levels for oil, gas and NGLs, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, liabilities resulting from litigation, difficulty in obtaining necessary approvals and permits, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, cyber-attacks, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties, and the other risks described under “Item 1A. Risk Factors” in this Annual Report.

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, 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. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and gas that are ultimately recovered.

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 Holdings, LP, together with its consolidated subsidiaries (“we,” or the “Company,”), is an independent exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We were formed in 1987 as a private Texas limited partnership. Our principal offices are at 15021 Katy Freeway, Suite 400, Houston, Texas 77094 and our main phone number is (281) 530-0991.

Beginning in the 1990’s, our predecessor operations were focused on vertical wells, waterfloods and analyzing the commercial productivity of the stacked formations on our acreage. Since 2012, our activities have become primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the Anadarko Basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County (“STACK”). The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, with potential for multiple horizontal target horizons, extensive production history and high drilling success rates. We generally maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners. We conduct all of our operations in the Upstream segment.

As of December 31, 2018, we have assembled a highly contiguous position of approximately 140,000 net acres in the up-dip, naturally-fractured oil portion of the STACK, primarily in eastern Kingfisher and southeastern Major Counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. When we consider acquiring STACK acreage, we prioritize opportunities where we can be the operator. During 2019, we expect to focus on optimizing completion

2

design and well spacing, reducing our well costs and lowering our operating cost structure (including lease operating and general and administrative expenses).

Business Combination

As described further in Item 8 of this Annual Report, certain transactions were consummated on February 9, 2018, that resulted in us being acquired by Alta Mesa Resources, Inc., a publicly traded corporation (“AMR”). These transactions are referred to as the “Business Combination.” Prior to the closing of the Business Combination, we were controlled by High Mesa Inc. (“HMI”).

During the fourth quarter of 2017, we sold certain of our non-STACK oil and gas assets and liabilities. Immediately prior to the closing of the Business Combination, we distributed our remaining non-STACK oil and gas assets and liabilities to High Mesa Holdings, LP (the “AM Contributor”), such that our only remaining oil and gas assets and liabilities were located in the STACK. Information related to our 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, our assets and liabilities were recorded at their estimated fair values, which values have been pushed down to us. 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”).

Sale of Produced Water Assets

In November 2018, we sold our produced water assets, consisting of over 200 miles of produced water gathering pipelines and related facilities, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher Midstream, LLC (“KFM”), a related party and an entity under common control by our parent, AMR, for $98.0 million, including approximately $90.0 million in cash transferred during 2018. The remaining balance owed of approximately $8.0 million is included in related party receivables. In conjunction with the sale, we entered into a new fifteen-year produced water disposal agreement with KFM.

Going Concern

As a result of the recent decrease in our forecasted production levels, increased operating costs, and pressures created by lower commodity prices, in the absence of one or more deleveraging transactions, we do not anticipate compliance with the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of June 30, 2019. We therefore have substantial doubt regarding our ability to continue as a going concern. Our parent’s board of directors and its financial advisors are evaluating the financial alternatives available to it, including, without limitation, seeking amendments or waivers to the covenants or other provisions of our indebtedness, raising new capital from the private or public markets or taking other actions to address our capital structure. For a more detailed discussion, please read “Item 1A. Risk Factors.”

Principal Products, Markets and Customers

We sell our production to customers generally at prevailing spot prices in effect at the time of the sale. Collateral or other security is generally not required with regard to our trade receivables. Much of our oil and gas production is sold through a marketing agreement with ARM Energy Management, LLC (“ARM”), who markets and sells our oil and gas production under short-term contracts, generally with month-to-month pricing based on published indices, adjusted for transportation, location and quality. ARM remits monthly collections of these sales to us, net of its fee. For the Successor Period, ARM marketed $309.7 million, or 75% of our total operating revenue for the period. We sell our NGL production under various contracts with processors in the vicinity of the production at spot market rates, after processing costs. Other than our marketing agreement with ARM, no other customers accounted for more than 10% of our consolidated sales for the Successor Period. We do not believe the loss of any specific customer, or of our marketing agent ARM, would have a material adverse effect on us because alternative purchasers are available.

The oil and gas production from our operated STACK acreage, not otherwise previously dedicated, is dedicated to KFM.

3

Operating Summary:

	Successor		Predecessor
	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Net production:
Oil (Mbbls)	5,053		494		3,907		2,571
Natural gas (MMcf)	16,913		1,609		13,972		8,259
NGLs (Mbbls)	2,268		151		1,277		824
Total (MBoe)	10,140		914		7,513		4,772
Daily average (MBoe)	31.1		23.4		20.6		13.1
Average sales prices (pre-hedging):
Oil (per bbl)	$	63.99	$	62.68	$	49.76	$	41.15
Natural gas (per Mcf)	2.57		2.66		2.70		2.42
NGLs (per bbl)	18.98		26.41		24.62		17.21
Combined (per Boe)	40.41		42.95		35.10		29.35
Average sales prices (after hedging):
Oil (per bbl)	$	56.64	$	56.24	$	49.42	$	73.25
Natural gas (per Mcf)	2.42		3.60		3.19		3.21
NGLs (per bbl)	18.98		26.41		23.48		16.81
Combined (per Boe)	36.51		41.13		35.64		47.93
Average costs per BOE:
Lease operating expense	$	5.97	$	4.82	$	5.85	$	6.20
Marketing and transportation expense	4.93		4.08		3.92		2.44
Production and ad valorem taxes	1.66		1.04		0.73		0.58
Workover expense	0.55		0.46		0.57		0.72

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 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 than us and have been engaged in the oil and gas business for a longer period of time than we have. This may allow our competitors to have an advantage over us with respect to:

• acquisitions of oil and gas properties, exploratory prospects and mineral leases;

• evaluations of properties; and

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

4

We are also affected by competition for drilling rigs and other equipment, including that used in our completion process. In the past, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe, materials (including drilling and completion fluids) and personnel. These shortages can delay our development, exploitation and exploration activities. We are unable to predict when, or if, such future shortages will occur or their impact on our operations.

With decreased activity in the STACK since 2018, we have seen opportunities to renegotiate our service costs. We believe that we can continue to drive service costs down or maintain the savings that we have captured during 2019.

Regulatory Environment

Our upstream 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:

• 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 regulatorily-deemed hazardous wastes. 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, dubbed 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

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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 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.

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 permit requirements and also utilize equipment or technologies to control emissions. Obtaining such permits could delay our 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 prepare an environmental assessment that assesses the potential impacts of a proposed project and may prepare 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 experience 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 (“OSHA”) and comparable state statutes whose purpose is 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.

Hydraulic Fracturing

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We perform hydraulic fracturing in horizontally drilled wells. Currently, most of our hydraulic fracturing activities are regulated at the state level as the EPA only has limited purview over 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.

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 these methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012, and known as Subpart OOOO, by using certain equipment-specific emissions control practices.

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 regulation 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.

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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 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.

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”) 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.

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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 May 1, 2019, we had 138 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. We currently have policies in place that cover 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 vendors, suppliers and employees and contractors. Additionally, each party generally is responsible for damage to its own property. We do not have insurance coverage for losses solely related to hydraulic fracturing operations.

Available Information

We periodically disseminate information about the Company through required filings we make with the SEC and, at our discretion, on our parent company’s website at www.altamesa.net. 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 issuers that file. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, are filed electronically and are available free of charge at http://www.sec.gov . Our reports are not separately available on our parent company’s website. Accordingly, the Company will provide electronic or paper copies free of charge upon request to our parent company’s Secretary at 15021 Katy Freeway, Suite 400, Houston, Texas 77094 or by calling (281) 530-0991.

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Item 1A. RiskFactors

Each of the following risk factors could adversely affect our business, operating results and financial condition (which we individually and/or collectively refer to as having “an adverse effect on us.” It is not possible to foresee or identify all such factors. Investors should not consider this list an exhaustive statement of all risks and uncertainties. This report also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ from those anticipated in these forward-looking statements as a result of both the risks described below and factors described elsewhere in this report. Please read the section above entitled “Cautionary Statement Regarding Forward-Looking Statements” for further discussion of these matters.

Oil, gas and NGL prices are highly volatile and a sustained decrease in prices can significantly and adversely affect our financial condition, results of operations and the carrying value of our assets.

Historically, the markets for oil, gas and NGLs have been volatile and are likely to continue to be volatile in the future, causing prices to fluctuate widely. Factors influencing the prices of oil, gas and NGLs are beyond our control. These factors include, but are not limited to, the following:

• domestic and worldwide supply of, and demand for, oil, gas and NGLs;

• volatility and trading patterns in the commodity-futures markets;

• the cost of exploring for, developing, producing, transporting and marketing oil, gas and NGLs;

• the level of global oil and gas inventories;

• weather conditions;

• the level of U.S. exports of oil, LNG or NGLs;

• the ability of the members of OPEC and other producing nations to agree to and maintain production levels;

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• the worldwide military and political environment, civil and political unrest worldwide, including in Africa and Middle East, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities, or acts of terrorism in the United States or elsewhere;

• the effect of worldwide energy conservation and environmental protection efforts;

• the price and availability of alternative and competing fuels;

• the value of the dollar relative to the currencies of other countries;

• the level of foreign imports of oil, gas and NGLs;

• domestic and foreign governmental laws, regulations and taxes;

• stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and gas;

• the proximity to, and capacity of, gas pipelines and other transportation facilities; and

• general economic conditions worldwide.

The long-term effects of these and other factors on the prices of oil, gas and NGLs are uncertain. Historical declines in commodity prices have adversely affected our business by:

• reducing the amount of oil, gas and NGLs that we can produce economically;

• reducing our liquidity, revenue, operating income and cash flows;

• causing us to reduce our capital expenditures and delay or postpone some of our capital projects;

• causing reductions to the Alta Mesa RBL borrowing base, which negatively impacts our borrowing ability;

• causing contractions of available trade credit;

• pressuring our ability to meet financial covenants under our debt agreements;

• triggering impairments of our long-term assets;

• reducing the value of our future net cash flows from our oil and gas properties;

• increasing the costs of obtaining capital, such as equity and short- and long-term debt; and

• adversely affect the ability of our partners to fund their working interest capital requirements.

In April 2019, we removed all of our PUD reserves effective as of December 31, 2018 due to our assessment of our ability to fund the associated development costs. Lower oil, gas and NGL prices and any corresponding reduction in our capital expenditure budget and drilling program could cause us to further reduce our estimates of production, which could reduce the value of our oil and gas properties.

Our operations, including development and acquisitions, will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

Our industry is capital intensive. We have made and expect to continue to make substantial capital expenditures for the exploration, exploitation, development and acquisition of oil and gas reserves. Due to the price environment in late 2018 and early 2019, we have substantially decreased our planned capital expenditures for 2019 compared to 2018.  Our upstream capital expenditures for 2019 are estimated to range from $190.0 million to $210.0 million principally for the drilling and completion of wells, expenditures for facilities and acquisition of leasehold. Our upstream capital expenditures for 2018 were substantially higher. Given our reduced capital plan for 2019, we are currently estimating a decline in production during each quarter of 2019. This decline in production as well as other factors such as lower oil, gas and NGL prices or declines in reserves may lead to reductions in our revenue and operating cash flow, and may limit our ability to obtain the capital necessary to sustain our operations at desired levels, which could materially and adversely affect us.

We funded our 2018 upstream capital program primarily through equity capital raised from the Business Combination, borrowings under the Alta Mesa RBL and operating cash flow.  We intend to finance our 2019 and future capital expenditures predominantly with cash flow from operations and borrowings under the Alta Mesa RBL, presuming that we continue to be able to access capital thereunder.

If necessary, and if permitted under the agreements governing our indebtedness, we may also access capital through proceeds from potential asset dispositions and the future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to several variables, including:

• the estimated quantities and value of our proved oil and gas reserves;

• the amount of oil and gas we produce from existing wells;

• the prices at which we sell our production; and

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• our ability to acquire, locate and produce new reserves.

On April 1, 2019, in connection with the Alta Mesa RBL’s semi-annual borrowing base redetermination, our borrowing base was reduced from $400 million to $370 million. If our operating cash flow or the borrowing base under the Alta Mesa RBL decreases for any reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. The Alta Mesa RBL may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all. If cash generated by operations or liquidity available under the Alta Mesa RBL is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our capital expenditures, which in turn could lead to a decline in our reserves and production, forfeiture of leasehold interests and the sale of our assets on an untimely or unfavorable basis, each of which could have a material adverse effect on us.

Our ability to continue as a going concern contemplates the realization of assets and the satisfaction of liabilities in the normal course of business, including the effective implementation and success of our plans to mitigate the conditions that raise substantial doubt about our ability to continue as a going concern.

Our consolidated financial statements have been presented on the basis that we would continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. Our liquidity and ability to comply with debt covenants under the Alta Mesa RBL have been negatively impacted by the recent decrease in forecasted production levels and increased operating costs, in addition to the pressures created by lower commodity prices in late 2018 and early 2019. Based on our current operating and commodity price forecast and our current capital structure, and in the absence of the consummation of one or more of the deleveraging transactions discussed below, we do not anticipate being able to maintain compliance with the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of June 30, 2019. The uncertainty related to our continued compliance with the financial covenants under the Alta Mesa RBL raises substantial doubt regarding our ability to continue as a going concern. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.

In March 2019, our parent’s board of directors authorized the retention of financial advisors to assist in evaluating the available financial alternatives, including without limitation:

• amending or waiving the covenants or other provisions of our debt;

• raising new capital in private or public markets; and

• taking other actions to address our balance sheet either in court or through an out of court agreement with creditors.

We are also considering operational matters such as reducing our forecasted capital plan. Any combination of such plans may be unsuccessful in attaining compliance with the covenants under the Alta Mesa RBL.

If an agreement is reached with our creditors and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings. We also may conclude that it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims and interests with respect to, or rights to acquire, our equity securities would be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration. If that were to occur, we anticipate that all or substantially all of the value of all investments in our equity securities would be lost and that our equity holders would lose all or substantially all of their investment. It is also possible that our stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims.

Our business strategy involves the use of technology, which involves risks and uncertainties in its application.

Our operations involve the use of the latest horizontal drilling, completion and production technologies in an effort to improve more efficient or inexpensive recovery of hydrocarbons. Although our development plan for 2019 relies upon less innovation than in prior years, our use of emerging technologies may not prove successful and could result in unexpected costs or decreases to production or the expected recoverability of reserves and in extreme cases, the abandonment of a well. While horizontal development has become more common in our industry, we may still face difficulties in drilling horizontal wells such as:

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• landing our wellbore in the desired drilling zone;

• staying in the desired drilling zone while drilling horizontally through the formation;

• running our production casing the entire length of the wellbore; and

• running tools and other equipment consistently through the horizontal wellbore.

The difficulties that we face while completing our wells include the following:

• designing and executing the optimum fracture stimulation program for a specific target zone;

• running tools through the entire length of the wellbore during completion operations; and

• cleaning out the wellbore after completion of the fracture stimulation.

Certain of the techniques may cause irregularities or interruptions in production due to offset wells being shut-in and the time required to drill and complete multiple wells before any such wells begin producing. Producing wells can be impacted by nearby completion operations which typically require nearby producing wells to de-water before production can resume. We have received, and are likely to continue to receive, claims alleging damage from our fracture and stimulation procedures on adjacent wellbores completed in the same geological interval and in other “associated” geological formations located above or below the target formation. These claims are inherently uncertain, and outcomes cannot be predicted.

Furthermore, the application of technology in one productive formation may not be successful in other prospective formations with little or no horizontal drilling history. If our use of the emerging technologies does not prove successful, our resulting production may be less than anticipated or we may experience cost overruns, timing delays or abandonment of a well. As a result, the return on our investment will be adversely affected, we could incur material write-downs of our assets, both of which could have a material effect on us.

Our oil and gas properties are located in a limited geographic area, making us vulnerable to risks associated with having geographically concentrated operations.

Our oil and gas properties are geographically concentrated in a portion of the STACK, which causes our success and profitability to be disproportionately exposed to regional factors relative to our competitors that have more geographically dispersed operations. These factors include, among others: (i) the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including midstream capacity constraints; (ii) the access to and availability of rigs, equipment, oil field services, supplies and labor; and (iii) the availability of and access to processing and refining facilities. In addition, we may have a heightened risk to the adverse effects of severe weather events such as floods, ice storms and tornadoes, which can disrupt operations and intensify competition and risk of unavailability of the items described above. The geographic concentration of our operations also increases our exposure to changes in local laws and regulations, wildlife protection stipulations and other unexpected regional events such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these events has the potential to disrupt our operations which could have a material adverse effect on us.

Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter our ability to conduct development activities.

Our management team has specifically identified and scheduled the prospective drilling locations on our existing acreage. Our ability to develop our identified locations depends on a number of uncertainties, including oil, gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of necessary field services and equipment, lease expirations, midstream constraints, access to and availability of water to conduct development, regulatory approvals and other factors. Because of these uncertainties, we do not know if the locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these locations. In addition, unless we meet the development timing requirements on our undeveloped acreage, the leases covering such acreage may expire, causing us to lose the opportunity of future development. As such, our actual drilling activities may materially differ from our current expectations.

Our current estimated drilling locations are based on the spacing pattern that we believe will maximize the economic returns associated with development. If our expectations about well results with such spacing pattern prove incorrect, there could be a material reduction to our estimated drilling locations and inventory life.

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In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to access or raise the capital required. Any drilling activities we conduct on these locations may be unsuccessful, which would limit our ability to add proved reserves or result in a downward revision of our estimated recoveries, which could have a material adverse effect on us.

Our undeveloped properties include leases that will expire over the next several years if production is not established on units containing that acreage.

Leases on oil and gas properties typically have a term of three to five years, after which they expire unless renewed or, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. Although the majority of our reserves are located on leases that are held by production, the leases included in our unproved properties typically have provisions whereby a lease will expire at the end of the lease term unless certain conditions are met, such as commencement of drilling or the existence of production in paying quantities within defined time periods. A reduction to our drilling program, lower commodity prices or our inability to fund our capital program could cause some of our unproved inventory to become unrealizable, be subject to lease expiration or require us to incur renewal or extension costs. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. This could result in a reduction in our acreage and growth opportunities (or the incurrence of significant costs). Our drilling plans for undeveloped acreage are subject to change based upon various factors, including drilling results, oil, gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

We depend on development of our assets and upon consummation of acquisitions to maintain reserves and revenue.

In general, the volume of production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. For example, we estimate that our wells experience approximately a 40% first year decline in production. Thus, absent successful development of our assets or acquisition of properties that have existing proved developed reserves, our revenue could decline as reserves are produced. Our future oil and gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Our reduced drilling program for 2019 could negatively affect our ability to replace reserves and maintain our current production levels, which could have a material adverse effect on us.  Additionally, to the extent our operating cash flow falls below projections and external sources of capital become limited or unavailable, our ability to conduct the capital investment to maintain or expand our asset base would be impaired.

We recognized material impairments to our upstream assets during 2018. Lower oil, gas and NGL prices or changes in our own operational performance may trigger additional impairments which could have a material effect on us.

We may recognize significant impairments of our proved and unproved oil and gas properties as a result of lower forecasted commodity prices, results of our development activities, reductions to our drilling plans or other material issues related to our businesses. As a result, we may be forced to write-down or write-off assets, restructure our operations, or incur impairment or other charges that could result in accounting losses. Even though these charges may be non-cash items and may not have an immediate impact on our liquidity, the fact that we report charges of this nature could lead to negative market perceptions about us or our securities. In addition, charges of this nature may result in our inability to obtain future financing on favorable terms, or at all.

GAAP requires that we periodically review the carrying value of our properties for possible impairment.  Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics, and other factors, we may be required to impair our properties further. 

Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil and gas reserves. Our estimation of proved reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding production levels and operating and development costs. Although the SEC has established a rule specifying the commodity prices that are incorporated into our proved reserve estimates, the prices that we use in estimating the fair value require us to develop future

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oil, gas and NGL prices in line with forward market expectations. We also estimate well costs and operating expenses based on recent experience, but these estimates could prove inaccurate. As a result, estimated quantities of proved reserves and projections of future cash flows and production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates to reflect actual drilling results and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and gas, the classifications of reserves based on risk of recovery and estimated future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Sustained lower prices will cause the 12-month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in reductions to the estimated quantities and present values of our reserves.

The standardized measure of our proved reserves will not be the same as the current fair value of our oil and gas properties.

We do not believe that the present value of future net revenue from our proved reserves represents the fair value of our oil and gas properties. In accordance with SEC requirements, we based the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted arithmetic average of the closing prices on the first day of each month for the preceding 12 months without giving effect to derivatives. Actual future net cash flows from our oil and gas properties will be affected by factors such as:

• actual prices we receive for our production, including the effects of our hedging program;

• actual cost of development and production expenses;

• the amount and timing of actual production;

• transportation and processing cost and availability; and

• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with our operations will affect the timing and amount of actual future net revenue and thus our oil and gas properties’ actual present value. In addition, the 10% discount factor we use in the standardized measure may not be the most appropriate discount factor to utilize in determining the fair value of our oil and gas properties. For example, although the standardized measure applies a 10% discount factor to both PDP and PUD reserves alike, in property sales transactions the fair value of PDP has historically been determined using a lower discount rate and the fair value of PUD reserves has typically been determined using a higher discount rate. Actual future prices and costs may differ materially from those used in the present value estimate.

We rely on drilling to increase our levels of production. Our production levels will be adversely affected by the planned reductions in our capital program.

A key component to our business strategy is to increase production levels by drilling wells. Although we were successful in elevating production levels during 2018, we cannot provide assurance that we will be able to maintain or grow production levels in the future. For example, our reduced drilling program for 2019 could negatively affect our ability to maintain or increase production levels and we are currently estimating a decline in production for each quarter in 2019. We may be unable to accelerate our drilling program in future years to make up for lost production which could have a material adverse effect on us.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow. Acquisitions that we do complete could be on terms that prove to be uneconomic.

We have made and expect to make future acquisitions of businesses or properties that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. We may not be able to obtain contractual indemnities from sellers for liabilities incurred prior to our acquisition.

The success of any completed acquisition will depend on our ability to integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets or to minimize any unforeseen operational difficulties could have a material adverse effect on us.

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In addition, our debt agreements impose certain limitations on our ability to enter into mergers or combinations transactions and our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

Our business is subject to operational risks that will not be fully insured, which could adversely affect us.

Our business activities are subject to operational risks, including:

• damages or disruptions caused by natural disasters such as earthquakes and adverse weather conditions;

• facility or equipment malfunctions;

• pipeline or tank ruptures or spills;

• surface fluid spills and water contamination;

• fires, blowouts, well collapses and explosions; and

• uncontrollable flows of oil or gas or other well fluids.

In addition, a portion of our gas production is processed to separate NGLs. If the processing plants that service us were to cease operations, we would need to arrange for alternative transportation and processing facilities, which may not be available. If unavailable, we might have to shut in our gas and, therefore, other production, which could reduce our operating cash flow. Further, any alternative facilities could be more expensive than the facilities we currently use.

Any of these types of events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension or termination of operations and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in our industry, we maintain insurance against some, but not all, of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of insurance exceeds our perceived risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on us.

Drilling for and producing oil and gas are high risk activities with many uncertainties that could adversely affect us.

Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and gas production.

Our decisions to develop or purchase properties will depend on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. As addressed elsewhere in our Risk Factors, this variability in interpretations presents risk for us. Further, many factors may curtail, delay or cancel our contemplated capital activities, including:

• delays imposed by regulatory bodies or from regulatory compliance, including regulations imposed on produced water disposal;

• regulation limiting the emission of GHGs;

• well set-back legislation or regulation;

• regulation limiting hydraulic fracturing;

• unexpected pressure or irregularities in geological formations;

• shortages of or delays in obtaining equipment, qualified personnel or water for hydraulic fracturing;

• equipment failures, accidents or other unexpected operational events;

• lack of available gathering facilities or delays in construction of gathering facilities;

• lack of available capacity on interconnecting transmission pipelines;

• adverse weather conditions;

• issues related to compliance with environmental regulations;

• environmental hazards, such as leaks, spills, ruptures and unauthorized discharges of fluids and gases associated with our operations;

• declines in oil and gas prices;

• limited availability of financing at acceptable terms; and

• title problems.

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Our derivative program could result in financial losses or could reduce our net income.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and gas, we regularly enter into derivatives (“hedges”) covering a significant portion of our expected production. The Alta Mesa RBL requires us to hedge at least 50% of anticipated equivalent production of our PDP reserves for the upcoming twenty-four month period at each measurement date, but also imposes maximum hedging levels for each production stream. Details of our derivative assets are included in Item 8. If we experience a sustained material interruption in our production, we might be forced to make payments under our hedging program without the benefit of the proceeds from our sale of the underlying production, which would have a material adverse effect on us. Further, risk exists that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge, although all of the counterparties to our current portfolio are lenders under the Alta Mesa RBL. Under that agreement, if a counterparty is a lender and does not perform, then the non-performance is treated as a reduction to the borrowings outstanding. Furthermore, given our current financial condition, our counterparties have ceased providing the credit necessary to enter into new hedges. Therefore, we may be more exposed to future price fluctuations. We may also be unable to comply with the minimum hedging requirements under the Alta Mesa RBL.

Our policy has been to meet the minimum required hedging levels under the Alta Mesa RBL and to opportunistically hedge an additional portion of our near-term estimated production. Other than the compliance with minimum and maximum hedging levels, our price hedging strategy and future hedging transactions will be determined using Board and management discretion, depending on the financial and future commodity expectations at the time. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged, as compared to current or historic levels, which would result in our oil and gas revenue becoming more sensitive to commodity price fluctuations.

Our use of seismic data is subject to interpretation and may not accurately identify the presence of hydrocarbons, which could adversely affect us.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques help geoscientists in identifying subsurface structures and hydrocarbon indicators, but do not prove the amount, if any, of hydrocarbons present in those structures. The use of seismic data and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, which may result in additional costs without an uplift to a well’s economics. As a result, even our successful drilling activities may not prove economic.

We often gather seismic data surveys over large areas including areas where we own no mineral rights. We may choose not to acquire or pursue mineral interests in areas covered by these surveys, which could result in substantial expenditures to acquire and analyze seismic data without the prospect of future benefit of production.

Competition in our industry is intense, making it more difficult for us to acquire properties, market oil or gas and secure trained personnel.

Our ability to acquire additional properties and pursue our operational objectives is dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive market. Our competitors may be able to pay more for oil and gas properties and pursue a greater number of properties than we can. In addition, our industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has adversely affected the timing and cost of operating. Competition has been historically strong in hiring experienced personnel, particularly in the engineering and technical, accounting, legal and land disciplines. An inability to compete effectively with our competitors could have a material adverse impact on us.

We may not be able to keep pace with technological developments in our industry.

Our industry has been characterized by rapid and significant technological advancements and introductions of new products and services using new technologies, all of which could either generate better recoveries or reduce development costs. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and gas companies may be better able to leverage

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technological advantages. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, it may have a material adverse effect on us.

Deficiencies in title to our leased interests could have a material adverse effect on us.

If an examination of the title history of a property reveals that an oil or gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or gas lease or leases or other developed rights would be lost. In acquiring mineral rights, we typically choose not to incur the expense of retaining title attorneys, instead we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records before we attempt to acquire a lease or other mineral interest.

Prior to drilling a well that we operate, however, we do obtain a preliminary title review of the spacing unit to ensure there are no obvious defects in title to the well. If we do find defects, we must perform or fund curative work to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. We may also elect to proceed with a well despite defects to the title identified in the preliminary title opinion. If we fail to obtain defensible title to our leasehold, we may be unable to develop additional reserves or benefit from the expected ownership.

Our operations are substantially dependent on the availability of water and our inability to obtain water may have a material adverse effect on us.

Water is an essential component of unconventional oil and gas upstream during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. However, our access to such water supplies may become limited by factors such as extended drought, competition for water or governmental regulation. If we are unable to obtain sufficient amounts of water, our ability to develop our reserves could be restricted or made less economic, which could have a material adverse effect on us.

Litigation and investigations by private plaintiffs or government officials or entities could adversely affect our performance.

Oil and gas upstream activities are complex and involve risks that could lead to legal proceedings. We currently are defending litigation and anticipate that we will be required to defend new litigation in the future. The subject matter of such litigation may include releases of hazardous substances from our facilities, contract, title or royalty disputes, regulatory compliance matters, personal injury or property damage matters or disputes related to any other laws or regulations that apply to our operations. In some cases, the plaintiff or plaintiffs seek alleged damages involving large classes of potential litigants and may allege damages relating to extended periods of time or other alleged facts and circumstances. For instance, our parent company and certain of its former and current directors and officers were named as defendants in three putative securities class action claims alleging that the defendants disseminated a false and misleading proxy statement in connection with the Business Combination as well as alleged misstatements after the Business Combination. In addition, the SEC is conducting a formal investigation into the facts involved in the material weakness in our internal controls over financial reporting and the impairment disclosed previously and in this annual report.

These and other legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that such proceedings could result in liability, penalties or sanctions, judgments, consent decrees, injunctive relief or orders requiring a change in our business practices, which could have a material adverse effect on us. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Our operations are regulated and the costs to comply or a failure to comply could be costly and have a material adverse effect on us.

We may incur significant costs and liabilities as a result of wide-ranging environmental requirements applicable to our operations. Such environmental laws and regulations include the following federal laws (along with their state counterparts):

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• the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring and reporting requirements and is relied upon by the U.S. Environmental Protection Agency (“EPA”) as authority for adopting climate change regulatory initiatives relating to GHG emissions;

• the Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;

• the Oil Pollution Act (“OPA”), which imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States;

• the Safe Drinking Water Act (“SDWA”), which ensures the quality of the nations’ public drinking water through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations;

• the Resource Conservation and Recovery Act (“RCRA”), which imposes requirements for the generation, treatment, storage, transport disposal and cleanup of non-hazardous and hazardous wastes;

• the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which imposes liability on generators, transporters and arrangers of hazardous substances sent for disposal to sites where hazardous substance releases have occurred or are threatening to occur, as well as imposes liability on present and certain past owners and operators of sites were hazardous substance releases have occurred or are threatening to occur;

• the Emergency Planning and Community Right to Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees and response departments about toxic chemical uses and inventories;

• the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas; and

• the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments or environmental impact statements.

These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective actions obligations, the incurrence of capital expenditures, delays in the permitting, development or expansion of projects, and the issuance of orders enjoining some or all of our future operations in a particular area. Certain environmental laws and regulations impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and more stringent laws and regulations may be adopted in the future. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results

Changes in the legal and regulatory environment governing our industry, particularly changes in the Oklahoma forced pooling system, could have a material adverse effect on us.

Our business is subject to various forms of extensive government regulation, including laws and regulations concerning the location, spacing and permitting of the wells we drill and the disposal of produced water. Changes in the legal and regulatory environment, particularly any changes to Oklahoma’s forced pooling procedures could result in increased compliance costs and adversely affect us.

In the past we have used, and we expect to continue to use, Oklahoma’s forced pooling process to increase our working interest in sections we propose to drill. In recent years, a relatively low percentage of working interest owners in our operated sections have elected to participate in our wells. Due to the continuing consolidation in the STACK by producers with greater access to capital, other working interest owners may be more likely to participate in the wells we drill. Thus, our ability to use forced pooling to increase our working interest in may be more difficult to accomplish.

The adoption of derivatives legislation and regulations could have an adverse impact on our ability to hedge risks associated with our business.

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Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the SEC and the Commodity Futures Trading Commission (the “CFTC”) to enact further regulations affecting derivatives, including those we use to hedge our commodity exposure. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016 a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued. Similarly, on December 2, 2016, the CFTC re-issued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into derivatives to hedge or mitigate our commodity price exposure. While we cannot predict when the CFTC will issue final rules applicable to position limits or capital requirements, it may require time and effort for us to comply with position limits and with certain clearing and trade-execution requirements in connection with our derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our counterparties to post additional capital, which could increase the costs of future derivatives. In addition, other provisions of the Dodd-Frank Act could cause current counterparties to restructure their derivative activities, including the potential that they might cease engaging in the business of commodity derivatives.

If we voluntarily or involuntarily reduce our use of derivative contracts as a result of the new requirements, we become more exposed to commodity price fluctuations, which could adversely affect our ability to conduct our operations.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our upstream operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and gas we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil and gas, and incur costs to comply with such federal, state and local laws and regulations.

Under the Natural Gas Act (“NGA”), the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation and sale for resale of gas, as well as the construction and operation of interstate gas pipelines. As a general matter, states regulate the intrastate transportation, local distribution and retail sale of gas under state laws and regulations.

Under the Interstate Commerce Act (“ICA”), FERC also regulates the rates and practices of oil pipeline companies engaged in interstate transportation, establishes equal service conditions to provide shippers with equal access to oil pipeline transportation, and establishes reasonable rates for transporting petroleum and petroleum products by pipeline. 

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The U.S. Congress, FERC, state legislatures and regulatory commissions and courts often consider legislative and regulatory proposals and proceedings that could affect the gas and oil industry. The industry historically has been heavily regulated and we cannot predict future legislative and regulatory proposals and proceedings or what effect such proposals or proceedings may have on our operations. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenue, our financial condition would be adversely affected.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and gas. The impact of the changing demand for oil and gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Should we fail to comply with all applicable statutes, rules, regulations and orders administered by the CFTC or FERC, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005 (“EPAct”), FERC has civil penalty authority under the NGA, including the ability to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation of the NGA or FERC’s regulations under the NGA. While neither we nor our subsidiaries have been regulated by FERC as “natural gas companies” under the NGA, as a customer of gas transportation service, we also must comply with the terms and conditions of FERC-jurisdictional tariffs pursuant to which transportation service is provided and the anti-market manipulation rules enforced by FERC under the NGA. If we fail to comply with all the applicable FERC-administered statues, rules, regulations and orders, we could be subject to substantial penalties. FERC also has the power to order disgorgement of profits from transactions deemed to violate the NGA.

Under the Commodity Exchange Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, FERC, or the CFTC from time to time. Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability.

Climate change legislation or other regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and gas we produce.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and may continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of 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 under the CAA that, among other things, establish 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 NSPS rule, known as Subpart OOOOa, that requires certain new, modified or reconstructed facilities in the oil and gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices. On September 11, 2018, however, the EPA proposed changes to the August 2016 final NSPS rule applicable to oil and gas well vapor leaks. These changes, if implemented, would ease compliance obligations by decreasing fugitive emission monitoring frequency requirements, allowing more time for repairs, and allowing compliance with certain state regulations in lieu of complying with federal regulations. Moreover, on March 2, 2017 the EPA withdrew a previously issued Information Collection Request that sought information about methane emissions from facilities and operations in the oil and gas industry.

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In December 2015, the United States attended the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. At the Conference, an agreement was prepared that requires member countries to determine, plan, and regularly report on their contribution to the mitigation of global warming. Under the agreement, GHG emission reduction goals are established every five years beginning in 2020. The agreement does not create any binding obligations for countries to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement, if it chooses to do so, are unclear at this time.

The adoption and implementation of any international treaty, or federal or state legislation, regulations or other regulatory initiative that imposes a carbon tax, requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, that could have an adverse effect on our business, financial condition and results of operations. Moreover, any such new treaty, legislation, regulation or initiative could increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas we produce and lower the value of our reserves.

Finally, it should be noted that some sources estimate that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such effects were to occur, our development and production operations could be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities, less efficient or non-routine operating practices necessitated by such climate effects, or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations. Nor, are we (on our own) capable of doing this in a prudent and accurate manner that would best serve our investors’ interests.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could increase our costs of doing business, impose additional operating restrictions or delays and adversely affect our production.

Hydraulic fracturing is an essential and common practice we use to develop our reserves. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation to fracture the surrounding rock and stimulate production. We routinely apply hydraulic fracturing techniques to stimulate production from the wells we drill.

Our hydraulic fracturing technique is currently generally exempt from regulation under the SDWA’s Underground Injection Control (“UIC”) program and is typically regulated by the Oklahoma Corporation Commission. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the 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 to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, the EPA asserted regulatory authority pursuant to the UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Also, in 2015, the Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. On December 29, 2017, BLM rescinded the 2015 rule. California and certain environmental groups have sued over the BLM’s rescission of the 2015 rule.

Additionally, in 2014, the EPA published an advanced notice of public rulemaking regarding Toxic Substances Control Act (“TSCA”) reporting of the chemical substances and mixture used in hydraulic fracturing. From time to time, Congress has

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introduced, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of chemicals used in the fracturing process.

In addition, some states, including Oklahoma, have adopted, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Concerns have been raised that hydraulic fracturing activities may be correlated to anomalous seismic events. In December 2016, the OCC Oil and Gas Conservation Division and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. States could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, although Oklahoma has taken steps to limit the authority of local governments to regulate oil and gas development. The issuance of any laws, regulations or other regulatory initiatives that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to develop our reserves or conduct our operations, either one of which could have a material adverse effect on us.

Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of produced water gathered from our drilling and production activities, which could have a material adverse effect on our business.

We dispose of produced water gathered from our operations pursuant to permits issued to our affiliates or third-party vendors by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent permitting or operating constraints or new monitoring and reporting requirements owing to, among other things, concerns of the public or governmental authorities regarding such disposal activities.

One such concern relates to recent seismic events near underground injection wells used for the disposal of produced water resulting from oil and gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, where we operate. In response to these concerns regarding induced seismicity, regulators in some states, including Oklahoma, have imposed, and other states are considering imposing, additional requirements in the permitting of produced water injection 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 injection wells in proximity to faults and also, from time to time, developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend injection well operations. The Oklahoma Corporation Commission (“OCC”) has implemented the National Academy of Science’s “traffic light system,” in determining whether new injection wells should be permitted, permitted only with special restrictions, or not permitted at all. In addition, the OCC has established rules requiring operators of certain produced water injection wells in seismically-active areas, or Areas of Interest, within the Arbuckle formation of the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for injection wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal operations in an attempt to mitigate the occurrence of such incidents. In February 2017, the OCC’s Oil and Gas Conservation District issued an order limiting future increases in the volume of oil and gas wastewater injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state.

Also, ongoing lawsuits allege that injection well disposal operations have caused damage to neighboring properties or otherwise violated state and federal rules governing waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and gas activities utilizing injection wells for produced water disposal. Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of produced water into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where produced water injection activities occur or are proposed to be performed. Court decisions or the adoption of any new laws, regulations or directives that restrict our ability to dispose of produced water generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of produced water disposed in such wells, restricting injection

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well locations or otherwise or by requiring us to shut down injection wells, could significantly increase our costs to manage and dispose of this produced water, which could have a material adverse effect on our financial condition and results of operations.

Laws and regulations pertaining to threatened and endangered species or protective of environmentally sensitive areas could delay or restrict our operations and cause us to incur significant costs.

Our operations may be adversely affected by seasonal or permanent restrictions or costly mitigation measures imposed under various federal and state statutes in order to protect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. Federal statutes, as amended from time to time, that are protective of these species, birds and environmentally sensitive areas include the ESA, the Migratory Bird Treaty Act (the “MBTA”), the CWA, the CERCLA and the OPA. For example, to the extent that species are listed under the ESA or similar state laws and live in areas where our oil and gas upstream activities are conducted, our ability to conduct or expand operations and construct facilities could be limited or we could be forced to incur material additional costs. Moreover, our operations may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

Additionally, the U.S. Fish and Wildlife Service (“FWS”) may designate new or increased critical habitat areas that it believes are necessary for survival of threatened or endangered species, which designation could result in material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. As a result of one or more settlements approved by the federal government, the FWS must make determinations on the listing of numerous specified species as endangered or threatened under the ESA pursuant to specified timelines. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. If harm to protected species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties. The designation of previously unprotected species as threatened or endangered in areas where we conduct operations could cause us to incur increased costs arising from species protection measures or time delays or limitations on our operations.

We could experience periods of higher costs if oil and gas prices rise or as drilling activity otherwise increases in the STACK, which could reduce our ability to develop our reserves and otherwise have a material adverse effect on us.

Historically, our capital and operating costs typically rise during periods of sustained increasing oil, gas and NGL prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor, especially those required in horizontal drilling and completion. As commodity prices rise or drilling activity otherwise increases in the STACK, our costs for materials, services and labor may increase, which may negatively impact our profitability, cash flow and cause us to delay, reduce or curtail our drilling program.

The sale of our production is dependent upon midstream and downstream facilities over which we may have no control.

The marketability of our production depends upon the availability, proximity and capacity of facilities and services, including pipelines, natural gas gathering systems, trucking or terminal facilities and processing facilities. We deliver oil, gas and NGLs through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could impact us by causing our production to be shut-in, reducing the price we receive for our production or delaying or eliminating our future development plans. Although we have some contractual control over this risk by virtue of the underlying contracts, such systems and facilities may be temporarily unavailable due to market conditions or operational reasons. Further, in the future, they may not be available to us at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these systems and facilities, as well as any delays in constructing new systems and facilities, could have a material adverse effect on us.

We rely primarily on KFM for gathering, transportation, processing and produced water disposal services.

Our operated production, not otherwise previously dedicated, is dedicated to KFM, an entity under common control by our parent. In November 2018, we sold our produced water assets to a subsidiary of KFM. In conjunction with the sale, we entered into a new 15-year water gathering and disposal agreement with such subsidiary. As a result, we are substantially dependent upon KFM for our operations. If KFM were unable to continue to provide these services, it could result in the shut-in of our

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production or cause delays and additional costs to find alternate providers for those services, any one of which could have a material adverse effect on us.

The parties on whom we rely for gathering, transportation and processing services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

Gathering, transportation and processing operations are subject to complex laws and regulations that require parties providing these services to obtain and maintain numerous permits, approvals and certifications with various levels of government. These operations could require substantial costs in order to comply with existing laws and regulations. If laws and regulations governing such operations are enacted, revised or reinterpreted, these changes may affect the costs that we pay for such services. There could be a material adverse effect on us if the gathering, transportation and processing operations that we rely upon were materially impacted by those laws and regulations.

We have limited control over activities on properties we do not operate, which could reduce our production and revenue.

We have limited control over properties that we do not operate, including a limited ability to influence normal operating procedures, expenditures or future development of the underlying properties. The failure of another operator to adequately perform operations or that operator’s financial difficulties could reduce our production and revenue. The success and timing of our drilling and development activities on properties operated by others, depends upon a number of factors outside of our control, including the operator’s timing of development and amount of capital expenditures, expertise and financial resources.

Turnover of our key executives and Board of Directors and difficulty of recruiting and retaining key employees could have a material adverse impact on our business.

We experienced a significant amount of executive-level turnover in late 2018. We recently introduced a new executive team including an Interim President, an Interim Chief Operating Officer - Upstream and a Chief Financial Officer. There is risk associated with effectively managing this or any other management transition. Our inability to retain the new management team and our remaining key executives and employees could harm our business and operations and have a material adverse effect on us.

Our success will depend to a large extent upon the efforts and abilities of our management team and having experienced individuals serving on our Board of Directors who are also knowledgeable about our operations and our industry. If we are unable to retain or find replacement employees, the loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintain key-man life insurance with respect to any of our employees. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. We also may be unable to timely replace the talents and skills of our Directors if one or more did not continue serving. These factors could cause us to incur greater costs or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.

We operate in an area of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

Oil and gas development in the STACK has been quite active in recent years. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years and may increase in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to conduct our planned development activities could result in our production falling below our forecasted volumes, which could have a material adverse effect on us at our estimated production levels in the next several years.

We may encounter obstacles marketing our oil and gas, which could adversely impact our revenue.

The marketability of our production will depend in part upon the availability of purchasers in our area plus gathering systems and pipelines owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities, but since we hold firm transportation covering our gas production we do not believe a significant risk exists that other companies would hold priority over us.

The availability of markets is beyond our control. If market factors dramatically change, our revenue could be substantially impacted, which could have a material adverse effect on us.

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We have identified material weakness in our internal control over financial reporting which, if not corrected, could affect the reliability of our financial statements, increase our costs and efforts to ensure accurate reporting and have other adverse consequences.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (ICFR). Section 404 of SOX requires management to assess the effectiveness of our ICFR. Based on our assessment as of December 31, 2018, we concluded that our ICFR was not effective as of that date, due to identification of material weakness. A material weakness is a deficiency or combination of deficiencies in ICFR that causes a reasonable possibility that a material misstatement could occur and not be prevented or detected on a timely basis. Our material weakness relates to both the design of our controls and execution of control procedures. Item 9A contains additional information regarding our deficiencies and the proposed remediation plan.

If not remediated, the material weaknesses could result in a material misstatement to our annual or interim consolidated financial statements that would not be prevented or detected on a timely basis. Our management has developed, and begun to implement, a plan to remediate the material weaknesses. We may not be able to implement the plan, or to remediate the material weaknesses in a timely manner. In addition, we may require more than one year to effect a system of internal controls and an information technology environment that are sufficiently designed and properly executed to prevent material misstatements from going undetected. Furthermore, during the course of re-designing existing processes and controls, implementing additional processes and controls and testing of the operating effectiveness of such re-designed and additional processes and controls, we may identify additional control deficiencies that could give rise to other material weakness, in addition to the currently identified matters. If we are unable to remediate our material weakness, or if additional material weakness or deficiency is discovered, we may be unable to report our financial results accurately or timely, which could cause our reported financial results to be materially misstated, which could adversely affect the market price of our securities and our ability to access the capital markets. Furthermore, the effort to remediate our internal controls could be expensive or could distract management from managing the business, either of which could adversely affect us.

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.

We do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the resource constraints and the benefit of controls relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations reflect that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations. 

Cyber-attacks targeting systems and infrastructure may adversely impact our operations.

Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and for compliance reporting. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as power generation and transmission, communications and oil and gas pipelines.

We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The technologies needed to conduct oil and gas exploration and development activities and global competition for oil and gas resources make certain information the target of theft or misappropriation.

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As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also have increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations.

Our systems and networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of information, or cause other disruptions to our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:

• unauthorized access to seismic data, reserves information, royalty owner data or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

• data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

• data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;

• a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt a development project, effectively delaying the start of cash flows from the project;

• a cyber-attack on a third party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenue;

• a cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenue;

• a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenue;

• a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

• expensive remediation efforts, distraction of management or damage to our reputation.

Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.  

Certain U.S. federal income tax preferences could be eliminated as a result of future legislation.

There has been proposed legislation that would, if enacted, make significant changes to U.S. tax laws regarding provisions currently available to oil and gas companies. Such legislative changes have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas upstream. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in our industry. These changes include:

• the repeal of the percentage depletion allowance;

• the elimination of current deductions for intangible drilling costs; and

• the increase in the amortization period from two years to seven years for geophysical costs.

It is unclear whether any such changes will be enacted or proposed by current or future administrations or how soon any such changes would become effective. In addition, Congress passed tax reform in December of 2017, and that legislation has changes including, but not limited to:

• the elimination of the deduction for U.S. production activities;

• the provision for individual taxpayers to deduct 20% of their domestic qualified business income (which may provide some relief from the aforementioned item);

• more stringent limitation on business interest deduction;

• modification of NOL carryforward rules; and

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• changes to items excluded from the $1.0 million executive compensation deduction limitation.

The further passage of any legislation, including the proposals above, or changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

Risks Related to Our Indebtedness

We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

Our present level of indebtedness requires us to use a substantial portion of our cash flow to pay interest, which reduces funds available to finance our capital and acquisition activities and could limit our flexibility in reacting to changes in our business. The outstanding debt under the Alta Mesa RBL bears interest at a variable rate, and so a rise in interest rates will generate greater interest expense (provided we have not hedged against interest rate increases). The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

We may incur substantially more debt in the future. The indenture governing our outstanding 2024 Notes contains restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness and remain in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute “indebtedness” as defined under the indenture.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If cash flow is not sufficient to service debt, we may be required to refinance debt, sell assets or sell additional securities on terms that we may not find attractive if it may be done at all. Further, the failure to comply with the financial and other restrictive covenants relating to the indebtedness could result in a default under that indebtedness, which could have a material adverse affect on us.

Our significant indebtedness could give rise to other material adverse consequences, including the following:

• the Alta Mesa RBL and the indenture governing the 2024 notes have cross default provisions, which could result in the acceleration of indebtedness under both agreements if we fail to comply with the covenants and other provisions in either agreement;

• it may be difficult to satisfy our obligations, including debt service requirements under debt agreements, or maintain compliance with financial and other debt covenants;

• the ability to obtain additional financing for working capital, capital expenditures, debt service requirements and other general corporate purposes may be impaired;

• a significant portion of our cash flow is committed to payments on our debt, which will reduce the funds available to us for other purposes, such as future capital expenditures, acquisitions and general working capital;

• we are more vulnerable to price fluctuations and to economic downturns and adverse industry conditions and our flexibility to plan for, or react to, changes in our business or industry is more limited; and

• our ability to capitalize on business opportunities and to react to competitive pressures may be limited.

The Alta Mesa RBL and the indenture governing our 2024 Notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities.

The Alta Mesa RBL and the indenture governing our 2024 Notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in activities that may be in our long-term best interests. These covenants, among other things, limit our ability to:

• incur additional indebtedness;

• sell assets;

• guaranty or make loans to others;

• make investments;

• enter into mergers;

• make certain payments and distributions;

• enter into or be party to hedge agreements;

• amend our organizational documents;

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• incur liens; and

• engage in certain other transactions without the prior consent of our lenders.

In addition, the Alta Mesa RBL requires us to maintain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios, which may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of these limitations.

Any significant reduction to the Alta Mesa RBL borrowing base as a result of the periodic redeterminations or other reasons may negatively impact our ability to fund our operations and we may not have sufficient funds to repay borrowings under the Alta Mesa RBL, if required as a result of a borrowing base redetermination.

Availability under the Alta Mesa RBL was subject to a borrowing base of $400.0 million at December 31, 2018. The borrowing base is subject to at least semi-annual borrowing base redeterminations which is based on the value of our oil and gas reserves as determined by the Alta Mesa RBL lenders and other factors deemed relevant by our lenders. On April 1, 2019, the borrowing base was reduced to $370.0 million upon completion of the regularly scheduled semi-annual redetermination. Declines in oil and gas prices or a decrease in reserves for any reason, including the removal of our PUDs in April 2019, could cause the Alta Mesa RBL banks to further reduce the borrowing base. Any significant future reduction in our borrowing base could have a material negative impact on our liquidity and our ability to fund our operations. Further, if the outstanding borrowings under the Alta Mesa RBL were to exceed the borrowing base due to any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may be in default under the Alta Mesa RBL, which could have a material adverse effect on us.

If we are unable to comply with the restrictions and covenants in our debt agreements, we could default under the terms of such agreements, which could ultimately result in an acceleration of repayment.

If we cannot comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of these agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond our control. As a result, we cannot provide assurance that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. We are currently in default under the Alta Mesa RBL for our failure to provide certain information by May 15, 2019 for the fiscal quarter ended March 31, 2019. Although certain types of circumstances (such as delays in providing timely financial information) give rise to defaults that are curable under the agreements, we may not be able to cure all defaults within the cure period, which could give rise to an event of default and potentially an acceleration of amounts due. Moreover, if we are in default on any indebtedness, we would be unable to make borrowings under the Alta Mesa RBL even if there are remaining borrowings available thereunder.

If we are unable to generate sufficient cash flow or are otherwise unable meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants in the instruments governing our indebtedness, we could be in default under those agreements. During 2019, we may be unable to satisfy the consolidated total leverage ratio and recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, the lenders under the Alta Mesa RBL could terminate their commitments to lend, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy protection. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our debt agreements or obtain needed waivers on satisfactory terms.

To service our indebtedness, we require significant liquidity and our ability to generate cash depends on many factors beyond our control.

Our ability to service and refinance our debt and to fund planned capital expenditures depends on our generating cash. This ability hinges on general economic, financial, competitive, legislative, regulatory and other factors beyond our control. We can provide no assurance that we will generate sufficient operating cash flow, that we will realize the planned operating cost improvements or that future borrowings will be available to us in an amount sufficient to service and repay our debt, while still

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funding our other liquidity needs. If we are unable to satisfy our debt obligations, we may have to undertake alternative plans such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments; or

• seeking to raise additional capital.

Any alternative plans that we undertake may still not enable us to meet our debt obligations. We can provide no assurance that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and proceeds realized from those sales would be favorable or that additional financing could be obtained on acceptable terms. Our inability to generate sufficient cash flows to satisfy our debt or to obtain alternative financing could have a material adverse effect on us and could result in us being unable to continue as a going concern.

If High Mesa Inc. and its subsidiaries (collectively, “HMI”) default on their obligations to us, it could have a material adverse effect on us and our results of operations, and could cause a default under the Alta Mesa RBL and could adversely impact the trading price for our securities.

High Mesa Services LLC (“HMS”), a subsidiary of HMI, is the promissor under two promissory notes in the principal amount of $1.5 million and $8.5 million. As of December 31, 2018, approximately $1.7 million and $11.7 million, respectively, were outstanding under the promissory notes including the accumulated interest cost. The promissory notes became the property of AMR pursuant to the identification of acquired assets under the Business Combination. When the $1.5 million promissory note became due on February 28, 2019, HMS made no payment and therefore defaulted under its terms, and HMS has failed to cure such default. Following the default, we submitted a demand letter to preserve our rights, declaring all amounts owing under the $1.5 million note immediately due and payable. HMI disputes that it has any obligation to pay the $1.5 million promissory note and the $8.5 million promissory note to us. We intend to pursue all available remedies in connection with securing repayment of the past due promissory note by HMS and the $8.5 million promissory note, which matures on December 31, 2019, but there is no guarantee that we will be successful in securing such repayment in full, or in part, or that HMI will have the liquidity necessary to repay the notes.

Pursuant to 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 “MSA”) with HMI whereby we agreed to provide management services to HMI with respect to the non-STACK oil and gas assets, which included both operational and administrative functions. At December 31, 2018, HMI owed us approximately $10.0 million, which includes amounts owed (i) under the MSA, (ii) from a duplicate revenue payment made to HMI and (iii) pursuant to payables arising prior to the Business Combination. Subsequent to year-end, we billed HMI $0.9 million for incremental MSA costs incurred and have received approximately $1.0 million in payments. HMI has disputed certain of these amounts. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result, we have recognized an allowance for uncollectible accounts of $9.0 million to fully provide for the unremitted balance and may have future allowances for amounts incurred in 2019 prior to the termination of the MSA. We also may be subject to liabilities for the non-STACK assets for which we should be indemnified, including liabilities associated with litigation relating to the non-STACK assets.

Under the Alta Mesa RBL, Investments (as defined) are limited to $10.0 million. If the amounts due from HMI continue unpaid, they may be deemed Investments, which when aggregated with other Investments could cause Alta Mesa to be in default of the Alta Mesa RBL. Such default would require us to get a waiver or other relief from our lenders. If we are unable to get such relief, the lenders may exercise their rights under the agreement, which as described elsewhere in our Risk Factors, could include acceleration of amounts due.  A failure by HMI to pay its obligations to us could also have an adverse impact on our financial position and results of operations. Alternatively, if HMI, which holds an estimated 134.0 million shares of our Class C Common Stock, sells all or a portion of those shares to fulfill its obligations under the MSA, the trading price of our shares may be negatively affected.

Additionally, we are co-guarantors under certain surety bonds with HMI, including bonds that cover the non-STACK oil and gas assets owned by them. The surety has requested posting of collateral. If HMI cannot post collateral or satisfy its indemnity

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obligations, Alta Mesa may be required post collateral or otherwise satisfy HMI’s obligations associated with HMI surety bonds.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Overview

As of December 31, 2018, we have assembled a highly contiguous position of approximately 140,000 net acres in the up-dip, naturally-fractured oil portion of the STACK, primarily in eastern Kingfisher and south-eastern Major Counties in, Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. This position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet.

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At December 31, 2018, we had a 66% average working interest in 786 gross producing wells. At December 31, 2018, we had six horizontal drilling rigs operating in the STACK, but by late February 2019, we had no rigs operating. We restarted our development program in March 2019 and expect to use 2-3 rigs for the remainder of 2019 as we focus on the optimal completion design, well pattern and lowering well costs.

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 establishes a development plan of 60 wells in three tranches, and provides opportunities for the parties to potentially agree to an additional 20 wells. As of December 31, 2018, 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. We are responsible for any drilling and completion costs exceeding approved amounts. In exchange for BCE carrying the drilling and completion costs, they receive 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 Successor Period, we brought 25 horizontal wells on production that were funded through the JDA. At December 31, 2018, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA.

Our Oil and Gas Reserves

Our proved reserves and production profile as of December 31, 2018 was as follows:

Total Estimated Proved Reserves (MMBoe)	Percent Proved Developed (1)		Liquids as a Percentage of Total Proved Reserves (1)		PV-10 ($ in millions) (2)	Net Acreage (3)	Net Producing Wells (4)	Average 2018 Daily Net Production (MBoe/d) (5)
69.1	100	%	65	%	812.9	140,400	517.9	31.1

_________________

(1) Computed as a percentage of total proved reserves. Based on our April 2019 assessment of our ability to continue as a going concern and our expected inability to fund development costs, we removed a total of 89,073 MBoe of PUDs as of December 31, 2018.

(2) PV-10 was calculated using an unweighted arithmetic average of oil and gas prices as of the first day of each of the twelve months ended December 31, 2018, as established by the SEC. Because Alta Mesa is a partnership and, as such, is not subject to income taxes, our PV-10 is the same as our standardized measure of future net cash flows, the most comparable measure under U.S. GAAP, which is reduced for the discounted value of estimated future income taxes. Calculation of PV-10 does not give effect to derivatives or hedging transactions.

(3) Includes developed and undeveloped acreage.

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

(5) Average daily net production for the Successor Period.

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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. The information presented during the Predecessor Periods includes amounts related to discontinued operations.

Oil and NGLS (Mbbls)
	Successor		Predecessor
	December 31, 2018		February 8, 2018		December 31, 2017		December 31, 2016
Proved Reserves (1)
Developed	45,064		30,693		32,527		24,809
Undeveloped	—		77,256		77,878		61,280
Total	45,064		107,949		110,405		86,089
Average market prices (per bbl) - oil(2)	$	65.56	$	52.89	$	51.34	$	42.75
Average realized prices (per bbl) - NGLs(2)	$	22.44	$	27.48	$	26.06	$	15.18

Natural Gas (MMcf)
	Successor		Predecessor
	December 31, 2018		February 8, 2018		December 31, 2017		December 31, 2016
Proved Reserves (1)
Developed	144,148		126,231		150,183		93,361
Undeveloped	—		284,571		283,336		222,644
Total	144,148		410,802		433,519		316,005
Average market prices (per MMBtu) - natural gas(2)	$	3.10	$	2.99	$	2.98	$	2.49

Total (MBoe)
	Successor	Predecessor
	December 31, 2018	February 8, 2018	December 31, 2017	December 31, 2016
Proved Reserves (1)
Developed	69,089	51,731	57,557	40,371
Undeveloped	—	124,685	125,101	98,386
Total	69,089	176,416	182,658	138,757

_________________

(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. Sustained lower prices may result in the estimated quantities and present values of our reserves being reduced and may necessitate future impairments of our capitalized costs.

(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

The information presented during the Predecessor Periods includes amounts related to discontinued operations. Changes in our proved undeveloped reserves were (in MBoe):

	Successor		Predecessor
	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Beginning of period	124,685		125,101		98,386		44,624
Converted into proved developed reserves	(18,999	)	—		(4,083	)	(1,509	)
Extensions and discoveries	43,354		—		32,972		51,306
Reserves acquired	3,738		—		1,846		—
Reserves sold/distributed(1)	—		(1,129	)	(746	)	—
Revisions(2)	(152,778	)	713		(3,274	)	3,965
End of period	—		124,685		125,101		98,386
Percentage of total proved reserves	—	%	71	%	68	%	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 consolidated 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 have removed all of our PUDs from our total estimated proved reserves.

During the Successor Period, we incurred approximately $160.6 million in expenditures to develop PUD reserves. 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. The identification and development of PUDs in the future is dependent on future commodity prices, costs, capital availability and other economic assumptions. During January 2019, we finalized our development plan for the next five years and received an audit report from our outside engineers that agreed with our recognition of PUDs for the majority of that future development. During April 2019, in finalizing our financial reporting for 2018, we determined that we may fail to satisfy the leverage covenant under the Alta Mesa RBL during 2019. Accordingly, we were unable to conclude that we would have continuing access to that capital source in the event of a failure of the leverage covenant. Thus, we concluded that we did not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our future drilling locations and did not recognize any proved undeveloped locations in our final December 31, 2018 reserve report. Should our ability to fund the required development costs improve in the future, we expect to recognize all or a portion of those resources as proved.

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 Development 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 Corporate 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:

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• 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 all new proved undeveloped reserves additions.

Ryder Scott Company, LP (“Ryder Scott”), a third-party petroleum engineering consulting firm, audited approximately 96% of our 2018 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 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 22 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 1.

Drilling and Other Exploratory and Development Activities

	Successor	Predecessor
	February 9, 2018 Through December 31, 2018	January 1, 2018 Through February 8, 2018	Year Ended December 31, 2017	Year Ended December 31, 2016
Development wells (net):
Productive	123.8	7.0	59.0	29.9
Dry	—	—	—	—
Total development wells	123.8	7.0	59.0	29.9
Exploratory wells (net):
Productive	—	—	0.1	3.0
Dry	1.0	—	—	—
Total exploratory wells	1.0	—	0.1	3.0

Activities at Year End

At December 31, 2018, we were in process of drilling 32 gross (26 net) wells.

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Delivery Commitments

Information about our firm transportation commitments is included in Part II, Item 7.

Productive Wells, Developed and Undeveloped Acreage

The following sets forth information with respect to our wells and acreage under lease as of December 31, 2018, all of which is located in the United States:

	December 31, 2018
	Gross	Net
Number of productive wells principally targeting (1):
Oil	760	502.6
Gas	26	15.3
Total wells	786	517.9
Properties:
Developed acres	166,955	112,088
Undeveloped acres	53,741	28,314
Total acres	220,696	140,402
Undeveloped acreage expirations (2):
Year ending December 31, 2019	13,942	7,213
Year ending December 31, 2020	14,183	5,636
Year ending December 31, 2021	12,778	6,493
Total	40,903	19,342

_________________

(1) Productive wells are producing wells and those wells we deem capable of production. 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. As of December 31, 2018, the majority of our undeveloped acreage subject to expiry does not have associated proved reserves. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests.

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. The interests owned by us may be subject to one or more royalty, overriding royalty net profits interests, liens and taxes or other outstanding interests (including disputes related to such interests) customary in the industry.

Item 3. Legal Proceedings

We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters.

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Litigation

On January 30, 2019, AMR, James T. Hackett, AMR’s interim Chief Executive Officer and Chairman of the Board, certain of AMR’s former and current directors, Thomas J. Walker, AMR’s 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.

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 and Michael A. McCabe, AMR’s former President and Chief Executive Officer and Chief Financial Officer, respectively. These complaints are 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 AMR and certain of its current and former officers on behalf of all persons or entities who purchased or otherwise acquired Silver Run or AMR securities between March 24, 2017, and February 25, 2019. The new claims are based upon alleged misstatements contained in AMR’s proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants.

The outcome of the above securities class action complaints is uncertain, and while we believe that AMR has 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. We are not a party to these suits but an adverse outcome could potentially impact our business.

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.

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 (a subsidiary of HMI), us, 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, we stipulated with respect to Biloxi that we 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 we distributed to a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Consequently, we believe that any potential damages incurred by us 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 us or Meridian. In addition, our ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI. 

SEC Investigation

The SEC is conducting a formal investigation into, among other things, the facts involved in the material weakness in our internal controls over financial reporting and the impairment charge disclosed previously and in this annual report. 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.

Environmental Claims

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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 in our consolidated financial statements at December 31, 2018.

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

No class of our limited partnership interests has been registered under the Exchange Act of 1934, as amended (the “Exchange Act”), and there is no established public trading market for our equity.

As of May 17, 2019, SRII Opco LP and AMH GP held 100% of such interests.

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Distributions to our partners are determined by the terms of our partnership agreement.  As of December 31, 2018, the covenants of the Company’s senior secured revolving credit facility prohibit us from making any distributions.

Item 6. Selected Financial Data

The following information has been derived from our audited consolidated financial statements.

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	Successor			Predecessor
	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31,
(in thousands)							2017(1)			2016(1)			2015(1)			2014(1)
Statement of Operations Data:
Total operating revenue	$	409,011		$	47,639		$	279,369		$	101,899		$	325,363		$	213,907
Operating income (2)	(2,040,088		)	(1,777		)	36,670			(57,337		)	162,697			80,949
Income (loss) from continuing operations	(2,076,374		)	(7,116		)	(12,846		)	(134,279		)	101,584			25,197
Income (loss) from discontinued operations, net of tax (3)	—			(7,746		)	(64,815		)	(33,642		)	(233,377		)	74,179
Net income (loss)	(2,076,374		)	(14,862		)	(77,661		)	(167,921		)	(131,793		)	99,200
Balance Sheet Data (at December 31):
Cash and cash equivalents	$	12,984		$	9,070		$	3,721		$	7,185		$	8,869		$	1,349
Total assets (4)	935,719			1,094,685			1,085,397			813,851			722,525			911,125
Total debt, including Founder Notes (5)	690,123			624,558			635,606			556,862			743,523			785,682
Total partners’ capital (deficit)	16,793			183,065			154,445			32,106			(177,049		)	(61,446		)

_________________

(1) Our statement of operations information for prior years has been adjusted to reflect the disposal of non-STACK oil and gas assets as discontinued operations. 

(2) The Successor Period includes total impairment charges of $2.0 billion for oil and gas properties. Additionally, impairment charges on oil and gas properties of $1.2 million, $0.4 million and $18.8 million were recognized during 2017, 2016 and 2015, respectively.

(3) For the period January 1, 2018 to February 8, 2018 and 2017, 2016, 2015, and 2014 income (loss) from discontinued operations, net of tax, includes $0.9million, $24.5million, $41.3 million, $82.7 million, and $112.7 million, respectively, of depreciation, depletion and amortization expense.  For the period January 1, 2018 to February 8, 2018 and for 2017, 2016, 2015 and 2014, income (loss) from discontinued operations, net of tax, includes impairment charges on oil and gas properties of $5.6 million, $29.1 million, $15.9 million, $158.0 million and $74.9 million, respectively. Additionally, income (loss) from discontinued operations, net of tax, for 2014 includes an $87.5 million gain on the sale of oil and gas properties.

(4) Total assets include $49.0 million, $156.7 million, $203.3 million, and $499.9 million as of December 31, 2017, 2016, 2015, and 2014, respectively, related to non-STACK assets.

(5) Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) which, at the Business Combination, were converted into an equity interest in the AM Contributor.  The balance of the Founder Notes at the time of conversion was approximately $28.3 million, including accrued interest.

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 “Selected Financial Data” and the consolidated financial statements and related notes included elsewhere in this report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

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We are an independent exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County (“STACK”). We generate revenue principally by the production and sale of oil, natural gas and NGLs. We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners.

As of December 31, 2018, we have assembled a highly contiguous position of approximately 140,000 net acres in the up-dip, naturally-fractured oil portion of the STACK primarily in eastern Kingfisher and south-eastern Major Counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. When we consider acquiring acreage within or adjacent to our acreage footprint, we prioritize opportunities where we can be the operator. At December 31, 2018, we had six horizontal drilling rigs operating in the STACK, but by late February 2019, we had no rigs operating. We restarted our development program in March 2019 and expect to use 2-3 rigs for the remainder of 2019 as we focus on the optimal completion design, well pattern and lowering well costs.

Additional information relating to the formation of Alta Mesa Resources and the acquisition of us and KFM on February 9, 2018, may be found in Item 8. Immediately prior to the Business Combination, we distributed our non-STACK oil and gas assets and related liabilities to High Mesa Holdings, LP (the “AM Contributor”). 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”) and the period after the Business Combination (“Successor”). The Company’s financial statement presentation reflects Alta Mesa as the “Predecessor” for periods prior to February 9, 2018. The Company’s financial statement presentation reflects Alta Mesa as the “Successor” for periods since February 9, 2018.

Outlook, Market Conditions and Commodity Prices

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

Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and it is uncertain whether the increase in market prices experienced in recent months will be sustained.  As a result, we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues.  In the event that oil, gas and NGLs prices significantly decrease, such decreases could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of the borrowing capacity under the Alta Mesa RBL.  The following table sets forth the historical average New York Mercantile Exchange spot prices:

	Years Ended December 31,
	2018		2017		2016
Average NYMEX daily prices:
Oil (per bbl)	$	64.75	$	50.80	$	43.40
Natural gas (per MMBtu)	$	3.07	$	3.02	$	2.55

Going concern

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Our present level of indebtedness and the current commodity price environment present challenges to our ability to comply with the covenants in the agreements governing our indebtedness. As a result of the recent decrease in our forecasted production levels, increased operating costs, and pressures created by lower commodity prices, in the absence of one or more deleveraging transactions, we do not anticipate maintaining compliance with the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of June 30, 2019. Our parent’s board of directors and its financial advisors are evaluating the available financial alternatives, including, without limitation, seeking amendments or waivers to the covenants or other provisions of our indebtedness, raising new capital from the private or public markets or taking other actions to address our capital structure. If we are unable to reach an agreement with our lenders or find acceptable alternative financing, it may lead to an event of default under the Alta Mesa RBL. If following an event of default, the Alta Mesa RBL lenders were to accelerate repayment, it may result in an event of default and an acceleration under the 2024 Notes. We have concluded that these circumstances create substantial doubt regarding our ability to continue as a going concern. For a more detailed discussion, please read “Item 1A. Risk Factors.”

Derivatives

The objective of our hedging program is to produce, over time, relative revenue stability. However, in the short-term, both settlements and fair value changes in our derivatives can significantly impact our results of operations, and we expect these gains and losses to continue to reflect the impact of changes in oil and gas prices. Our derivatives are reported at fair value and are sensitive to changes in the price of oil and gas. Changes in derivatives are reported as gain (loss) on derivatives, which include both the unrealized increase and decrease in their fair value, as well as the effect of realized settlements during the period. For the Successor Period, we recognized a net loss on our derivatives of $10.2 million, which includes $39.0 million in cash settlements paid for derivatives. Our Alta Mesa RBL generally has minimum and maximum hedging limits as further described elsewhere.

Impairments

In late fourth quarter of 2018, the combination of depressed prevailing oil and gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations resulted in impairment charges of $2.0 billion to our proved and unproved oil and gas properties.  Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place. At the time of the Business Combination, we believed that the stratigraphy underlying our acreage was conducive to development of three distinct benches within the broader Mississippian section. Proved reserve assumptions at the time of the Business Combination were based on initial wells drilled in the STACK, stated expectations from other operators in the STACK as well as analogous results from other resource plays. These proved reserve assumptions included spacing of four wells per section and probable and possible resource assumptions included an incremental three wells per section for a total of seven wells per section. An incremental five wells per section (for a total of 12 wells per section) were classified as contingent resources to which no value was assigned in the purchase price allocation for the Business Combination. We expected all proved and unproved wells to deliver similar results of approximately 250 Mbbl of reserve recovery. Our 2018 drilling program was executed under these assumptions and by early 2019, we had 17 different sectional development patterns with six to ten wells per section and meaningful production results.  The pattern wells generally produced as expected for the initial 60 days but began to fall below type curve after 90-120 days, which we believe was due to interference associated with the current spacing and benches. Our analysis of these results led to the following individual well reserve recovery and the overall spacing assumptions (all arrived at prior to the de-recognition of PUDs more fully described elsewhere): 

• No distinct benches exist within the Mississippian section that are not in direct communication with each other resulting in only four to five wells per section that we believe should be spaced horizontally 1,000 feet or more apart;

• Year-end PUD type curves for future development are estimated to have reserves of 175 Mbbl per well, down from the 250 Mbbl at the time of the Business Combination; 

• Year-end proved reserve spacing per section is assumed at four or five wells per section which is roughly equivalent to the assumptions at the time of the Business Combination; 

• Year-end probable and possible resource individual well recovery was assessed to be 200 Mbbl compared to 250 Mbbl at the time of the Business Combination;

• Year-end probable and possible resource spacing assumes no additional wells per section on fully developed proved sections; and

• No incremental recovery expected from contingent resources.

The summary of impairment expense follows:  

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	Successor		Predecessor
(in millions)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year ended December 31, 2017		Year ended December 31, 2016
Impairment of unproved properties	$	742.1	$	—	$	—	$	—
Impairment of proved properties	1,291.6		—		1.2		0.4
Total impairment of assets	$	2,033.7	$	—	$	1.2	$	0.4

In the future, we may recognize further impairments of proved and unproved oil and gas properties if commodity prices decline and further restrict our drilling plans. Prolonged low commodity prices may also result in additional impairments of other assets and could cause us to delay or abandon anticipated development activities. Our impairments in the Successor Period are also the result of reductions in estimated sectional recovery and per well recovery.

Factors affecting future performance and our outlook

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

Results of Operations

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. 

For the Periods from February 9, 2018 Through December 31, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor) Compared to the Year Ended December 31, 2017 (Predecessor)

The tables included below set forth financial information for the Successor Period, the 2018 Predecessor Period, and the year ended December 31, 2017, which are distinct reporting periods as a result of the Business Combination.  The amounts below exclude operating results related to discontinued operations.

Revenues

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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)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017
Net production:
Oil (Mbbl)	5,053			494			3,907
Natural gas (MMcf)	16,913			1,609			13,972
NGLs (Mbbl)	2,268			151			1,277
Total (MBoe)	10,140			914			7,513
Average net daily production volume:
Oil (Mbbld)	15.5			12.7			10.7
Natural gas (MMcfd)	51.9			41.2			38.3
NGLs (Mbbld)	7.0			3.9			3.5
Total (MBoed)	31.1			23.4			20.6
Average sales prices:
Oil (per bbl)	$	63.99		$	62.68		$	49.76
Effect of realized derivatives settlements (per bbl)	(7.35		)	(6.44		)	(0.34		)
Oil, after hedging (per bbl)	$	56.64		$	56.24		$	49.42
Percentage of unhedged realized oil price to NYMEX oil price	99		%	99		%	98		%
Natural gas (per Mcf)	$	2.57		$	2.66		$	2.70
Effect of realized derivatives settlements (per Mcf)	(0.15		)	0.94			0.49
Natural gas, after hedging (per Mcf)	$	2.42		$	3.60		$	3.19
Percentage of unhedged realized gas price to NYMEX gas price	84		%	87		%	89		%
NGLs (per bbl)	$	18.98		$	26.41		$	24.62
Effect of realized derivatives settlements (per bbl)	—			—			(1.14		)
NGLs, after hedging (per bbl)	$	18.98		$	26.41		$	23.48
Percentage of unhedged NGL price to NYMEX oil price	29		%	42		%	48		%
Revenue
Oil	$	323,299		$	30,972		$	194,423
Natural gas	43,407			4,276			37,794
Natural gas liquids	43,039			4,000			31,445
Total E&P sales revenue	$	409,745		$	39,248		$	263,662

Oil revenue for the Successor Period and the 2018 Predecessor Period increased compared to the year ended December 31, 2017 due to an increase in production in 2018 and higher prevailing market prices. The increase in production in 2018 was due to an increase in the number of wells drilled and new wells on production as a consequence of a sharp increase in 2018 capital expenditures.

Natural gas revenue for the Successor Period and the 2018 Predecessor Period increased compared to the year ended December 31, 2017, due to an increase in production in 2018, this was partially offset by lower prevailing market prices.

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NGL revenue for the Successor Period and the 2018 Predecessor Period increased compared to the year ended December 31, 2017 due to an increase in production in 2018, partially offset by lower average prices. The increase in production volume was primarily due to our 2018 development activities.  The pricing reduction primarily relates to the volume election, as described below. Under our gathering contract with KFM, we have an ability to determine ethane recovery volumes as either actual volumes or as the levels that the plant can recover. In 2018, we generally elected to recover ethane volumes, which had the impact of increasing the NGLs volume and decreasing the price received per barrel.

Gain (loss) on sale of assets in 2018 primarily includes a gain for the sale of seismic data totaling $5.9 million in the Successor Period.

Gain on acquisition of oil and gas properties in 2017 was related to a bargain purchase of certain proved STACK oil and gas reserves resulting in a gain totaling $1.7 million in 2017. A bargain purchase occurs when the fair value of the assets acquired, net of the fair value of liabilities assumed, exceeds the purchase price paid.

	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017
Gain (loss) on derivatives:
Realized gains (losses) -
Oil	$	(36,505	)	$	(3,819	)	$	(1,325	)
Natural gas	(2,456		)	1,523			6,904
NGLs	—			—			(1,462		)
Total realized gains (losses)	(38,961		)	(2,296		)	4,117
Unrealized gains (losses)	28,714			8,959			4,170
Total gain (loss) on derivatives	$	(10,247	)	$	6,663		$	8,287

Gain (loss) on derivatives changes represent market movements in futures prices compared with the levels where our ongoing hedging program are struck. Unrealized gains in the Successor Period were substantially influenced by the spot and futures price declines during the latter half of 2018, particularly during in the last week of December 2018.

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Operating Expenses

	Successor		Predecessor
(in thousands, except per unit data)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017
Operating expenses:
Lease operating	$	60,547	$	4,408	$	43,953
Transportation and marketing	50,038		3,725		29,460
Production taxes	16,865		953		5,494
Workovers	5,563		423		4,255
Exploration	34,085		7,003		13,563
Depreciation, depletion and amortization	133,554		11,670		89,115
Impairment of assets	2,033,712		—		1,188
General and administrative	114,735		21,234		55,671
Total operating expense	$	2,449,099	$	49,416	$	242,699
Select operating expenses per BOE:
Lease operating	$	5.97	$	4.82	$	5.85
Transportation and marketing	4.93		4.08		3.92
Production taxes	1.66		1.04		0.73
Workovers	0.55		0.46		0.57
Depreciation, depletion and amortization	13.17		12.77		11.86

Lease operating expense for the Successor Period and the 2018 Predecessor Period increased compared to 2017, primarily due to cost associated with increased use of submersible pumps for artificial lift, and increased costs associated with our produced water disposal assets (prior to their sale to KFM) and additional wells drilled.

Transportation and marketing expense in the Predecessor Periods represents throughput for our properties in the STACK at the KFM processing facility. Transportation and marketing expense in the Successor Period and the 2018 Predecessor Period increased compared to the year ended December 31, 2017 primarily due to higher volumes flowing from our operated wells into the KFM plant. 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. 

Production taxes for the Successor Period and 2018 Predecessor Period are higher as compared to 2017 primarily due to the increase in oil and natural gas liquids revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018, for wells in their first 3 years of production.  Production taxes are assessed based on revenues on a pre-hedge basis.

	Successor		Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017
Exploration expense:
Geological and geophysical costs	$	6,755	$	2,440	$	5,729
Exploratory dry hole expense	1,954		—		—
Other exploration expense, including expired leases	24,374		4,504		7,797
ARO settlements in excess of recorded liabilities	1,002		59		37
Total exploration expense	$	34,085	$	7,003	$	13,563

Exploration expense for the Successor Period and the 2018 Predecessor Period increased compared to 2017 primarily due to an increase in expired leaseholds of $20.1 million and a single exploratory dry hole costing $2.0 million.

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Depreciation, depletion and amortization expense was higher on a per BOE basis in the Successor Period and the 2018 Predecessor Period as compared to 2017, primarily due to an increase in capital spending and in production in relation to booked reserves for 2018 on a Boe basis.

	Successor		Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017
Impairment of assets:
Impairment of unproved properties	$	742,065	$	—	$	—
Impairment of proved properties	1,291,647		—		1,188
Total impairment of assets	$	2,033,712	$	—	$	1,188

Impairment of assets largely hinges on 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)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017
General and administrative expense:
Employee-related costs	$	20,129	$	1,032	$	28,317
Strategic costs - Business Combination costs	23,717		17,040		8,118
Equity-based compensation	20,000		—		—
Professional fees	13,028		1,019		10,567
Severance costs	8,357		—		—
Provision for uncollectible related party receivables	22,438		—		—
Other	7,066		2,143		8,669
Total general and administrative expense	$	114,735	$	21,234	$	55,671

General and administrative expense for the Successor Period and the 2018 Predecessor Period increased compared to 2017. Strategic costs and professional fees were higher in 2018 due to advisors helping to value and integrate the acquired business pursuant to the Business Combination, plus the related increase in accounting and audit professional fees. The Successor Period also includes a $22.4 million reserve associated with estimated collectibility of receivables from certain related parties, including notes receivable, equity-based compensation awards using our parent’s publicly traded securities and the establishment of a stock-based compensation program, plus severance costs associated with the departure of certain members of executive management in late 2018, with no similar activity in the Predecessor Periods. Employee-related costs decreased primarily due to reduced headcount.

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

	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017
Loss from continuing operations before income taxes	$	(2,076,370	)	$	(7,116	)	$	(12,840	)
Interest expense	38,265			5,511			50,585
Gain on unrealized hedges	(28,714		)	(8,959		)	(4,170		)
(Gain) loss on sale of property and equipment	388			—			—
Exploration	34,085			7,003			13,563
Depreciation, depletion and amortization	133,554			11,670			89,115
Impairment of assets	2,033,712			—			1,188
Provision for uncollectible related party receivables(1)	22,438			—			—
Equity-based compensation	20,000			—			—
Business Combination related expense	23,717			17,040			8,118
Adjusted EBITDAX	$	201,075		$	25,149		$	145,559

_________________

(1) Represents a reserve associated with estimated collectibility of certain related party receivables, including notes receivable, and is included in general and administrative expense in the Successor Period.

Other Income (Expense)

	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017
Alta Mesa RBL	$	2,807		$	815		—
Alta Mesa Predecessor Credit Facility	—			—			7,283
2024 Notes	35,273			3,281			39,375
Bond premium amortization	(4,512		)	—			—
Deferred financing cost amortization	221			170			2,732
Other	4,476			1,245			1,195
Total interest expense	38,265			5,511			50,585
Interest income and other	(1,983		)	(172		)	(1,075		)
Total other (income) expense	$	36,282		$	5,339		$	49,510

Interest expense for the Successor Period and 2018 Predecessor Period decreased primarily due to amortization of bond premium of $4.5 million and lower interest on the Alta Mesa RBL due to lower average amounts outstanding.

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For the Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016

The tables included below set forth financial information of our Predecessor for the years ended December 31, 2017 and 2016. The amounts below exclude operating results related to discontinued operations.

Revenues

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:

	Predecessor
(in thousands, except per unit data)	Year Ended December 31, 2017			Year Ended December 31, 2016
Net production:
Oil (Mbbl)	3,907			2,571
Natural gas (MMcf)	13,972			8,259
NGLs (Mbbl)	1,277			824
Total (MBoe)	7,513			4,772
Average net daily production volume:
Oil (Mbbld)	10.7			7.0
Natural gas (MMcfd)	38.3			22.6
NGLs (Mbbld)	3.5			2.3
Total (MBoed)	20.6			13.1
Average sales prices:
Oil (per bbl)	$	49.76		$	41.15
Effect of realized derivatives settlements (per bbl)	(0.34		)	32.1
Oil, after hedging (per bbl)	$	49.42		$	73.25
Percentage of unhedged realized oil price to NYMEX oil price	98		%	95		%
Natural gas (per Mcf)	$	2.70		$	2.42
Effect of derivatives settlements (per Mcf)	0.49			0.79
Natural gas, after hedging (per Mcf)	$	3.19		$	3.21
Percentage of unhedged realized gas price to NYMEX gas price	89		%	95		%
NGLs (per bbl)	$	24.62		$	17.21
Effect of derivatives settlements (per bbl)	(1.14		)	(0.40		)
NGLs, after hedging (per bbl)	$	23.48		$	16.81
Percentage of unhedged realized NGL price to NYMEX oil price	48		%	40		%
Revenue
Oil	$	194,423		$	105,811
Natural gas	37,794			20,021
Natural gas liquids	31,445			14,174
Total E&P sales revenue	$	263,662		$	140,006

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The 2017 increase in oil revenue was primarily attributable to higher average sales prices pre-hedge as well as increased production volumes. An increase in production of 1,336 Mbbls, resulted in an approximate $55.0 million increase in oil revenue at 2016 average oil sales price. The increase in oil volumes is primarily due to new production.

The 2017 increase in natural gas revenue was attributable to increased production volumes as well as higher prices during 2017. The increase in gas volumes is attributable to new production.

The 2017 increase in NGL revenue was primarily attributable to an increase in prices as well as increased volumes. The increase in natural gas liquid volumes is due primarily to an increase in output.

Gain on acquisition of oil and gas properties was related to a bargain purchase of certain proved STACK oil and gas reserves resulting in a gain totaling $1.7 million in 2017.

	Predecessor
(in thousands)	Year Ended December 31, 2017			Year Ended December 31, 2016
Gain (loss) on derivatives:
Realized gains (losses) -
Oil	$	(1,325	)	$	82,522
Natural gas	6,904			6,500
NGLs	(1,462		)	(333		)
Total realized gains (losses)	4,117			88,689
Unrealized gains (losses)	4,170			(129,149		)
Total gain (loss) on derivatives	$	8,287		$	(40,460	)

Operating Expenses

	Predecessor
(in thousands, except per unit data)	Year Ended December 31, 2017		Year Ended December 31, 2016
Operating expenses:
Lease operating	$	43,953	$	29,567
Transportation and marketing	29,460		11,628
Production taxes	5,494		2,765
Workovers	4,255		3,441
Exploration	13,563		17,230
Depreciation, depletion and amortization	89,115		53,755
Impairment of assets	1,188		382
General and administrative expenses	55,671		40,468
Total operating expense	$	242,699	$	159,236
Select operating expenses per BOE:
Lease operating	$	5.85	$	6.20
Transportation and marketing	3.92		2.44
Production taxes	0.73		0.58
Workovers	0.57		0.72
Depreciation, depletion and amortization	11.86		11.26

Lease operating expense increased primarily due to increased production volume and increased compression, salt water disposal, chemicals, repairs and maintenance and fuel and power totaling $12.9 million.

Transportation and marketing expense increased primarily due to increased throughput at the KFM processing facility beginning in the second quarter of 2016. In addition, the increase is due to higher transportation and marketing fees charged to

48

provide effective gathering, efficient processing and assurance that our production will continue to flow as the activity in the basin expands at the KFM processing facility.

Production taxes increased $3.0 million primarily due to the increase in oil and gas revenue. Ad valorem taxes remained flat year over year.

	Predecessor
(in thousands)	Year Ended December 31, 2017		Year Ended December 31, 2016
Exploration expense:
Geological and geophysical costs	$	5,729	$	9,653
Other exploration expense	7,797		7,545
ARO settlements in excess of recorded liabilities	37		32
Total exploration expense	$	13,563	$	17,230

Exploration expense decreased primarily due to decreases in seismic expenses of $4.1 million, which are reflected in geological and geophysical costs.

Depreciation, depletion and amortization expense increased due to increased production.

	Predecessor
(in thousands)	Year Ended December 31, 2017		Year Ended December 31, 2016
Impairment of assets:
Impairment of unproved properties	$	—	$	16
Impairment of proved properties	1,188		366
Total impairment of assets	$	1,188	$	382

Impairment of assets increased due to the impairment of certain developed fields resulting from downward revisions in reserves on proved properties based on lower commodity prices, and performance or development drilling results that were below expectations.  

	Predecessor
(in thousands)	Year Ended December 31, 2017		Year Ended December 31, 2016
General and administrative expense:
Employee-related costs	$	28,317	$	26,226
Strategic costs - Business Combination Costs	8,118		—
Professional fees	10,567		10,577
Other	8,669		3,665
Total general and administrative expense	$	55,671	$	40,468

General and administrative expense increased primarily due to consulting and other fees directly attributable to the Business Combination plus a legal settlement of $4.7 million which is included in other G&A.

Below is a reconciliation of Upstream EBITDAX to operating income (loss):

49

	Predecessor
(in thousands)	Year Ended December 31, 2017			Year Ended December 31, 2016
Loss from continuing operations before income taxes	$	(12,840	)	$	(134,279	)
Interest expense	50,585			59,675
(Gain) loss on unrealized hedges	(4,170		)	129,149
Exploration	13,563			17,230
Depreciation, depletion and amortization	89,115			53,755
Impairment of assets	1,188			382
Non-recurring Business Combination expense	8,118			—
Adjusted EBITDAX	$	145,559		$	125,912

Other Income (Expense)

	Predecessor
(in thousands)	Year Ended December 31, 2017			Year Ended December 31, 2016
Interest expense:
Alta Mesa Predecessor Credit Facility	$	7,283		$	8,826
Senior term loan facility	—			9,156
2024 Notes	39,375			37,272
Deferred financing cost amortization	2,732			3,905
Other	1,195			516
Total interest expense	50,585			59,675
Interest income and other	(1,075		)	(884		)
Loss on extinguishment of debt	—			18,151
Total other (income) expense	$	49,510		$	76,942

Interest expense decreased primarily due to the interest on our senior term loan facility that was repaid in full during the fourth quarter 2016.

Loss on extinguishment of debt resale from the2016 repurchase of our $450.0 million outstanding 2018 Notes for which we recognized a loss of $13.5 million, which included unamortized discount and unamortized deferred financing costs write-offs. In addition, we repaid all amounts outstanding under the senior secured term loan facility of $127.7 million, which included accrued interest and a prepayment premium of $2.5 million. We recognized a loss related to the repayment of $4.7 million, which included write-offs of unamortized deferred financing costs totaling $2.0 million.

Loss on discontinued operations relates to the loss from the distribution of non-STACK oil and gas assets and related liabilities to the AM Contributor immediately prior to the Closing Date of the Business Combination.

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, development activities and to satisfy our contractual obligations related to servicing our debt and hedges. During 2018, our main sources of liquidity and capital resources came from the cash balance held following the Business Combination, cash flows generated from operations and borrowings under the Alta Mesa RBL.

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Our future drilling plans and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, midstream availability, other working interest owner participation and regulatory matters. Any deferral of planned capital expenditures, particularly with respect to bringing new wells onto production, could reduce our anticipated production, revenue and cash flow, and may result in the expiry of certain leases. However, because a large percentage of our acreage is held by production,we can alter our drilling program to minimize the risk of losing significant acreage. 

We strive to maintain financial flexibility and, if they are available to us on terms we find acceptable, may access the capital markets to facilitate our development program, to selectively expand our acreage position or to redesign our capital structure. If our operating cash flow is materially less than anticipated and other sources of capital are not available on acceptable terms, we may decide to curtail our capital spending. 

During January 2019, we received an audit report from our external reserve engineers regarding their opinion of our 2018 ending proved reserves, which included multi-year development of our proved undeveloped reserves. During April 2019, in finalizing our financial reporting for 2018, we determined that we may fail to satisfy the leverage covenant under the Alta Mesa RBL during 2019, possibly as soon as the June 2019 testing period, the results of which to be reported in August 2019. Accordingly, if we were to fail the leverage covenant, access to capital under the Alta Mesa RBL would likely be impaired, thus limiting our ability to satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our future drilling locations. Thus, we did not recognize any proved undeveloped locations in the final December 31, 2018 reserve report. Should our ability to fund the required development costs improve in the future, we expect to re-recognize all or a portion of those reserves as proved.

Despite the absence of PUD locations in the 2018 reserve report, we expect to operate between 2 and 3 rigs during 2019 to develop our assets, particularly to focus on testing the spacing patterns we believe to be optimal, and to implement cost reduction strategies. If we have adequate liquidity to fund such operations, we expect to drill and bring online approximately 60 wells during 2019 while incurring approximately $140.0 million to $155.0 million of capital expenditures related to this development program. We also expect that an additional $18.0 million to $23.0 million could be incurred for non-operated projects, leasehold costs and capitalized workover activity. We do not expect our operating cash flow to provide sufficient proceeds to meet this level of expenditure and we would be required to utilize proceeds from borrowings under the Alta Mesa RBL, if capacity becomes available to us.

During April 2019, our borrowing base was reduced from $400.0 million to $370.0 million as part of the semi-annual redetermination. In addition, we drew our remaining capacity to bring our outstanding borrowings to approximately $350.0 million and outstanding letters of credit of $20.0 million, with approximately $86.0 million of cash on hand after completing that borrowing. We did not obtain covenant relief as part of the redetermination, but that remains an important objective for us as we strive to continue to comply with all the terms of our debt. We believe that the combined operating cash flow and cash currently on our balance sheet will be sufficient to allow us to carry out the desired development program, despite the associated negative free cash flow. Our ability to reduce well costs and to more precisely assess the productivity of wells under our new spacing design tests are important to our success in 2019 and beyond as we evaluate our future prospects and opportunities.

As we execute our business strategy, we will continually monitor the capital resources available to meet future financial obligations and planned capital expenditures. We believe our cash flows provided by operating activities and funds sourced by the Alta Mesa RBL will allow us to pursue our currently planned development activities. We cannot provide assurance that operations and other needed capital will be available on acceptable terms, or at all.

A detailed description of our debt including the significant terms and associated requirements is found in Item 8.

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Alta Mesa RBL

In connection with the consummation of the Business Combination, all indebtedness at that time under the Alta Mesa senior secured revolving credit facility was repaid in full and we entered into the Alta Mesa RBL,which provided an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base, which will be redetermined semi-annually.  The Alta Mesa RBL matures on February 9, 2023. In April 2018, the borrowing base was increased to $400.0 million, which was reaffirmed by the lenders during the fourth quarter of 2018. As of December 31, 2018, in addition to $161.0 million of borrowings outstanding, we also had $21.9 million of outstanding letters of credit, leaving a total borrowing capacity of $217.1 million remaining available for future use. On April 1, 2019, the borrowing base was reduced to $370.0 million upon completion of the regularly scheduled semi-annual redetermination. During April 2019, we drew $70.0 million to consume all the remaining capacity under the Alta Mesa RBL.

The Alta Mesa RBL includes usual and customary covenants for facilities of its type and size. The covenants cover matters such as mandatory reserve reports, the responsible operation and maintenance of properties, certifications of compliance, required disclosures to the lenders, notices under other material instruments, and notices of sales of oil and gas properties. It also places limitations on the incurrence of additional indebtedness, restricted payments, distributions, investments outside of the ordinary course of business and the amount of hedges that we can put in place. We are not permitted to borrow funds if we are not in compliance with the financial covenants.

The Alta Mesa RBL bears interest at LIBOR plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 1.50% to 2.50%. There is also a commitment fee that ranges between 0.375% and 0.50% on the undrawn borrowing base amounts. The RBL may be prepaid without a premium. Interest on outstanding facility debt was LIBOR+2.00% at December 31, 2018.

The Alta Mesa RBL has two financial maintenance covenants (each as determined under the applicable definitions):

• A ratio of current assets to current liabilities of not less than 1.0; and

• A consolidated total leverage ratio of not more than 4.0.

During 2019, we may be unable to satisfy the consolidated total leverage ratio and recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. In addition, we are currently in default under the Alta Mesa RBL for our failure to provide certain information by May 15, 2019 for the fiscal quarter ended March 31, 2019. The default can be cured by providing the information by June 14, 2019.

2024 Notes

Alta Mesa has $500.0 million in aggregate principal amount of 7.875% senior unsecured notes (the “2024 Notes”) that were issued at par by Alta Mesa and its wholly owned subsidiary Alta Mesa Finance Services Corp. during the fourth quarter of 2016.  The 2024 Notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017. 

The 2024 Notes will mature in December 2024, and interest is payable semi-annually on June 15 and December 15 of each year. Alta Mesa may, from time to time, redeem certain amounts of the outstanding 2024 Notes at specified prices.

During the latter half of 2018 and into 2019, the 2024 Notes saw a substantial decrease in their trading prices. The ratings associated with the 2024 Notes also deteriorated, based on the rating agencies’ belief that an exchange for less than par value had become more likely. In March 2019, we were notified that certain noteholders had formed a group, which purported to represent a majority of the face value of the 2024 Notes. Although the impact of this formation has not yet been determined, we have contacted the group through our financial advisors and believe that further discussions will take place.

The 2024 Notes include usual and customary covenants for debt of its type and size. The covenants cover matters such as the responsible operation and maintenance of properties, certificates of compliance, required disclosures to the lenders, notices under other material instruments, notices of sales of oil and gas properties and events of default. The covenants also limit our ability to incur liens, which impacts the quantum available to refinance our Alta Mesa RBL.

The 2024 Notes have no financial maintenance covenants.

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We may from time to time seek to retire the 2024 Notes through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity, contractual restrictions and other factors.

Related Party Receivables

On September 29, 2017, we 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, 2018 and 2017, amounts due under the promissory note totaled $1.7 million and $1.5 million, respectively. 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. We subsequently declared all amounts owing under the note immediately due and payable. We also have 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, 2018 and 2017, the note receivable amounted to $11.7 million and $10.8 million, respectively. HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to us. We oppose HMI’s claims and believe HMI’s obligation under the notes to be our valid assets and that the full amount is payable to us. We intend to pursue all available 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 directors of AMR who are also controlling holders and directors of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2018, 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, $0.1 million, $0.9 million, and $0.8 million for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively, all recorded as paid-in-kind and added to the balance due thereunder.

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 “High Mesa Agreement”) with HMI with respect to its non-STACK assets. Under the High Mesa Agreement, during the 180-day period following the Closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000, (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the High Mesa Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services from 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 High Mesa 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 High Mesa Agreement, and pursuant to the High Mesa Agreement as “Receivables due from related party” in the balance sheets. As of December 31, 2018 (Successor) and December 31, 2017 (Predecessor), we had receivables of approximately $10.1 million and $0.8 million for costs and expenses incurred on HMI’s behalf. Subsequent to year-end, we billed HMI $0.9 million for incremental MSA costs incurred and have received approximately $1.0 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result, we have recognized an allowance for uncollectible accounts of $9.0 million to fully provide for the unremitted balance and may have future allowances for amounts incurred in 2019 prior to the termination of the MSA. 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.

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Cash flows

	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
Cash from operating activities	$	93,480		$	26,336		$	59,328		$	131,704
Cash from investing activities	(643,746		)	(37,913		)	(345,876		)	(224,298		)
Cash from financing activities	553,906			16,932			283,920			91,238
Net increase (decrease) in cash, cash equivalents and restricted cash	$	3,640		$	5,355		$	(2,628	)	$	(1,356	)

Cash flows from operating activities

Cash provided by operating activities (including operating activities of discontinued operations) was $93.5million, $26.3 million and $59.3 million for the Successor Period, the 2018 Predecessor Period and the year ended December 31, 2017, respectively. Cash-based items of net income (loss), including revenue (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense were approximately $139.2 million, $1.0 million and $95.2 million for the Successor Period, 2018 Predecessor Period and the year ended December 31, 2017, respectively. Changes in working capital and other assets and liabilities in a decrease in cash of approximately $47.7 million and $35.9 million for the Successor Period and the year ended December 31, 2017, respectively. Changes in working capital and other assets and liabilities during the 2018 Predecessor Period resulted in an increase in cash of approximately $51.7 million.

Cash provided by operating activities (including operating activities of discontinued operations) was $59.3 million and $131.7 million for the years ended December 31, 2017 and 2016, respectively. The changes in our working capital accounts used $35.9 million in cash as compared to having provided $28.1 million in cash in 2016. Cash-based items of net income, including revenue (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense were approximately $95.2 million and $103.6 million for the years ended December 31, 2017 and 2016, respectively.

Cash flow from investing activities

Approximately $643.7 million of cash was used by investing activities (including investing activities from discontinued operations) in the Successor Period. $37.9 million and $345.9 million were for the 2018 Predecessor Period and 2017 Predecessor Period, respectively. Capital expenditures for property and equipment, including acquisitions used cash of $701.0 million and $369.6 million for the twelve months ended December 31, 2018 and 2017, respectively.  Cash used for capital expenditures for property and equipment totaled approximately $36.7 million during the 2018 Predecessor Period. During the 2017 Predecessor Period, the cash used for capital expenditures for property and equipment totaled approximately $314.0 million and acquisitions totaled approximately $55.6 million. Additionally, during the 2017 Predecessor Period, we entered into an interest bearing promissory note receivable with our affiliate Northwest Gas Processing, LLC for approximately $1.5 million.  

Investing activities (including investing activities from discontinued operations) used cash of $345.9 million for the year ended December 31, 2017 as compared to $224.3 million for the year ended December 31, 2016. Capital expenditures for property and equipment, including acquisitions used cash of $369.6 million and $225.6 million for the years ended December 31, 2017 and 2016, respectively. In addition, we entered into an interest bearing promissory note receivable with our affiliate Northwest Gas Processing, LLC for approximately $1.5 million.

Cash flow from financing activities

Cash provided by financing activities (including financing activities of discontinued operations) was $553.9 million, $16.9 million and $283.9 million for the Successor Period, the 2018 Predecessor Period and 2017 Predecessor Period, respectively. The 2018 Predecessor Period included proceeds from the issuance of long-term debt totaling $60.0 million, offset by repayments of long-term debt totaling $43.0 million. The 2017 Predecessor Period included proceeds from the issuance of long-term debt totaling $373.1 million and capital contributions totaling $207.9 million, partially offset by repayments of long-term debt totaling $296.6 million.

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Cash provided by financing activities (including financing activities of discontinued operations) was $283.9 million during the year ended December 31, 2017 as compared to cash used of $91.2 million during the year ended December 31, 2016. During 2017, we drew down $76.4 million, net of payments, under our senior secured revolving credit facility. During 2017, Riverstone was admitted as a limited partner in connection with its $200.0 million contribution to us. In addition, we received $7.9 million in capital contributions from our former Class B limited partner, HMI.

Risk Management Activities — Commodity Derivative Instruments

Oil and gas prices are inherently volatile and unpredictable. Accordingly, to achieve more predictable cash flow and reduce our exposure to adverse fluctuations in commodity prices, we have historically utilized commodity derivatives, such as swaps and collars, to hedge price risk associated with our anticipated production and to underpin our development program. This helps reduce potential negative effects of reductions in gas prices but also reduces our ability to benefit from increases in gas prices. In certain circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions.

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

A put option has an established floor price. The buyer of that put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.

A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

A put option and a call option may be combined to create a collar. A collar requires the seller to pay the buyer if the settlement price is above the ceiling price and requires the buyer to pay the seller if the settlement price is below the floor price. Our commodity derivatives allow us to mitigate the potential effects of the variability in operating cash flow thereby providing increased certainty of cash flows to support our capital program and to service our debt. Our derivatives provide only partial price protection against declines in natural gas prices and partially limit our potential gains from future increases in prices. The following table summarizes our remaining derivatives.

We had the following call and put derivatives at December 31, 2018:

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OIL

	Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	182,500	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	2,701,000	66.31		75.20		56.50
Long Put Options	2,883,500	53.80		62.00		50.00
Short Put Options	2,883,500	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	585,600	64.32		73.80		59.55
Long Put Options	1,537,200	55.54		62.50		50.00
Short Put Options	1,537,200	44.64		50.00		37.50

GAS

	Volume in	Weighted	Range
Settlement Period and Type of Contract	MMBtu	Average	High	Low
2019
Price Swap Contracts	10,905,000	2.69	3.09	2.64
Collar Contracts
Short Call Options	4,000,000	3.31	3.75	3.17
Long Put Options	3,550,000	2.81	2.90	2.70
Short Put Options	2,425,000	2.27	2.40	2.20
2020
Collar Contracts
Short Call Options	2,275,000	3.19	3.20	3.17
Long Put Options	9,150,000	2.57	2.70	2.50
Short Put Options	9,150,000	2.07	2.20	2.00
2021
Collar Contracts
Long Put Options	2,250,000	2.65	2.65	2.65
Short Put Options	2,250,000	2.15	2.15	2.15

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

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We had the following basis swaps at December 31, 2018:

Total Gas Volumes in MMBtuover Remaining Term(1)	Reference Price 1 (1)	Reference Price 2 (1)	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
17,950,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '19	—	Dec '19	(0.68		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
2,365,000	San Juan	NYMEX Henry Hub	Jan '19	—	Oct '19	(0.78		)

_________________

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

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2018 (in thousands):

	Year Ended December 31,
	Total		2019		2020-2021		2022-2023		Thereafter
Long-term debt	$	661,000	$	—	$	—	$	161,000	$	500,000
Interest on long-term debt (1)	280,911		50,243		100,485		90,808		39,375
Operating leases	26,945		2,819		5,762		6,145		12,219
Firm gas processing reservation contract(2)	4,658		1,551		3,107		—		—
Firm transportation contracts(3)	86,203		12,236		24,472		24,472		25,023
Drilling rigs (4)	6,068		6,068		—		—		—
Abandonment liabilities (5)	11,409		2,860		791		175		7,583
Total	$	1,077,194	$	75,777	$	134,617	$	282,600	$	584,200

_________________

(1) Interest on the outstanding balance under the Alta Mesa RBL is payable quarterly; and for the 2024 Notes is payable semiannually. The weighted average rates on our outstanding borrowings as of December 31, 2018 of 6.75% was utilized to calculate the projected interest for our Alta Mesa RBL.  Projected obligation amounts are based on the payment schedules for interest, and are not presented on an accrual basis.  

(2) We entered into an agreement with KFM to reimburse half of the expenses associated with any shortfall in committed volumes not physically delivered. Amounts represent the total maximum cash payment required if KFM does not deliver to a third party for processing. During the period February 9, 2018 through December 31, 2018, cash payments required under our commitments totaled approximately $0.1 million.

(3) Total cash payment required for committed capacity.

(4) Obligations for the cost of drilling rigs are included at the gross contractual value. Due to our various working interests where the drilling rig contracts will be utilized, it is not feasible to estimate a net contractual obligation. Net payments under these contracts are accounted for as capital additions to our oil and gas properties and could be less than the gross obligation disclosed.  

(5) Represents estimated discounted costs to retire and remove long-lived assets at the end of their operations.

Our contracted commitments to secure capacity on third party pipelines for transportation of our natural gas are as follows:

	Total
Gas:
2019 (MMBtu)	54,750,000
2020 (MMBtu)	54,900,000
2021 (MMBtu)	54,750,000
2022 (MMBtu)	54,750,000

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We have entered into certain firm commitments intended to secure capacity on third party pipelines for transportation of our natural gas. We currently do not utilize the full amount of our contracted capacity. However, we strive to release capacity to third parties for a fee.

Off-Balance Sheet Arrangements

As of December 31, 2018, other than as described below, we had no guarantees of third-party obligations, and our off-balance sheet obligations include our obligations under operating leases.  We also are contingently liable for bonds posted in the aggregate amount of $1.3 million, primarily to cover future abandonment costs, and $21.9 million in letters of credit provided under our senior secured revolving credit facility.  We typically enter into short-term drilling contracts which are customary in the oil and gas industry.  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 on behalf of both companies covering STACK and non-STACK assets. The surety bonds in place and covered by the joint indemnity agreement for HMI non-STACK properties total approximately $15.0 million. The surety has requested posting of collateral. If HMI cannot post collateral or satisfy its indemnity obligations, Alta Mesa may be required post collateral or otherwise satisfy HMI’s obligations associated with HMI 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.

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

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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. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in recognition of impairments, such as those seen in 2018 where our year-end reserves reduced substantially compared to reserves at the time of the Business Combination. In addition to using estimates of proved reserves to assess for impairment, 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 could also cause us 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, current development plans, expected resource recovery, recent drilling results in the area, our geologists’ evaluation of the property and the remaining 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 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.

59

Key assumptions used to determine the undiscounted future cash flows 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. As an example, we utilized forward commodity price estimates as of December 31, 2018, in our future net cash flow estimates. These price estimates contributed to an impairment charge of $1.3 billion being recorded during the Successor Period with respect to our proved oil and gas properties. Forward commodity price estimates increased shortly after the end of 2018. Had we been able to use mid-January 2019 forward commodity price estimates instead, our impairment charge would have decreased by approximately $100.4 million. 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.

Derivatives

Policy Description

We measure our derivatives at estimated fair value and record them as assets or liabilities in the balance sheet. Changes in fair value of our derivatives are recognized as “Gain (loss) on derivatives” in the statement of operations, along with realized gains or losses from the settlement of matured derivatives.  

We net the value of our derivative assets and liabilities with the same counterparty for purposes of presentation in our consolidated balance sheets where master netting agreements are in place.

Judgments and Assumptions

We have chosen not to elect hedge accounting treatment for our derivatives, which results in all changes in fair value of our derivatives being recognized each period in our statement of operations. Had we elected to treat some or all of our derivatives as cash flow hedges, any change in fair value of the derivative that effectively offsets the change in fair value of the underlying transaction, would have been deferred in other comprehensive income until the underlying transaction affected earnings at which time the offsetting impact of the hedge would have been reclassified from other comprehensive income to earnings. Hedge ineffectiveness would have been recognized in earnings each period under this election.

The estimates of the fair values of our commodity derivatives require substantial judgment. Valuations are based upon multiple factors such as futures prices, volatility data, length of time to maturity, credit risks and interest rates. We compare our estimates of fair value for these instruments with valuations obtained from independent third parties and counterparty valuation confirmations. We also make evaluations around the creditworthiness of counterparties where our derivatives are in the money. The values we report in our financial statements change as these estimates are revised to reflect actual results. Future changes to forecasted or realized commodity prices could result in significantly different values and realized cash flows for such instruments.

Recent Accounting Pronouncements

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

60

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk and Hedges

Our major market risk exposure is to prices for oil, gas and NGLs, which have historically been volatile. As such, future results are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for gas. We have used, and expect to continue to use, derivatives to reduce our exposure to the risks of price changes. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated with developed and undeveloped reserves.

Forecasted production from proved reserves is estimated in our December 2018 reserve report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, perhaps materially. Our risk factors in Item 1A contain discussions of significant matters related to future production.

The fair value of our oil and gas derivatives and basis swaps at December 31, 2018 was a net asset of $17.5 million. A 10% increase or decrease in oil and gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and gas commodity contracts of approximately $14.9 million (decrease in value) or $14.2 million (increase in value), respectively, as of December 31, 2018.

Counterparty and Customer Credit Risk

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

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

Much of our oil and gas production is sold through a marketing agreement with ARM, who markets and sells our oil and gas production under short-term contracts, generally with month-to-month pricing based on published indices, adjusted for transportation, location and quality. ARM remits monthly collections of these sales to us, net of its fee. For the Successor Period, ARM marketed $309.7 million, or 75% of our total operating revenue for the period. We are significantly exposed to ARM’s credit quality but have experienced no and anticipate no losses with it.

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

Interest Rates

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivatives. A 1% increase in interest rates would increase interest expense on the Alta Mesa RBL by approximately $1.6 million, based on the balance outstanding at December 31, 2018.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the Successor Period, the 2018 Predecessor Period, or the year ended December 31, 2017.  Although the impact of inflation has been insignificant in recent years, it could cause upward pressure on the cost of oilfield services, equipment and general and administrative expenses. 

61

Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

	Page
Audited Financial Statements
Reports of Independent Registered Public Accounting Firms	63
Consolidated Statements of Operations	65
Consolidated Balance Sheets	66
Consolidated Statements of Changes in Partners’ Capital	67
Consolidated Statements of Cash Flows	68
Notes to Consolidated Financial Statements	69
Note 1 — Description of Business	69
Note 2 — Summary of Significant Accounting Policies	69
Note 3 — Impairment of Assets	76
Note 4 — Receivables	76
Note 5 — Supplemental Cash Flow Information	77
Note 6 — Significant Acquisitions and Divestitures	77
Note 7 — Property and Equipment	80
Note 8 — Discontinued Operations (Predecessor)	81
Note 9 — Fair Value Measurements	83
Note 10 — Derivatives	84
Note 11 — Asset Retirement Obligations	87
Note 12 — Long Term Debt, Net	87
Note 13 — Accounts Payable and Accrued Liabilities	89
Note 14 — Commitments and Contingencies	89
Note 15 — Significant Concentrations	92
Note 16 — Employee Benefit Plans	92
Note 17 — Significant Risks and Uncertainties	92
Note 18 — Partners’ Capital	92
Note 19 — Equity-based Compensation (Successor)	93
Note 20 — Related Party Transactions	94
Note 21 — Subsidiary Guarantors	96
Note 22 — Subsequent Events	97
Note 23 — Supplemental Quarterly Information (Unaudited)	97
Note 24 — Supplemental Oil and Natural Gas Disclosures (Unaudited)	97

62

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Alta Mesa Holdings GP, LLC (as general partner of Alta Mesa Holdings, LP)

and the limited partners of Alta Mesa Holdings, LP:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Alta Mesa Holdings, LP and subsidiaries (the “Company”) as of December 31, 2018, the related consolidated statements of operations, changes in partners’ capital, and cash flows for the period from January 1, 2018 to February 8, 2018 (predecessor period) and for the period from February 9, 2018 to December 31, 2018 (successor period), 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, 2018 and the results of its operations and its cash flows for the period from January 1, 2018 to February 8, 2018 (predecessor period) and for the period from February 9, 2018 to December 31, 2018 (successor period), 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 is facing risks and uncertainties surrounding its credit facility covenant compliance that 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 audit. 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 audit 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 audit, 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 audit 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 audit 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 audit provides a reasonable basis for our opinion.

/s/ KPMG LLP

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

Houston, Texas

May 17, 2019

63

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Alta Mesa Holdings, LP and Board of Directors of

Alta Mesa Holdings GP, LLC

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Alta Mesa Holdings, LP and subsidiaries (collectively, the “Predecessor”) as of December 31, 2017, the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Predecessor as of December 31, 2017, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Predecessor’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 Predecessor 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 Predecessor 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 Predecessor’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/ BDO USA, LLP

We served as the Predecessor’s auditor from 2014 to 2018.

Houston, Texas

March 29, 2018, except for Note 8, as to which the date is May 17, 2019.

64

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)

	Successor			Predecessor
	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
Revenue
Oil	$	323,299		$	30,972		$	194,423		$	105,811
Natural gas	43,407			4,276			37,794			20,021
Natural gas liquids	43,039			4,000			31,445			14,174
Other	4,762			888			5,724			2,350
Operating revenue	414,507			40,136			269,386			142,356
Gain on sale of assets	4,751			840			28			3
Gain on acquisitions of oil and gas properties	—			—			1,668			—
Gain (loss) on derivatives	(10,247		)	6,663			8,287			(40,460		)
Total revenue	409,011			47,639			279,369			101,899
Operating expenses
Lease operating	60,547			4,408			43,953			29,567
Transportation and marketing	50,038			3,725			29,460			11,628
Production taxes	16,865			953			5,494			2,765
Workovers	5,563			423			4,255			3,441
Exploration	34,085			7,003			13,563			17,230
Depreciation, depletion and amortization	133,554			11,670			89,115			53,755
Impairment of assets	2,033,712			—			1,188			382
General and administrative	114,735			21,234			55,671			40,468
Total operating expenses	2,449,099			49,416			242,699			159,236
Operating income	(2,040,088		)	(1,777		)	36,670			(57,337		)
Other income (expense)
Interest expense	(38,265		)	(5,511		)	(50,585		)	(59,675		)
Interest income and other	1,983			172			1,075			884
Loss on debt extinguishment	—			—			—			(18,151		)
Total other income (expense), net	(36,282		)	(5,339		)	(49,510		)	(76,942		)
Loss from continuing operations before income taxes	(2,076,370		)	(7,116		)	(12,840		)	(134,279		)
Income tax provision (benefit)	4			—			6			—
Loss from continuing operations	(2,076,374		)	(7,116		)	(12,846		)	(134,279		)
Loss from discontinued operations, net of tax	—			(7,746		)	(64,815		)	(33,642		)
Net loss	$	(2,076,374	)	$	(14,862	)	$	(77,661	)	$	(167,921	)

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

65

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

໿

	Successor		Predecessor
	December 31, 2018		December 31, 2017
ASSETS
Current assets
Cash and cash equivalents	$	12,984	$	3,660
Restricted cash	1,001		1,269
Accounts receivable, net	68,370		76,161
Other receivables	6,267		1,388
Related party receivables	24,282		790
Notes receivable from related party	—		—
Prepaid expenses and other current assets	747		2,932
Current assets — discontinued operations	—		5,195
Derivatives	16,423		216
Total current assets	130,074		91,611
Property and equipment
Oil and gas properties, successful efforts method, net	763,337		894,630
Other property and equipment, net	38,147		32,140
Total property and equipment, net	801,484		926,770
Other assets
Deferred financing costs	1,151		1,787
Notes receivable from affiliate	—		12,369
Deposits and other long-term assets	63		9,067
Noncurrent assets — discontinued operations	—		43,785
Derivatives	2,947		8
Total other assets	4,161		67,016
Total assets	$	935,719	$	1,085,397

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

	Successor		Predecessor
	December 31, 2018		December 31, 2017
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	197,064	$	170,489
Accounts payable — related party	3,425		5,476
Advances from non-operators	5,193		5,502
Advances from related party	9,822		23,390
Asset retirement obligations	2,079		69
Current liabilities — discontinued operations	—		15,419
Derivatives	1,710		19,303
Total current liabilities	219,293		239,648
Long-term liabilities
Asset retirement obligations, net of current portion	9,330		10,400
Long-term debt, net	690,123		607,440
Noncurrent liabilities — discontinued operations	—		66,862
Derivatives	180		1,114
Other long-term liabilities	—		5,488
Total long-term liabilities	699,633		691,304
Total liabilities	918,926		930,952
Commitments and contingencies (Note 14)
Partners’ capital	16,793		154,445
Total liabilities and partners’ capital	$	935,719	$	1,085,397

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

66

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in thousands)

໿

	Predecessor
Balance, December 31, 2015	$	(177,049	)
Contributions	377,076
Net loss	(167,921		)
Balance, December 31, 2016	32,106
Contributions	200,000
Net loss	(77,661		)
Balance, December 31, 2017	154,445
Distribution of non-STACK oil and gas assets, net of associated liabilities	43,482
Net loss	(14,862		)
Balance, February 8, 2018	$	183,065
	Successor
Balance, February 9, 2018	$	1,535,891
Contributions	560,344
Distributions	(32,535)
Issuance of additional AMH purchase consideration	9,467
Equity-based compensation expense	20,000
Net loss	(2,076,374		)
Balance, December 31, 2018	$	16,793

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

67

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Successor			Predecessor
	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
Cash flows from operating activities:
Net loss	$	(2,076,374	)	$	(14,862	)	$	(77,661	)	$	(167,921	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	133,554			12,554			113,634			95,075
Provision for uncollectible related party receivables	22,438			—			—			—
Impairments	2,033,712			5,560			30,317			16,306
Amortization of deferred financing costs	221			171			2,732			3,905
Amortization of debt (premium) discount	(4,512		)	—			—			468
Equity-based compensation expense	20,000			—			—			—
Exploratory dry hole expense	1,954			—			2,500			419
Expired leases	24,101			4,575			9,125			11,158
(Gain) loss on derivatives	10,247			(6,663		)	(8,287		)	40,460
Cash settlements of derivatives	(38,961		)	(2,296		)	4,117			88,689
Premium paid on derivatives	—			—			(520		)	18,151
Interest converted into debt	—			103			1,209			1,209
Interest added to notes receivable from affiliate	12,454			(85		)	(867		)	(774		)
(Gain) loss on sale of property and equipment	388			1,923			22,179			(3,542		)
Gain on acquisitions of oil and gas properties	—			—			(3,294		)	—
Impact on cash from changes in:
Accounts receivable	10,936			(21,184		)	(43,530		)	(10,500		)
Other receivables	(4,205		)	(662		)	6,519			10,465
Receivables from affiliate and related party	(14,320		)	(117		)	218			45
Prepaid expenses and other non-current assets	10,881			(591		)	(6,203		)	(819		)
Advances from related party	(37,684		)	24,116			(19,138		)	42,528
Settlement of asset retirement obligations	(1,610		)	(63		)	(6,409		)	(2,125		)
Accounts payable to related party	2,032			—			(2,170		)	—
Accounts payable, accrued liabilities, and other liabilities	(11,772		)	23,857			34,857			(11,493		)
Cash from operating activities	93,480			26,336			59,328			131,704
Cash flows from investing activities:
Capital expenditures	(700,953		)	(36,695		)	(313,961		)	(214,061		)
Acquisitions, net of cash acquired	(31,959		)	(1,218		)	(55,605		)	(11,527		)
Proceeds from sale of assets	89,166			—			25,205			1,290
Notes receivable due from affiliate	—			—			(1,515		)	—
Cash from investing activities	(643,746		)	(37,913		)	(345,876		)	(224,298		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	241,000			60,000			373,065			722,557
Repayments of long-term debt	(214,065		)	(43,000		)	(296,622		)	(921,034		)
Deferred financing costs paid	(1,373		)	—			(398		)	(13,747		)
Capital distributions	(32,000		)	(68		)	—
Capital contributions	560,344			—			207,875			303,462
Cash from financing activities	553,906			16,932			283,920			91,238
Net Increase (Decrease) In Cash, Cash Equivalents and Restricted Cash	3,640			5,355			(2,628		)	(1,356		)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	10,345			4,990			7,618			8,974
Cash, Cash Equivalents and Restricted Cash, End of Period	$	13,985		$	10,345		$	4,990		$	7,618

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

68

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2018

NOTE 1 — DESCRIPTION OF BUSINESS

Alta Mesa Holdings, LP (“Alta Mesa” or “the Company”) is an independent exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County (“STACK”). Our operations prior to February 9, 2018, also included other oil and gas interests in Texas, Louisiana, Idaho and Florida.    In connection with the closing of the Business Combination described below, in which we were acquired by our parent company, Alta Mesa Resources, Inc. (“AMR”), on February 9, 2018, we distributed our non-STACK oil and gas assets and liabilities to High Mesa Holdings, LP (the “AM Contributor”) and completed our transition from a multi-play asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in the STACK.  

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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) or partners’ capital.  

As a result of the Business Combination, AMR was treated as the accounting acquirer and we were the accounting acquiree.  Our identifiable assets acquired and liabilities assumed by AMR were recorded at their estimated fair values which caused push down effects to us on the acquisition date.  As a result, our financial statements and certain footnote presentations separate our presentation into two distinct periods, the period before the consummation of the transaction (“Predecessor Period”) and the period after that date (“Successor Period”), to indicate the application of the different basis of accounting between the periods presented.  The period January 1, 2018 to February 8, 2018 is referred to as the 2018 Predecessor Period.

As noted above, we distributed our remaining non-STACK oil and gas assets and liabilities to the AM Contributor just prior to the closing of the Business Combination. We have determined that the remaining non-STACK oil and gas assets and liabilities as well as our Weeks Island field sold during the 4th quarter of 2017 are discontinued operations during the Predecessor Periods and have segregated their financial information from ours in the financial statements.

Principles of Consolidation

The consolidated 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, in accordance with GAAP.

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 estimates are utilized to determine amounts reported under GAAP related to collectibility of receivables, asset retirement obligations, derivatives, accounting for business combinations, share-based compensation 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

69

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company regularly maintains cash balances that exceed federally insured amounts but we have experienced no losses associated with these amounts. As of December 31, 2018 and 2017, we did not have any assets classified as cash equivalents.

Restricted Cash

Cash balances that are legally, contractually or otherwise restricted as to withdrawal or usage are considered restricted cash. As of December 31, 2018 and 2017, 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 and (ii) joint interest owners’ portion of operating costs for properties in which we are the operator. The purchasers of our production 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, or when leases expire, 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 other assets include:

Other Property and Equipment — Other property and equipment, such as land, vehicles, office furniture and office equipment, are recorded at cost.  Maintenance, repairs and minor renewals are expensed as incurred. 

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.  Other non-oil and gas property and equipment is depreciated over their estimated useful life, ranging from three to seven years.

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, current development plans, 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.

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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 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 or a change in our intent to utilize the asset. The determination of recovery is based on undiscounted cash flow projections 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 or an analysis from outside professional advisors.

Exploration Expense

Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, delay rentals, gains or losses on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized 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 there is ongoing assessment of commerciality.

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. The costs associated with the Alta Mesa RBL are reported as non-current assets and are amortized over the term of the facility as additional interest expense. During the Predecessor Periods, costs associated with the issuance of the 2024 Notes were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense.

Acquisitions

Business combinations are accounted for using the acquisition method of accounting. Accordingly, 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.

Asset Retirement Obligations

We recognize liabilities for the anticipated future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets by increasing the carrying amount of the related long-lived asset at the time it is legally incurred.  The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The asset retirement cost is recognized as depletion or depreciation over the life of the asset.  Accretion expense represents the increase to the discounted liability toward its expected settlement value and is included in “Depreciation, depletion and amortization” in the statements of operations.  Asset retirement obligations are subject to revision primarily for changes related to the estimated timing and cost of abandonment.

Bond Premium on Senior Unsecured Notes

In connection with the Business Combination, we estimated the fair value of our $500.0 million senior unsecured notes at $533.6 million. The excess above the face value was recognized as a bond premium, which is being amortized as a reduction in interest expense over the remaining term of the notes.

Derivatives

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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.

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 -

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. Entities can choose to apply ASC 606 using either the full retrospective approach or a modified retrospective approach. Effective December 31, 2018, we ceased to be an emerging growth company and adopted ASC 606 for the Successor Period, using a modified retrospective approach. There was no impact on the timing of recognition of revenue or of our classification of amounts between revenue and operating expenses upon adoption of ASC 606.

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.

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, 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. All facts and circumstances are considered and judgment is often required in making this determination.

Customers are invoiced once our performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30-60 days. There are no significant judgments that affect the amount or timing of revenue from contracts with customers. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities, apart from production receivables.

Our receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates, as well as for unbilled costs for wells subject to Oklahoma’s forced pooling process in which mineral owners have the option to participate in the drilling of pooled wells. Depending on the mineral owner’s decision, these costs

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will be billed to them or added to our oil and gas properties. 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.

Equity-Based Compensation

Our parent company, AMR, grants 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 AMR’s Class A Common Stock on the grant date. Performance-based restricted stock awards are valued using the market price of AMR’s 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 three 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.

Income Taxes

We have elected under the Internal Revenue Code of 1986, as amended, to be treated as an individual partnership for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are not taxed at the partnership level. Accordingly, no tax provision for federal income taxes is included in these financial statements.

Fair Value Hierarchy

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

There are three levels of the fair value hierarchy:

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

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

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

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

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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. We also consider the carrying value of our long-term debt under the Alta Mesa RBL to not be materially different from fair value due to short-term variable market rates of interest applicable to our outstanding borrowings.

Going Concern

We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration the following factors:

• During 2018, we incurred a net loss of $2.0 billion, due mainly to impairment of our proved and unproved oil and gas properties. Also, at December 31, 2018, our current liabilities exceeded our current assets by approximately $68.5 million.

• Market prices for crude oil declined significantly during the fourth quarter of 2018, closing in the mid-$40 range at the end of 2018. This negatively impacted future estimated prices for oil in 2019 and beyond, which lowers our expected future economic results from our assets.

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

• Our drilling costs increased in 2018 as compared to 2017 as a result of increased hydraulic fracturing intensity, installation of dewatering pumps, and the increasing number of stages completed in a lateral. While initially generating positive results, the benefit of these advanced completion techniques began to abate over time indicating limited long-term effect over the course of each well’s life. Our capital expenditures during the Successor Period were considerably higher than during 2017 and 2016.

• On April 1, 2019, our borrowing base was reduced to $370.0 million under the Alta Mesa RBL. During April 2019, we drew $70.0 million to consume all of the remaining capacity under the Alta RBL. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. Also, the lack of sufficient borrowing capacity may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations.

• We anticipate having difficulty meeting our existing leverage covenants during the next 12 months without relief from our lenders.

• We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in June 2019. The 2024 Notes trade substantially below par value.

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

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

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

• considered seeking new sources of financing at levels consistent with our current and recent secured debt capacity of $370.0 million to $400.0 million, however, such efforts have not reached a stage allowing us to formally seek terms; and

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

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

Recently Issued Accounting Standards Applicable to Us

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Adopted

During the 1st quarter of 2018, we adopted Accounting Standards Update (“ASU”) No. 2017-04, Intangibles - Goodwill and Other, Simplifying the Test for Goodwill Impairment. This newguidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Accordingly, any identified impairment of goodwill will be recognized as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.

We adopted ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) on December 31, 2018, which clarified how certain transactions are classified in the statement of cash flows. The adoption of this guidance had no material effect.

We adopted ASU 2014-09, Revenue from Contacts with Customers, and related amendments, codified as Accounting Standards Codification (“ASC”) 606, on December 31, 2018, retroactive to the beginning of our Successor Period. There was no impact on the timing of recognition of revenue or of our classification of amounts between revenue and operating expenses upon adoption of ASC 606, however, enhanced disclosure of our revenue recognition policies was required.

Not Yet Adopted

Leasing Standards

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. We have used a modified retrospective transition approach for existing leases with terms in excess of 12 months entered into prior to January 1, 2019, the date of our adoption.

In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases.  ASU 2018-01 and subsequent applicable ASUs also provide several other optional practical expedients in transition. We elected the “package of practical expedients”, which permits us to forgo reassessment of our prior conclusions about lease identification, lease classification and initial direct costs for leases entered into prior to the effective date, January 1, 2019. We also elected the land easement relief which permits us to forgo reassessment of existing or expired land easements not previously accounted for under ASC 840. Additionally, we elected the practical expedient to not provide comparative reporting periods and therefore financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. By accounting policy, we will not separate non-lease components from lease components. We did not elect the use-of-hindsight practical expedient.

We are continuing to assess and finalize all of the effects of adoption, but currently believe the most significant effects relate to (1) recognition of new right-of-use assets and lease liabilities on our balance sheet for our office and equipment operating leases totaling approximately $20.0 million each, effective as of January 1, 2019; and (2) providing significant new disclosures about our leasing activities in our future filings.

We are also finalizing the implementation of third-party lease accounting software and completing the design and implementation of our processes and internal controls regarding this new standard.

Other Standards

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses(Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

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

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We don’t expect the adoption of this standard to impact our financial position or results of operations.

NOTE 3 — IMPAIRMENT OF ASSETS

	Successor		Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Impairment of unproved properties	$	742,065	$	—	$	—	$	16
Impairment of proved properties	1,291,647		—		1,188		366
Total impairment of assets	$	2,033,712	$	—	$	1,188	$	382

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.

NOTE 4 — RECEIVABLES

	Successor			Predecessor
(in thousands)	December 31, 2018			December 31, 2017
Production sales	$	31,532		$	26,916
Joint interest billings	18,147			13,821
Pooling interest (1)	18,786			35,839
Allowance for doubtful accounts	(95		)	(415		)
Total accounts receivable, net	$	68,370		$	76,161

_________________

(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.

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

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	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017			Year Ended December 31, 2016
Trade receivables:
Balance at beginning of period	$	415		$	415	$	490		$	1,030
Charged to expense	25			—		(69		)	243
Deductions	(345		)	—		(6		)	(783		)
Balance at end of period	$	95		$	415	$	415		$	490
Related party receivables:
Balance at beginning of period	$	—		$	—	$	—		$	—
Charged to expense(1)	22,438			—		—			—
Deductions	—			—		—			—
Balance at end of period	$	22,438		$	—	$	—		$	—

_________________

(1) At December 31, 2018, receivables, including notes receivable, from HMI were approximately $23.4 million. Upon receiving payment of approximately $1.0 million dollars in 2019, the balance was reduced to $22.4 million. Because HMI disputes it obligations under the promissory notes with us, we established an allowance for doubtful accounts totaling $22.4 million which is included in general and administrative expense in 2018.

NOTE 5 — SUPPLEMENTAL CASH FLOW INFORMATION

	Successor		Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Supplemental cash flow information:
Cash paid for interest	$	47,862	$	1,145	$	47,773	$	74,694
Cash paid for state income taxes, net of refunds	4		—		—		285
Non-cash investing and financing activities:
Increase in asset retirement obligations	5,665		—		4,363		2,719
Asset retirement obligations assumed on purchased properties	—		—		702		—
Increase in accruals or payables for capital expenditures	5,389		4,896		71,995		12,375
Increase in accounts payable to related party for capital expenditures	4,082		—		7,646		—
Increase in withholding tax accruals for share-based compensation	535		—		—		—
Distribution of non-STACK assets, net of liabilities	—		43,482		—		—
Contribution of interests in oil and gas properties	—		—		—		65,740
Contribution receivable	—		—		—		7,875

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

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	Successor		Predecessor
(in thousands)	December 31, 2018		February 8, 2018		December 31, 2017		December 31, 2016
Cash and cash equivalents	$	12,984	$	9,070	$	3,660	$	7,102
Restricted cash	1,001		1,275		1,269		433
Cash from discontinued operations	—		—		61		83
Total cash, cash equivalents and restricted cash	$	13,985	$	10,345	$	4,990	$	7,618

NOTE 6 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES

2018 Activity

On February 9, 2018 (the “Closing Date”), AMR consummated the transactions contemplated by (i) the Contribution Agreement (“AM Contribution Agreement”), dated August 16, 2017, with us, the AM Contributor, High Mesa Holdings GP, LLC, the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor, (ii) the Contribution Agreement (the “KFM Contribution Agreement”), dated August 16, 2017, with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, and, solely for certain provisions therein, the equity owners of the KFM Contributor; and (iii) the Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”), dated August 17, 2017, with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor” and together with the AM Contributor and the KFM Contributor, the “Contributors”).

Pursuant to the Contribution Agreements, SRII Opco, LP, a newly formed subsidiary of AMR (“SRII Opco”) acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP ((i) and (ii) collectively, the “AM Contribution”) and (b) 100% of the economic interests in KFM (the “KFM Contribution”). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “Business Combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions”. We are deemed to be a variable interest entity (“VIE”) and SRII Opco is our primary beneficiary since it controls our general partner, AMH GP, and has the power to direct our activities impacting our performance, as well as holding all of our equity at risk. Accordingly, our results of operations have been consolidated into SRII Opco. Similarly, AMR is the primary beneficiary of SRII Opco and controls SRII Opco, GP, LLC (“SRII Opco GP”), the general partner of SRII Opco. As a result, AMR controls and consolidates SRII Opco, and by extension, us.

KFM is considered a related party affiliate. We do not control or have significant influence over KFM as such control resides with SRII Opco’s general partner, SRII Opco GP. As AMR is the primary beneficiary of SRII Opco and controls SRII Opco GP, KFM’s financial results are also included in the consolidated financial statements of our ultimate parent, AMR.

Pursuant to the Transactions, AMR contributed $554.0 million in net cash to us at the closing of the Business Combination. We used a portion of the amount to repay all outstanding balances under a predecessor senior secured revolving credit facility (the “Alta Mesa Predecessor Credit Facility”).

The Business Combination has been accounted for using the acquisition method resulting in our assets acquired and liabilities assumed being recognized at their fair values as of the acquisition date by AMR, which were then pushed down to us.  

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Purchase Price

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(in thousands)	February 9, 2018 (As initially reported)		Measurement Period Adjustment (1)		February 9, 2018 (As adjusted)
Purchase Consideration:(2)
SRII Opco Common Units issued (3)	$	1,251,782	$	9,467	$	1,261,249
Estimated fair value of contingent earn-out purchase consideration (4)	284,109		—		284,109
Total purchase price consideration	$	1,535,891	$	9,467	$	1,545,358

_________________

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

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

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

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

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Purchase Price Allocation for Alta Mesa

(in thousands)	February 9, 2018 (As initially reported)		Measurement Period Adjustment (1)			February 9, 2018 (As adjusted)
Estimated Fair Value of Assets Acquired(2)
Cash, cash equivalents and restricted cash	$	10,345	$	—		$	10,345
Accounts receivable	101,745		—			101,745
Other receivables	1,222		840			2,062
Receivables due from related party	907		—			907
Prepaid expenses and other	1,405		—			1,405
Derivatives	352		—			352
Property and equipment:(3)
Oil and gas properties, successful efforts	2,314,858		(4,879		)	2,309,979
Other property and equipment, net	43,318		—			43,318
Notes receivable due from related party	12,454		—			12,454
Deposits and other long-term assets	10,286		—			10,286
Total fair value of assets acquired	2,496,892		(4,039		)	2,492,853
Estimated Fair Value of Liabilities Assumed (2)
Accounts payable and accrued liabilities	210,867		(13,506		)	197,361
Accounts payable — affiliate	5,476		—			5,476
Advances from non-operators	6,803		—			6,803
Advances from related party	47,506		—			47,506
Asset retirement obligations (3)	5,998		—			5,998
Derivatives	11,585		—			11,585
Long-term debt(4)	667,700		—			667,700
Other long-term liabilities	5,066		—			5,066
Total fair value of liabilities assumed	961,001		(13,506		)	947,495
Total consideration and fair value	$	1,535,891	$	9,467		$	1,545,358

_________________

(1) The measurement period adjustments were recognized in the reporting period in which the adjustments were determined. The measurement period adjustments relate to a change in the purchase consideration based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 and certain adjustments to beginning balances.

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

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

(4) Represents the approximate fair value as of the acquisition date of (i) Alta Mesa’s $500.0 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million, based on Level 1 inputs, and (ii) outstanding borrowings under the Alta Mesa Predecessor Credit Facility of approximately $134.1 million as of the acquisition date.

Acquisition of acreage

In October 2018, we completed a transaction to acquire certain unproved oil and gas properties from Fenter Energy, LLC for $22.3 million, net of customary post-closing purchase price adjustments.  The acquisition was funded utilizing borrowings under the Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association (the “Alta Mesa RBL”).  

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2017 Activity

In December 2017, we sold our assets located in the Weeks Island field to Texas Petroleum Investment for approximately $22.5 million.

In September 2017, we acquired certain proved oil and gas properties from Brown & Borelli (the “B&B Acquisition”) for $8.2 million, using cash on hand. The fair value of the net assets acquired was approximately $9.9 million. Accordingly, a bargain purchase gain of $1.7 million was recognized at the time of the acquisition. The gain primarily resulted from growth in reserves and value between signing and closing of the transaction.

In July 2017, we acquired oil and gas properties in Oklahoma from an unaffiliated third party for $45.6 million, funded utilizing borrowings under Alta Mesa’ Predecessor credit facility.

2016 Activity

During 2016, we acquired approximately $10.6 million of oil and gas properties in Oklahoma which were primarily related to unevaluated leasehold.

On December 31, 2016, HMI, a related party, purchased from BCE-STACK Development LLC (“BCE”) and contributed interests in 24 producing wells (the “Contributed Wells”) to us.  We recorded HMI’s equity contribution at the fair value of the wells contributed of approximately $65.7 million, plus contributed cash of $11.3 million, of which $7.9 million was collected subsequent to December 31, 2016. 

NOTE 7 — PROPERTY AND EQUIPMENT

	Successor			Predecessor
(in thousands)	December 31, 2018			December 31, 2017
Oil and gas properties
Unproved properties	$	816,282		$	84,590
Accumulated impairment of unproved properties	(742,065		)	—
Unproved properties, net	74,217			84,590
Proved oil and gas properties	2,110,346			1,061,105
Accumulated depreciation, depletion, amortization and impairment	(1,421,226		)	(251,065		)
Proved oil and gas properties, net	689,120			810,040
Total oil and gas properties, net	763,337			894,630
Other property and equipment
Land	5,059			2,912
Fresh water wells	27,366			—
Produced water disposal system	3,608			30,990
Office furniture, equipment and vehicles	2,840			20,008
Accumulated depreciation	(726		)	(21,770		)
Other property and equipment, net	38,147			32,140
Total property and equipment, net	$	801,484		$	926,770

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Depreciation and Depletion Expense

	Successor		Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Oil and gas properties depletion	$	130,439	$	11,021	$	83,537	$	49,481
Other property and equipment depreciation	2,375		609		5,240		4,004
Total depreciation and depletion expense	$	132,814	$	11,630	$	88,777	$	53,485

Sale of Produced Water Assets

In November 2018, we sold our produced water assets, consisting of over 200 miles of produced water gathering pipelines and related facilities, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher Midstream, LLC (“KFM”), a related party and an entity under common control by our parent, AMR, for $98.0 million, including approximately $90.0 million in cash transferred during 2018. The remaining balance owed of approximately $8.0 million is included in related party receivables. No gain or loss was recognized as a result of these transactions. In conjunction with the sale, we entered into a new fifteen-year produced water disposal agreement with KFM. Under that agreement, we recognized expense of $4.7 million during November and December of 2018.

NOTE 8 — DISCONTINUED OPERATIONS (Predecessor)

We distributed our remaining non-STACK oil and gas assets and liabilities to the AM Contributor just prior to the closing of the Business Combination. We have determined that the remaining non-STACK oil and gas assets and liabilities as well as our Weeks Island field sold during the 4th quarter of 2017 are discontinued operations during the Predecessor Periods and have segregated their financial information from ours in the financial statements.

Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bore simple interest at 10%.  The Founder Notes were part of the non-STACK distribution.  The balance of the Founder Notes at the time of conversion was approximately $28.3 million, including accrued interest.  Interest on the Founder Notes was $0.1 million, $1.2 million and $1.2 million for the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, respectively.

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	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
Revenue:
Oil	$	1,617		$	47,218		$	57,866
Natural gas	1,023			10,090			10,932
Natural gas liquids	236			2,359			1,489
Other	16			316			213
Operating revenue	2,892			59,983			70,500
Loss on sale of assets	(1,923		)	(22,207		)	3,539
Gain on acquisition of oil and gas properties	—			1,626			—
Total revenue	969			39,402			74,039
Operating expenses:
Lease operating	1,770			27,763			29,474
Transportation and marketing	83			1,354			1,698
Production taxes	167			6,730			7,985
Workover	127			2,088			1,273
Exploration	—			11,431			7,547
Depreciation, depletion and amortization	884			24,519			41,320
Impairments of assets	5,560			29,129			15,924
General and administrative	21			82			1,290
Total operating expenses	8,612			103,096			106,511
Other income (expense)
Interest expense	(103		)	(1,209		)	(1,209		)
Interest income and other	—			88			10
Total other income (expense)	(103		)	(1,121		)	(1,199		)
Income tax provision (benefit)	—			—			(29		)
Loss from discontinued operations, net of state income taxes	$	(7,746	)	$	(64,815	)	$	(33,642	)

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	Predecessor
(in thousands)	December 31, 2017
Assets associated with discontinued operations:
Current assets
Cash	$	61
Accounts receivable	4,980
Other receivables	154
Total current assets	5,195
Noncurrent assets
Investments	9,000
Oil and gas properties, net	33,618
Other long-term assets	1,167
Total noncurrent assets	43,785
Total assets associated with discontinued operations	$	48,980
Liabilities associated with discontinued operations:
Current liabilities
Accounts payable and accrued liabilities	$	7,882
Asset retirement obligations	7,537
Total current liabilities	15,419
Noncurrent liabilities
Asset retirement obligations, net of current portion	37,049
Founder Notes	28,166
Other long-term liabilities	1,647
Total noncurrent liabilities	66,862
Total liabilities associated with discontinued operations	$	82,281

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017		Year Ended December 31, 2016
Total operating cash flows of discontinued operations	$	2,974		$	21,138	$	31,255
Total investing cash flows of discontinued operations	(601		)	6,891		(14,378		)

NOTE 9 — FAIR VALUE MEASUREMENTS

Recurring measurements

We utilize 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 include 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.

Non-recurring measurements

In connection with the Business Combination, we recorded the fair value of our $500.0 million unsecured senior notes (“the 2024 Notes”) at $533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $312.5 million at December 31, 2018, based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination.

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Oil and gas properties are subject to impairment testing and potential impairment based largely on future estimated cash flows determined using Level 3 inputs.

	Successor						Predecessor
	December 31, 2018						December 31, 2017
(in thousands)	Original Carrying Value		Estimated Fair Value		Impairment		Original Carrying Value		Estimated Fair Value		Impairment
Unproved oil and gas properties	$	816,282	$	74,217	$	742,065	$	—	$	—	$	—
Proved oil and gas properties	1,895,670		604,023		1,291,647		3,350		2,162		1,188
Total	$	2,711,952	$	678,240	$	2,033,712	$	3,350	$	2,162	$	1,188

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 10 — DERIVATIVES

We have entered into derivatives to reduce our exposure to price risk for oil and gas. Substantially all of our derivatives are executed by lenders under the Alta Mesa RBL, and are collateralized by the security interests thereunder. The derivatives settle monthly. No derivatives have been entered into for trading or speculative purposes, however none have been designated as hedges under GAAP.

From time to time, we may enter into interest rate swap agreements to mitigate the risk of changes in interest rates, but as of December 31, 2018, we have none.

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

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

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

	December 31, 2017 (Predecessor)
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	$	1,406	$	(1,190	)	$	216
Derivatives, long-term assets	3,010		(3,002		)	8
Total	$	4,416	$	(4,192	)	$	224

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Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	20,493	$	(1,190	)	$	19,303
Derivatives, long-term liabilities	4,116		(3,002		)	1,114
Total	$	24,609	$	(4,192	)	$	20,417

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

	Successor			Predecessor
	February 9, 2018			January 1, 2018
Derivatives not	Through			Through		Year Ended			Year Ended
designated as hedges	December 31, 2018			February 8, 2018		December 31, 2017			December 31, 2016
Gain (loss) on derivatives -
Oil commodity contracts	$	(3,559	)	$	4,796	$	1,450		$	(36,572	)
Natural gas commodity contracts	(6,688		)	1,867		7,288			(2,410		)
Natural gas liquids commodity contracts	—			—		(451		)	(1,478		)
Total gain (loss) on derivatives	$	(10,247	)	$	6,663	$	8,287		$	(40,460	)

Other receivables at December 31, 2018 and 2017 include $1.3 million and $1.4 million, respectively, of derivative positions covering the month of December scheduled to be settled in January of the succeeding year.

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

We had the following call and put derivatives at December 31, 2018:

OIL

	Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	182,500	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	2,701,000	66.31		75.20		56.50
Long Put Options	2,883,500	53.80		62.00		50.00
Short Put Options	2,883,500	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	585,600	64.32		73.80		59.55
Long Put Options	1,537,200	55.54		62.50		50.00
Short Put Options	1,537,200	44.64		50.00		37.50

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GAS

	Volume in	Weighted		Range
Settlement Period and Type of Contract	MMBtu	Average		High		Low
2019
Price Swap Contracts	10,905,000	$	2.69	$	3.09	$	2.64
Collar Contracts
Short Call Options	4,000,000	3.31		3.75		3.17
Long Put Options	3,550,000	2.81		2.90		2.70
Short Put Options	2,425,000	2.27		2.40		2.20
2020
Collar Contracts
Short Call Options	2,275,000	3.19		3.20		3.17
Long Put Options	9,150,000	2.57		2.70		2.50
Short Put Options	9,150,000	2.07		2.20		2.00
2021
Collar Contracts
Long Put Options	2,250,000	2.65		2.65		2.65
Short Put Options	2,250,000	2.15		2.15		2.15

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

We had the following basis swaps at December 31, 2018:

Total Gas Volumes in MMBtuover Remaining Term(1)	Reference Price 1 (1)	Reference Price 2 (1)	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
17,950,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '19	—	Dec '19	(0.68		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
2,365,000	San Juan	NYMEX Henry Hub	Jan '19	—	Oct '19	(0.78		)

________________

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

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NOTE 11 — ASSET RETIREMENT OBLIGATIONS 

				Predecessor
(in thousands)	2018			2017
Balance, as of January 1 (Predecessor)	$	10,469		$	8,400
Liabilities settled	(63		)
Revisions to estimates	63
Accretion expense	39
Balance, as of February (Predecessor)	$	10,508
Balance, beginning of year (Successor)(1)	$	5,998		—
Liabilities assumed	—			604
Liabilities incurred	2,536			1,583
Liabilities settled	(1,610		)	(119		)
Liabilities transferred via sale	(383		)	—
Revisions to estimates	4,130			(337		)
Accretion expense	738			338
Balance, as of December 31	11,409			10,469
Less: Current portion	2,079			69
Long-term portion	$	9,330		$	10,400

_________________

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

NOTE 12 — LONG TERM DEBT, NET

໿

	Successor		Predecessor
(in thousands)	December 31, 2018		December 31, 2017
Alta Mesa RBL	$	161,000	$	—
Alta Mesa Predecessor Credit Facility	—		117,065
2024 Notes	500,000		500,000
Unamortized premium on 2024 notes	29,123		—
Unamortized deferred financing costs	—		(9,625		)
Total long-term debt, net	$	690,123	$	607,440

Alta Mesa RBL

In connection with the Business Combination, we entered into the Alta Mesa RBL which features a face amount of $1.0 billion and had an initial $350.0 million borrowing base.  In April 2018, the borrowing base was increased to $400.0 million, which was reaffirmed by the lenders during the fourth quarter of 2018. Drawing on the Alta Mesa RBL requires us to be in compliance with the covenants on a current and pro forma basis. As of December 31, 2018, in addition to $161.0 million of borrowings outstanding, we also had $21.9 million of outstanding letters of credit, leaving a total borrowing capacity of $217.1 million available for future use at that time. On April 1, 2019, the borrowing base was reduced to $370.0 million upon completion of the regularly scheduled semiannual redetermination.

The facility matures in February 2023 and is subject to semiannual redeterminations. We may borrow in Eurodollars or at a reference rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, plus a margin ranging from 2.00% to 3.00%. Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s prime rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus a margin ranging from 1.00% to 2.00%.

The amounts outstanding are secured by first priority liens on substantially all of our upstream oil and gas properties and all of the equity of our material guarantor subsidiaries. Additionally, SRII Opco and Alta Mesa GP have pledged their respective partner interests in us as security.

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Restrictive covenants may limit 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, amend organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders.

The Alta Mesa RBL has two covenants that are tested quarterly according to the definitions and provisions thereunder:

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

• a ratio of our consolidated debt to our consolidated EBITDAX of not greater than 4.0 to 1.0. Through December 31, 2018 we were able to annualize cumulative Successor Period results in measuring EBITDAX. 

We are currently in default under the Alta Mesa RBL for our failure to provide certain information by May 15, 2019 for the fiscal quarter ended March 31, 2019. The default can be cured by providing the information by June 14, 2019.

Predecessor Credit Facility

As of December 31, 2017, we had $117.1 million of borrowings outstanding, which were paid in full at the time of the Business Combination.

2024 Notes

Our 2024 Notes have a face value of $500.0 million and bear interest at 7.875% per annum. The 2024 Notes were issued at par during the 4th quarter of 2016 in a private placement but were exchanged for substantially identical registered senior notes in November 2017. 

The 2024 Notes mature in December 2024 with interest payable semi-annually on June 15 and December 15. Before December 2019, we may redeem up to 35% of the 2024 Notes using proceeds from equity offerings at a redemption price of 107.875% of principal under specified conditions. Before December 2019, we otherwise may redeem the 2024 Notes at their principal amount plus an applicable make-whole premium.

On and after December 15, 2019, we may redeem the 2024 Notes, in whole or in part, at the following redemption prices plus accrued and unpaid interest, if any, to the date of redemption:

	After December 15
	2019		2020		2021		2022
Redemption price as a percentage of principal amount	105.906	%	103.938	%	101.969	%	100	%

The 2024 Notes are guaranteed by each of our subsidiaries and rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future subordinated indebtedness; effectively subordinated to all of our existing and future 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 our subsidiaries that do not guarantee the 2024 Notes.

The 2024 Notes contain certain covenants limiting our ability to prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on our assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business.  

Upon certain changes of control, the terms of the notes may require us to redeem them at 101% of the principal amount. The Business Combination did not constitute a change in control for the 2024 Notes. 

If an event of default occurs, all outstanding amounts may become due and payable.

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Bond Premium

The fair value of the 2024 Notes as of the Business Combination was $533.6 million yielding a bond premium of $33.6 million Amortization of the premium reduced our interest expense by $4.5 million during the Successor Period.

Maturities of Long-Term Debt (Successor)

Fiscal Year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	161,000
Thereafter	500,000
	$	661,000

Deferred Financing Costs

As of December 31, 2017, we had $11.4 million of deferred financing costs related to both the 2024 Notes and the Predecessor Credit Facility. Pursuant to the Business Combination, the unamortized deferred financing costs were adjusted to a fair value of zero.  During the Successor Period, we incurred additional deferred financing costs related to the Alta Mesa RBL of $1.4 million. For the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, the amortization of deferred financing costs was $0.2 million, $0.2 million, $2.7 million, and $3.9 million, respectively. 

NOTE 13 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 

໿

	Successor		Predecessor
(in thousands)	December 31, 2018		December 31, 2017
Accounts payable	$	20,200	$	68,578
Accruals for capital expenditures	101,214		48,771
Revenue and royalties payable	46,870		29,514
Accruals for operating expenses	16,355		14,632
Accrued interest	1,784		2,587
Derivative settlements	109		2,106
Other	10,532		4,301
Total accrued liabilities	176,864		101,911
Accounts payable and accrued liabilities	$	197,064	$	170,489

NOTE 14 — COMMITMENTS AND CONTINGENCIES 

Commitments

Office and Equipment Leases

We lease office space and certain field equipment under long-term operating lease agreements. For the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017, and 2016, total net lease payments, was approximately $7.8 million, $0.1 million, $7.8 million, and $3.6 million, respectively.

At December 31, 2018, we have the remaining future minimum lease payments:

89

Fiscal Year	In thousands
2019	$	2,819
2020	2,851
2021	2,911
2022	3,107
2023	3,038
Thereafter	12,219
	$	26,945

Gas Processing Reservation Commitment

We entered into an agreement with KFM to reimburse half of the expenses associated with any shortfall in committed volumes not physically delivered. The amounts below represent the total maximum cash payment required if KFM does not deliver to a third party for processing. This commitment extends through 2021 with the following commitments at December 31, 2018:

Fiscal Year	In thousands
2019	$	1,551
2020	1,556
2021	1,551
	$	4,658

During the period February 9, 2018 through December 31, 2018, cash payments required under our commitments totaled approximately $0.1 million.

Firm Natural Gas Transportation Commitments

We have entered into certain firm commitments intended to secure capacity on third party pipelines for transportation of our natural gas that extend through 2028 with the following commitments at December 31, 2018:

Fiscal Year	In thousands
2019	$	12,236
2020	12,236
2021	12,236
2022	12,236
2023	12,236
Thereafter	25,023
	$	86,203

Contingencies

Environmental claims

Various landowners have sued Alta Mesa in lawsuits concerning several fields in which Alta Mesa’s subsidiaries have, or historically had, operations.  The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from its oil and gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our consolidated financial statements at December 31, 2018.

Title/lease disputes

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

Litigation

On January 30, 2019, AMR, James T. Hackett, AMR’s interim Chief Executive Officer and Chairman of the Board, certain of AMR’s former and current directors, Thomas J. Walker, AMR’s 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.

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 and Michael A. McCabe, AMR’s former President and Chief Executive Officer and Chief Financial Officer, respectively. These complaints are 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 AMR and certain of its current and former officers on behalf of all persons or entities who purchased or otherwise acquired Silver Run or AMR securities between March 24, 2017, and February 25, 2019. The new claims are based upon alleged misstatements contained in AMR’s proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants.

The outcome of the above securities class action complaints is uncertain, and while we believe that AMR has 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. We are not a party to these suits but an adverse outcome could potentially impact our business.

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.

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 (a subsidiary of HMI), us, 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, we stipulated with respect to Biloxi that we 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 we distributed to a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Consequently, we believe that any potential damages incurred by us 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 us or Meridian. In addition, our ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI. 

SEC Investigation

The SEC is conducting a formal investigation into, among other things, the facts involved in the material weakness in our internal controls over financial reporting and the impairment charge disclosed previously and in this annual report. 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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Other contingencies

We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes cannot be reasonably estimated; however, in our opinion, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. 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 remaining amounts due under the plan at the time of the Business Combination, but recognized and paid $10.9 million as strategic costs in G&A during the Successor Period.

NOTE 15 — SIGNIFICANT CONCENTRATIONS 

We have an agreement with ARM pursuant to which they market our oil, gas and NGLs. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. ARM collects payments from purchasers, deducts their fee and remits the balance to us. In addition, ARM markets our firm transportation on the ONEOK Gas Transportation, L.L.C. system and the Panhandle Eastern Pipeline Company, LP system for a management fee. The AM Contributor owns 10% of ARM. During the Successor Period, we paid ARM $1.4 million for our share of the marketing fees. Receivables from ARM for sales on our behalf were $38.4 million and $22.4 million as of December 31, 2018 and 2017, respectively.  During the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, sales managed by ARM on our behalf were $309.7 million, $28.8 million, $199.2 million and $114.8 million, respectively.

Additionally, ARM provides us with strategic advice, execution and reporting services with respect to our derivatives activities. Fees paid to ARM for these services were $0.8 million, $0.1 million, $0.8 million and $1.9 million during the Successor Period, 2018 Predecessor Period, 2017 and 2016, respectively.

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 16 — EMPLOYEE BENEFIT PLANS 

AMR sponsors a 401(k) savings plan, whereby our employees can elect to make contributions pursuant to a salary reduction agreement. We make matching contributions equal to 100% of the first 5% of an employee’s contributions. Employee contributions are immediately vested whereas company matching contributions vest 50% after two years and become fully vested at the end of three years. Matching contributions to the plan were approximately $1.0 million, $0.3 million, $1.2 million, and $1.1 million for the Successor Period, the 2018 Predecessor Period, 2017 and 2016, respectively.

NOTE 17 — SIGNIFICANT RISKS AND UNCERTAINTIES 

Our business makes us vulnerable to changes in wellhead prices of oil and gas.  Historically, world-wide oil and gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, spot and future estimated commodity prices declined sharply during the fourth quarter of 2018. Prices for oil and gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and gas, as well as market uncertainty, economic conditions and a variety of additional factors.  The duration and magnitude of changes in oil and gas prices cannot be predicted.  Sustained low oil or gas prices may require us to further write down the value of our oil and gas properties and/or revise our development plans, which may cause certain undeveloped well locations to be less valuable. This could cause a reduction in the borrowing base under our credit facilities to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into derivatives.

NOTE 18 — PARTNERS’ CAPITAL

Partnership Management and Control

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

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

NOTE 19 — EQUITY-BASED COMPENSATION (Successor)

Certain of our employees are eligible to participate in the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”).  A total of 50,000,000 shares of AMR’s Class A Common Stock are reserved for issuance under the LTIP.  The LTIP provides 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 (“RSUs”) and other awards in AMR’s Class A Common Stock.  Prior to the Business Combination, we had no equity-based compensation programs. During the Successor Period, the Company recognized stock-based compensation expense of $20.0 million in general and administrative expense including accelerated vesting for separated executives related to the LTIP.  

Stock options

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

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	Successor
	Stock Options		Weighted Average Exercise Price		Weighted Average Grant-Date Fair Value		Weighted Average Remaining Term (Years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of February 9, 2018	—		$	—	$	—	—	$	—
Granted	4,840,799		8.90		4.37		—	—
Exercised	—		—		—		—	—
Forfeited or expired	(134,956	)	9.37		4.55		—	—
Outstanding as of December 31, 2018	4,705,843		8.89		4.36		5.2	—
Vested at December 31, 2018 or expected to vest in future	4,705,843		8.89		4.36		5.2	—
Exercisable as of December 31, 2018	1,509,434		$	9.54	$	4.62	3.0	$	—

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

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

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Unrecognized compensation cost related to non-vested stock options at December 31, 2018 was $9.8 million, which we expect to recognize over a weighted average remaining period of 2.2 years.

Restricted stock

Restricted stock granted to employees generally vests in one-third increments each year based on continued employment. Prior to vesting, unvested restricted stock may not be traded.

The following table provides information about restricted stock awards granted during the Successor Period:

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	Successor
	Restricted Stock Awards		Weighted Average Grant Date Fair Value per share
Outstanding as of February 9, 2018	—		$	—
Granted	1,720,949		7.61
Vested (1)	(286,214	)	8.38
Forfeited or expired	(59,980	)	8.80
Outstanding as of December 31, 2018	1,374,755		$	7.39

_________________

(1) To satisfy minimum tax withholding, 94,576 shares were withheld.

Unrecognized compensation cost related to unvested restricted shares at December 31, 2018 was $7.3 million, which we expect to recognize over a weighted average remaining period of 2.2 years.

Restricted stock units

Employees were also granted performance-based restricted stock units (“PSUs”) under the LTIP. PSUs granted in 2018 generally vest over three years at 20% during the first year, 30% during the second year and 50% during the third year. The number of PSUs vesting each year will be based on the achievement of annual company-specified performance goals and objectives applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that vest can range from 0% to 200% of the target grant applicable to each vesting period. We only recognize expense for PSUs when the specified performance thresholds for future periods have been established. For PSUs granted during the 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. No amounts will be recognized for the 2019 and 2020 performance periods until the specific targets have been established and probability of attainment can be measured.

The following summary provides information about the target number of PSUs granted during the Successor Period:

	Successor
	Restricted Stock Units			Weighted Average Grant - Date Fair Value per unit
Outstanding as of February 9, 2018	—			$	—
Granted	2,049,105			3.99
Vested (1)	(1,559,749	)		2.53
Forfeited or expired	(489,356	)		(8.61		)
Outstanding as of December 31, 2018	—		—	$	—

_________________

(1) To satisfy minimum tax withholding, 388,655 shares were withheld.

As of December 31, 2018, there was no unrecognized compensation cost related to unvested PSUs.

NOTE 20 — RELATED PARTY TRANSACTIONS 

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On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM. The Gas Gathering and Processing Agreement was subsequently amended in February 2017, effective December 2016 and again in June 2018, effective April 2018. The more recent amendment to the Gas Gathering and Processing Agreement impacts our ability to make elections with respect to the NGL portion of our production volumes but has no other effect on our consolidated financial statements.

In November 2018, we sold our produced water assets, consisting of over 200 miles of produced water gathering pipelines and related facilities, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher, a related party and an entity under common control by our parent, AMR, for $98.0 million, including approximately $90.0 million in cash transferred during 2018. The remaining balance owed of approximately $8.0 million is included in related party receivables. In conjunction with the sale, we entered into a new fifteen-year produced water disposal agreement with KFM. Under that agreement, we recognized expense of $4.7 million during November and December of 2018.  

On September 21, 2016, we entered into an agreement with Kingfisher that beginning January 1, 2017 through January 31, 2022, we shall reimburse Kingfisher for 50% of any shortfall fee paid by Kingfisher to Superior Pipeline Company, LLC, a third party gas processor.  During the period February 9, 2018 through December 31, 2018, cash payments required under our commitments totaled approximately $0.1 million.

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David -Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $166,000, $28,000, $186,000 and $146,000 for the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, respectively. Following termination of the contract, Brigid Murrell continued to provide services to the Company as an individual contractor and was paid $8,523 for services rendered in that capacity through December 31, 2018. These amounts are recorded in general and administrative expenses.

David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of approximately $1,157,774, $28,874, $250,000, and $425,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively. These amounts are included in general and administrative expense.

David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of approximately $297,134, $67,322, $150,000, and $180,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively. These amounts are included in general and administrative expense.

Bayou City Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of Alta Mesa’s drilling operations and to allow Alta Mesa to accelerate development of our STACK acreage. The JDA establishes a development plan of 60 wells in three tranches, and provides opportunities for the parties to potentially agree to an additional 20 wells. Pursuant to the terms and provisions of the JDA, BCE committed to fund 100% of Alta Mesa’s working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for carrying the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return on each individual tranche. Following the completion of each joint well, Alta Mesa and BCE will each bear its respective proportionate working interest share of all subsequent costs and expenses related to such joint well.  Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time.  During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of December 31, 2018, 61

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joint wells have been drilled or spudded. As of December 31, 2018 and 2017, $9.8 million and $23.4 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our consolidated balance sheets. At December 31, 2018, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA.

High Mesa

In September 2017, we entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured in February 2019. At December 31, 2018 and 2017, amounts due under the promissory note totaled $1.7 million and $1.5 million, respectively. 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. We subsequently declared all amounts owing under the note immediately due and payable. We also have 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, 2018 and 2017, the note receivable amounted to $11.7 million and $10.8 million, respectively. HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to us. We oppose HMI’s claims and believe HMI’s obligation under the notes to be our valid assets and that the full amount is payable to us. We intend to pursue all available 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 directors of AMR who are also controlling holders and directors of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2018, 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, $0.1 million, $0.9 million, and $0.8 million for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively, all recorded as paid-in-kind and added to the balance due thereunder.

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. Under the High Mesa Agreement, during the 180-day period following the Closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000, (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the High Mesa Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services from 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 High Mesa 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 High Mesa Agreement, and pursuant to the High Mesa Agreement as “Receivables due from related party” in the balance sheets. As of December 31, 2018 (Successor) and December 31, 2017 (Predecessor), we had receivables of approximately $10 million and $0.8 million for costs and expenses incurred on HMI’s behalf. Subsequent to year-end, we billed HMI $0.9 million for incremental MSA costs incurred and have received approximately $1.0 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result, we have recognized an allowance for uncollectible accounts of $9.0 million to fully provide for the unremitted balance and may have future allowances for amounts incurred in 2019 prior to the termination of the MSA. 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.

NOTE 21 — SUBSIDIARY GUARANTORS 

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All of our wholly owned subsidiaries are guarantors under the terms of our 2024 Notes and the RBL. The guarantees are full and unconditional (except for customary release provisions) and are joint and several. Our consolidated financial statements reflect the financial position of these subsidiary guarantors.

NOTE 22 — SUBSEQUENT EVENTS

We implemented a reduction in force in 2019 that will cause us to incur approximately $4.7 million of expense in the first quarter and approximately $1.2 million of expense in the second quarter. This action also resulted in a partial termination of AMR’s 401(k) savings plan, which will accelerate vesting for those employees that were impacted by the reduction in force to the extent they were not already vested in our matching contributions.

NOTE 23 — SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited) 

	Predecessor			Successor
2018 (in thousands)	January 1, 2018 Through February 8, 2018			February 9, 2018 Through March 31, 2018			June 30			Sept 30		Dec 31
Total revenue	$	47,639		$	34,090		$	66,459		$	122,873	$	185,589
Income (loss) from continuing operations (1)(2)(3)	(7,116		)	(34,571		)	(22,477		)	17,844		(2,037,170		)
Income (loss) from discontinued operations	(7,746		)	—			—			—		—
Net income (loss)(1)(2)(3)	(14,862		)	(34,571		)	(22,477		)	17,844		(2,037,170		)

_________________

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(1) Includes$2.0 billion of impairment expense during the quarter ended December 31, 2018.

(2) Includes $6.7 million and $52.8 million of gains on derivatives during the 2018 Predecessor Period and the quarter ended December 31, 2018, respectively. Includes $22.6 million, $29.2 million and $11.2 million of losses on derivatives during the period from February 9, 2018 through March 31, 2018, and during the quarters ended June 30, 2018 and September 30, 2018, respectively.

(3) Includes $6.0 million gain primarily from the sale of seismic data during the period from February 9, 2018 through March 31, 2018.

	Predecessor
2017 (in thousands)	March 31			June 30			Sept 30			Dec 31
Total revenue(1)(2)	$	95,079		$	79,800		$	57,923		$	46,567
Income (loss) from continuing operations (1)(2)(3)	29,430			15,620			(22,163		)	(35,733		)
Loss from discontinued operations(4)	(4,515		)	(30,934		)	(2,041		)	(27,325		)
Net income (loss)	24,915			(15,314		)	(24,204		)	(63,058		)

_________________

(1) Includes $30.2 million and $18.3 million of gains on derivatives during quarters ended March 31, 2017 and June 30, 2017, respectively, and $10.5 million and $29.7 million of losses on derivatives during the quarters ended September 30, 2017 and December 31, 2017, respectively.

(2) Includes $5.3 million gain on acquisition of oil and gas properties during the quarter ended September 30, 2017, which was reduced by $3.6 million during the quarter ended December 31, 2017.

(3) Includes $1.2 million of impairment expense during the quarter ended March 31, 2017.

(4) The quarter ended December 31, 2017 includes a loss on the sale of assets of $22.2 million, primarily associated with the sale of Weeks Island.

NOTE 24 — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

During January 2019, we finalized our development plan for the next five years and received an audit report from our outside engineers that agreed with our recognition of PUDs for the majority of that future development. During April 2019, in finalizing our financial reporting for 2018, we determined that we may fail to satisfy the leverage covenant under the Alta Mesa RBL during 2019. Accordingly, we were unable to conclude that we would have continuing access to that capital source in the event of a failure of the leverage covenant. Thus, we concluded that we did not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our future drilling locations and did not recognize any proved undeveloped locations in our final December 31, 2018 reserve report. Should our ability to fund the required development costs improve in the future, we expect to recognize all or a portion of those resources as proved.

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The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235.  The information presented during the Predecessor Periods 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. Under our gathering contract with KFM, we have options regarding how we accept or reject ethane volumes. Our reserve disclosures that follow assume that we recover (rather than reject) ethane volumes, which generally has the effect of increasing the reserves, with no corresponding increase to value or future cash flow.

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 the Successor Period, the 2018 Predecessor Period, the years ended December 31, 2017 and 2016, and the changes therein during the periods then ended. Proved oil and gas reserves are the estimated quantities of crude oil, gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the dates the estimates were made).

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	Oil (Mbbls)		Gas (MMcf)		NGL’s (Mbbls)		Boe (Mbbls)
Total Proved Reserves:
Balance at December 31, 2015 (Predecessor)	34,142		155,423		18,437		78,483
Production	(4,001	)	(13,959	)	(956	)	(7,284	)
Purchases in place(1)	1,508		6,754		613		3,247
Discoveries and extensions	29,903		154,653		14,000		69,679
Sales of reserves in place	(73	)	(966	)	(10	)	(244	)
Revisions of previous quantity estimates and other	(3,680	)	14,100		(3,794	)	(5,124	)
Balance at December 31, 2016 (Predecessor)	57,799		316,005		28,290		138,757
Production	(4,850	)	(18,218	)	(1,387	)	(9,274	)
Purchases in place	725		4,860		401		1,936
Discoveries and extensions	20,135		108,676		9,640		47,888
Sales of reserves in place	(3,622	)	(1,280	)	—		(3,836	)
Revisions of previous quantity estimates and other	3,331		23,476		(57	)	7,187
Balance at December 31, 2017 (Predecessor)	73,518		433,519		36,887		182,658
Production	(521	)	(1,984	)	(161	)	(1,012	)
Purchases in place	—		—		—		—
Discoveries and extensions	—		—		—		—
Sales of reserves in place(2)	(1,667	)	(24,239	)	(771	)	(6,478	)
Revisions of previous quantity estimates and other	375		3,506		289		1,248
Balance at February 8, 2018 (Predecessor)	71,705		410,802		36,244		176,416
Production	(5,053	)	(16,913	)	(2,268	)	(10,140	)
Purchases in place(3)	2,658		13,331		1,751		6,631
Discoveries and extensions(3)	30,026		155,306		19,646		75,557
Sales of reserves in place	—		—		—		—
Revisions of previous quantity estimates and other(3)(4)	(74,064	)	(418,378	)	(35,581	)	(179,375	)
Balance at December 31, 2018 (Successor)	25,272		144,148		19,792		69,089
Proved Developed Reserves:
Balance at December 31, 2015	14,942		71,752		6,958		33,859
Balance at December 31, 2016	16,832		93,361		7,977		40,371
Balance at December 31, 2017	20,347		150,183		12,180		57,557
Balance at February 8, 2018	19,345		126,231		11,348		51,731
Balance at December 31, 2018	25,272		144,148		19,792		69,089
Proved Undeveloped Reserves:
Balance at December 31, 2015	19,200		83,671		11,479		44,624
Balance at December 31, 2016	40,967		222,644		20,313		98,386
Balance at December 31, 2017	53,171		283,336		24,707		125,101
Balance at February 8, 2018	52,360		284,571		24,896		124,685
Balance at December 31, 2018	—		—		—		—

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(1) Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from HMI.

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

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(3) 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 have removed all of our PUDs from our total estimated proved reserves. Discoveries and extensions and purchases in place during the 2018 Successor Period include approximately 47,092 MBoe in PUDs, and this amount is also included with our negative revisions and is consequently removed from our total proved reserves at December 31, 2018.

(4) In addition to removing PUDs, we lowered our estimate of proved reserves at December 31, 2018 by approximately 101,516 MBoe, largely due to results of the 2018 drilling program demonstrating lower estimated recovery per 640-acre section. Partially offsetting this was an increase in recoverable reserves of approximately 11,196 MBoe, due mainly to higher average commodity prices in 2018 as compared to 2017.

Results of Operations for Oil and Gas Producing Activities

	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017		Year Ended December 31, 2016
Operating revenue	$	414,507		$	40,136		$	269,386	$	142,356
Production expense (1)	247,748			30,743			138,833		87,869
Depreciation, depletion and amortization	133,554			11,670			89,115		53,755
Exploration expense	34,085			7,003			13,563		17,230
Impairment expense	2,033,712			—			1,188		382
Income tax expense (benefit)	4			—			6		—
Results of operations	$	(2,034,596	)	$	(9,280	)	$	26,681	$	(16,880	)

________________

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

Capitalized Costs Relating to Oil and Gas Producing Activities

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	December 31,
(in thousands)	Successor 2018			Predecessor 2017(1)
Capitalized costs:
Proved properties	$	2,110,346		$	1,545,963
Unproved properties	816,282			116,787
Total	2,926,628			1,662,750
Accumulated depreciation, depletion, amortization and impairment	(2,163,291		)	(711,275		)
Net capitalized costs	$	763,337		$	951,475

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(1) Includes amounts related to non-STACK assets distributed in the 2018 Predecessor Period and reflected as discontinued operations.

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.

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	Successor		Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Costs incurred during the period: (1)
Property acquisition
Unproved (2)	$	54,587	$	4,240	$	88,378	$	66,788
Proved (3)	16,300		327		11,704		68,478
Exploration	32,130		3,678		26,836		28,480
Development (4)	664,138		37,672		351,570		165,796
	$	767,155	45,917		$	478,488	$	329,542

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(1) Costs incurred in all Predecessor Periods include amounts related to non-STACK oil and gas assets, which were distributed in connection with the Business Combination. Costs incurred in 2017 include amounts related to the Weeks Island field and other assets, all of which are classified as discontinued operations.

(2) Property acquisition costs for unproved properties include the acquisition of unevaluated leasehold portion from an unaffiliated third party of approximately $22.3 million and $45.6 million for the 2018 Successor Period and the year ended December 31, 2017, respectively.

(3) Property acquisition costs for proved properties in 2016 include the transfer of Contributed Wells by our former Class B partner to us of $65.7 million.

(4) Includes asset retirement additions (revisions) of $5.6 million, $4.4 million, and $1.9 million for the Successor Period, and years ended December 31, 2017 and 2016, respectively. For the 2018 Predecessor Period, there were no material asset retirement additions (revisions).

Standardized Measure of Discounted Future Net Cash Flows

The following information utilizes reserve and production data prepared by us. Future cash inflows were calculated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month, for the Successor Period, the 2018 Predecessor Period, and for the years ended December 31, 2017 and 2016. Well costs, operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. 

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

	Successor			Predecessor
(in thousands, except per unit data)	December 31, 2018			February 8, 2018			December 31, 2017			December 31, 2016
Future cash inflows	$	2,446,888		$	5,798,886		$	5,799,753		$	3,547,130
Future production costs	(1,214,479		)	(2,556,361		)	(2,617,476		)	(1,811,683		)
Future development costs	(23,183		)	(965,780		)	(1,035,481		)	(709,738		)
Future income taxes	—			—			—			—
Future net cash flows(1)	1,209,226			2,276,745			2,146,796			1,025,709
Discount to present value at 10 percent per annum	(396,375		)	(1,096,859		)	(1,040,874		)	(467,101		)
Standardized measure of discounted future net cash flows	$	812,851		$	1,179,886		$	1,105,922		$	558,608
Base price for crude oil, per barrel, in the above computation	$	65.56		$	52.89		$	51.34		$	42.75
Base price for natural gas, per MMBtu, in the above computation	$	3.10		$	2.99		$	2.98		$	2.49
Realized price for NGLs, per barrel, in the above computation	$	22.44		$	27.48		$	26.06		$	15.18

Changes in Standardized Measure of Discounted Future Net Cash Flows

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	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
Balance at beginning of period	$	1,179,886		$	1,105,922		$	558,608		$	629,596
Sales and transfers of oil and gas produced, net of production costs	(278,091		)	(30,391		)	(202,232		)	(124,610		)
Net changes in prices and production costs	38,963			71,334			354,900			(324,638		)
Revisions of previous quantity estimates(1)	(1,120,097		)	10,887			(12,106		)	(35,972		)
Purchases of reserves in-place	24,376			—			11,483			40,611
Sales of reserves in-place(2)	—			(4,807		)	(20,423		)	2,345
Current year discoveries and extensions, less related costs	684,700			—			513,012			356,631
Changes in estimated future development costs	(39,069		)	491			(5,869		)	849
Development costs incurred during the period	160,583			—			26,317			8,363
Accretion of discount	117,989			110,592			55,861			62,960
Net change in income taxes	—			—			—			—
Change in production rate (timing) and other	43,611			(84,142		)	(173,629		)	(57,527		)
Net change	(367,035		)	73,964			547,314			(70,988		)
Balance at end of period	$	812,851		$	1,179,886		$	1,105,922		$	558,608

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(1) Our revisions include approximately $250.0 million of proved undeveloped reserves that were removed at December 31, 2018 due to our subsequent determination of substantial doubt about our ability to continue as a going-concern and the impact on our ability to fund the costs associated with developing those reserves.

(2) The sale of reserves in-place during the 2018 Predecessor Period includes the sale of non-STACK properties, and in 2017 the sale of Weeks Island Field and other assets, all of which are reflected as discontinued operations in the Company’s consolidated financial statements.

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

Change of Independent Registered Public Accounting Firm

In July 2018, AMR’s Audit Committee approved the engagement of KPMG LLP (“KPMG”) as the Company’s independent registered public accounting firm for the year ending December 31, 2018. In connection with KPMG’s appointment, BDO USA, LLP (“BDO”) was informed in July 2018 that it was dismissed as AMH’s independent registered public accounting firm. BDO was the independent auditor of the Predecessor consolidated financial statements for the fiscal years ended December 31, 2017 and 2016.

During the period from BDO’s appointment through July 6, 2018, the date of BDO’s replacement, there were no disagreements with BDO on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreement, had it not been resolved to the satisfaction of BDO, would have caused BDO to make reference thereto in its reports on the financial statements for such periods. During the same periods, there have been no “reportable events,” as that term is described in Item 304(a)(1)(v) of Regulation S-K.

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.

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We have concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to existence of material weakness in our internal control over financial reporting (“ICFR”) described below.

In light of material weakness in our ICFR, we performed extensive additional analysis and other effort to ensure that our consolidated financial statements included in this Form 10-K were prepared in accordance with US GAAP. Following such additional analysis and procedures, our management, including our principal executive officer and principal financial officer, has concluded that our consolidated financial statements present fairly, in all material respects, our financial position, results of our operations and our cash flows for the periods presented in this Form 10-K, in conformity with GAAP.

Management’s Annual Report on ICFR

Under the Exchange Act, our management is responsible for establishing and maintaining adequate 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.

Material weakness describes a deficiency, or a combination of deficiencies, in ICFR, such that there is a reasonable possibility that material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

As of December 31, 2018, 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). Using these criteria, we concluded that, as of December 31, 2018, we had material weaknesses in our ICFR as further described below:

Control Environment

We had insufficient internal resources with appropriate knowledge and expertise to design and implement, document and operate effective financial reporting processes and internal controls. Additionally, we did not assign the proper personnel with sufficient experience to review information provided to and monitor the activities performed by third-party business valuation and technical accounting specialists.

We did not have formal policies and procedures that defined our personnel’s internal control responsibilities through performance measurement plans and goals, and our personnel did not have sufficient training on the COSO 2013 Framework and its implications on financial reporting and their related internal control roles and responsibilities.

Risk Assessment

We did not have an effective continuous risk assessment process to adequately identify and respond to changes in business operations and the impact of those changes on financial reporting, including ineffective internal control over both recurring and nonrecurring transactions including the Business Combination.

Information and Communication

We did not establish an effective communication processes to identify and provide relevant and reliable information on a timely basis to those responsible at all levels for financial reporting, and related internal controls and to those charged with governance to enable their effective review and oversight of financial reporting.

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Monitoring Activities

We did not design, implement and maintain effective monitoring activities that span the Company to ensure that the processes and internal controls related to the five COSO 2013 Framework components (and underlying principles) were present and functioning. We did not have a timely process to identify all deficiencies and we lacked sufficient cross-functional engagement to remediate the identified deficiencies.

Control Activities

As a consequence of the ineffective control environment, risk assessment, information and communication and monitoring activities components, we did not design, implement, and maintain effective control activities over both recurring and nonrecurring transactions including the Business Combination to mitigate the risk of material misstatement in financial reporting. We did not develop written policies and procedures at a sufficient level of detail. Additionally, we did not retain the required documentation to demonstrate the consistent and timely operation of the controls at a sufficient level of precision to prevent and detect potential misstatements.

Financial Statement Close and Reporting Process

We had ineffective design and implementation and operation of controls over the financial statement close and disclosure process, including regarding assertions about the completeness, existence and accuracy of the financial information.

Information Technology (IT) Controls

IT controls over production volumes and payroll systems were not designed and operating effectively because user access controls did not restrict access privileges to assigned authority or provide adequate segregation of duties. Accordingly, the manual and automated controls for these key IT systems were also ineffective.

The Company did not maintain effective controls to ensure that critical spreadsheets were identified, access was restricted to appropriate personnel, changes to data or formulas were authorized and appropriate, or that the spreadsheets were adequately reviewed by someone other than the preparer.

The material weakness resulted in immaterial and material misstatements in the preliminary consolidated financial statements that were corrected prior to their issuance, including entries impacting oil and gas properties, exploration expense, impairment expense and amounts arising pursuant to the Business Combination. Due to the presence of material weakness, we concluded that our ICFR was not effective as of December 31, 2018.

This Annual Report does not include an attestation report of our independent registered public accounting firm regarding ICFR. Management’s report regarding ICFR was not subject to attestation by our registered public accounting firm pursuant to rules and regulations of the SEC that permit us to provide only management’s report in this Annual Report.

Changes in ICFR

Prior to December 31, 2018, we identified control deficiencies regarding inadequate design and maintenance of IT systems and related databases and system infrastructure (including the core financial reporting system). Specifically, we did not have effective administration controls to ensure appropriate approval of new users and timely removal of users. During the quarter ended December 31, 2018, we completed remediation activities to address these deficiencies by designing and communicating written policies and procedures over administration of logical access for in-scope applications and their related databases and system infrastructure. We also created and deployed policies and procedures for the core financial reporting system to enable improved control over appropriate authorization of user access, tailored logical access to users’ job requirements and improved segregation of duties. Except for this remediation, there were no other material changes in our ICFR during the quarter ended December 31, 2018.

Remediation

We have strengthened our ICFR for our year-end closing and reporting process and are committed to ensuring that our controls continue to mature and operate effectively. Our Board of Directors and management have prioritized the implementation of a remediation plan, taking the necessary actions to address the root causes that contributed to our material weakness and other

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deficiencies identified and to establish and maintain effective ICFR. The following actions and plans have been undertaken or are being undertaken:

• We now have a 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 who has a strong background in oil and gas accounting and managing sophisticated internal control assessments, including utilization of outside advisors.

• We expect to improve the cross-functional nature of our internal control environment. We believe that embedding ICFR at all levels and across all departments will allow us to better distribute accountability for ICFR. Further, we will continue to provide ongoing GAAP and internal controls training for all our employees to embed better internal control. We will continue to assess the organization’s needs in key finance and accounting positions and may retain outside resources to help supplement our employees with respect to complex accounting areas and financial reporting. This remediation effort will also include documenting roles, responsibilities and procedures and retain the appropriate evidence of the operation of control at a sufficient level of precision.

• Given the broad nature of the material weakness, we expect to deploy enhanced management review controls at an appropriate level of precision to reduce the risk of an undetected material misstatement.

• We will evaluate and revise the risk assessment process 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. We will be more programmatic in dealing with the evolving nature of our business operations, ensuring that the risks associated with both recurring and nonrecurring transactions, including any business acquisitions, are communicated timely to those responsible for financial reporting, ICFR and those charged with governance.

• We have engaged 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 plan to use outside resources to enhance the business process documentation, provide company-wide training, and help with management's self-assessment and testing of internal controls. We also plan to implement a rigorous interim testing program to better allow for remediation of identified deficiencies, as appropriate, before the year-end 2019 assessment of ICFR.

• We are evaluating our IT systems, including identification of its shortcomings that result in over-reliance on spreadsheets and manual processes. We expect to make improvements to existing systems to automate interfaces and to enhance reporting capabilities to management, as well as to better evidence performance of key control procedures.

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Item 9B. Other Information

On December 26, 2018, in connection with the resignations of Messrs. Chappelle and Ellis from the Board of Directors of our general partner, Alta Mesa Holdings GP, LLC (“AMH GP”), Ms. Warnica was appointed as a director of AMH GP.  Ms. Warnica resigned from that position on May 14, 2019.  Such resignation was not due to any disagreement with the Company on any matter relating to its operations, policies or practices.  Ms. Warnica will continue to act as the Vice President, General Counsel, Chief Compliance Officer and Secretary of AMH GP.

PART III

Item 10. Directors, Executive Officers, and Corporate Governance

As is the case with many partnerships, we do not directly employ officers, directors or employees. Our operations and activities are managed by the Board of Directors and officers of our general partner, Alta Mesa Holdings GP, LLC (“AMH GP”). References to our directors and officers are references to the directors and officers of AMH GP. References to our employees are references to employees of Alta Mesa Services., LP (“AMS”), an entity wholly owned by us.

Our executive management, other than Messrs. Limbacher, Campbell and Castiglione, which are subject to a Consulting Agreement, are employees of AMS. Our executive management team devotes all of their time to our business and affairs. We also utilize a significant number of employees of AMS to operate our properties and provide us with certain general and administrative services. Under the shared services and expenses agreement with AMS, we reimburse AMS for its operational personnel who perform services for our benefit.

Board Leadership Structure

Our Chairman is James T. Hackett. Our Board of Directors has no policy regarding the separation of the positions of Chief Executive Officer and Chairman. We also do not have a lead independent director.

Board Oversight of Risk

Like all businesses, we face risks in our business activities. Many of these risks are discussed under the caption “Item 1A. Risk Factors” elsewhere in this report. The Board of Directors has delegated to management the primary responsibility of risk management, while it has retained oversight of management in that regard.

In addition, our Board of Directors considers our practices regarding risk assessment and risk management, reviews our contingent liabilities, reviews our oil and natural gas reserve estimation practices, as well as major legislative and regulatory developments that could affect us. Our Board reviews and attempts to mitigate risks which may result from our compensation policies.

Executive Officers and Directors

The following table sets forth the names, ages and positions of our present directors and executive officers as of May 10, 2019. Members of our Board of Directors are elected for one-year terms.

Name	Age	Director  Since
James T. Hackett	65		Executive Chairman of the Board and Interim Chief Executive Officer
Randy L. Limbacher	61		Interim President
John C. Regan	49		Vice President and Chief Financial Officer
John H. Campbell, Jr.	61		Interim Chief Operating Officer— Upstream
Kimberly O. Warnica	45		Vice President, General Counsel, Chief Compliance Officer and Secretary
Mark Castiglione	48		Chief of Staff to the Interim President
Ronald J Smith	60		Vice President and Chief Accounting Officer

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Under SEC rules, we believe all of our executive officers and directors are qualified to hold their positions and the below includes select information regarding their experience, including all positions held in the preceding 5 years, as required under Item 401 of Regulation S-K.

James T. Hackett became our Executive Chairman of the Board immediately following the closing of the Business Combination and was named Interim Chief Executive Officer on December 27, 2018. He also briefly served as Chief Operating Officer— Midstream at AMR and now serves as President of KFM. Prior to the Business Combination, he served as AMR’s Chief Executive Officer and director since March 2017. Mr. Hackett is a Senior Advisor to Riverstone Investment Group, LLC. Prior to joining Riverstone in 2013, Mr. Hackett served as the Chairman of the Board from 2006 to 2013 and the Chief Executive Officer from 2003 to 2012 of Anadarko Petroleum Corporation. Before joining Anadarko, Mr. Hackett served as President and Chief Operating Officer of Devon Energy Corporation, following its merger with Ocean Energy, where he had served as Chairman, President, and Chief Executive Officer. Mr. Hackett has held senior positions at Seagull, Duke Energy, and Pan Energy. He also held positions in engineering, finance and marketing in the midstream, oil field services, and power sectors of the energy industry. Mr. Hackett serves on the Board of Directors of Enterprise Products Holdings, LLC, Fluor Corporation and National Oilwell Varco, Inc. He is a former Chairman of the Board of the Federal Reserve Bank of Dallas. Mr. Hackett received a Bachelor of Science degree from the University of Illinois in 1975 and an MBA and MTS from Harvard University in 1979 and 2016, respectively.

Randy L. Limbacher became our Interim President and the Interim President of AMR on January 1, 2019. He also serves as the Chief Executive Officer of Meridian Energy LLC (a Houston-based energy advisory firm), a position he has held since June 2017. He currently serves on the board of directors of CARBO Ceramics Inc. and TransCanada Corporation. From March 2017 to June 2017, Mr. Limbacher managed his personal investments as a private investor. From April 2013 until December 2015, Mr. Limbacher served as President, Chief Executive Officer and a Director of Samson Resources Corporation, a Tulsa-based oil and gas company, which filed for Chapter 11 protection in September 2015. Mr. Limbacher served as Vice Chairman of the Board of Directors of Samson from December 2015 until the company emerged from bankruptcy in March 2017.  From November 2007 until February 2013, Mr. Limbacher served as President and Chief Executive Officer and a Director of Rosetta Resources, Inc., a Houston-based oil and gas company. From February 2010 until February 2013, Mr. Limbacher also served as Chairman of the Board of Rosetta. From April 2006 until November 2007, Mr. Limbacher held the position of President, Exploration and Production - Americas for ConocoPhillips, a Houston-based energy company. Prior to that time, Mr. Limbacher spent over twenty years with Burlington Resources Inc., a Houston-based oil and gas company, where he served as Executive Vice President and Chief Operating Officer from 2002 until it was acquired by ConocoPhillips in April 2006. He was a Director of Burlington Resources from January 2004 until the sale of the company. Mr. Limbacher received a Bachelor of Science degree in petroleum engineering from Louisiana State University in 1980.

John C. Regan became our Chief Financial Officer and Chief Financial Officer of AMR on January 7, 2019. Prior to joining us, Mr. Regan served as the Chief Financial Officer of Vine Oil and Gas LP from January 2015 to June 2018. He previously served as Chief Financial Officer of Quicksilver Resources from April 2012 through December 2014, after having served as their Chief Accounting Officer beginning in September 2007. Mr. Regan practiced public accounting for nine years with PricewaterhouseCoopers, is a Certified Public Accountant with more than 25 years of combined public accounting, corporate finance and financial reporting experience, and completed his undergraduate degree at the University of Miami.

John H. Campbell, Jr. became our Interim Chief Operating Officer and AMR’s Interim Chief Operating Officer—Upstream on January 1, 2019. He also serves as President and Chief Operating Officer of Meridian Energy LLC, a position he has held since June 2017. From June 2016 to June 2017, Mr. Campbell served as a partner of Quantum Energy Partners, LLC. Prior to joining Quantum Energy Partners, LLC, he served as President of QL-Energy, LLC. From 2010 to 2014, Mr. Campbell served as President and Chief Operating Officer of QR Energy, LP. From 2008 to 2015 Mr. Campbell served as President and Chief Operating Officer of Quantum Resources Management, LLC. Mr. Campbell received a Bachelor of Science degree in petroleum engineering from the University of Alabama, Tuscaloosa in 1983 and a Master of Engineering degree in petroleum engineering degree from Texas A&M University in 1987.

Kimberly O. Warnica became our and AMR’s Vice President, General Counsel, Chief Compliance Officer and Secretary in April 2018. Prior to joining us, Ms. Warnica served as Assistant General Counsel and Assistant Secretary at Marathon Oil Corporation since April 2017. She previously served as Group Counsel and Assistant Secretary of Marathon Oil from October 2016 until April 2017. Prior to Marathon Oil, Ms. Warnica served as Assistant General Counsel and Assistant Secretary at Freeport-McMoRan Oil & Gas (formerly Plains Exploration and Production Company) from April 2006 until June 2016. She started her career at Andrews Kurth LLP where she practiced corporate and securities law representing a variety of clients in

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numerous transactional, securities and corporate governance matters. Ms. Warnica has a bachelor’s degree from Texas A&M University and earned her J.D. from the University of Texas School of Law.

Mark Castiglione became our and AMR’s Chief of Staff to the President on January 1, 2019. He also serves as Executive Vice President of Meridian Energy LLC, a position he has held since June 2017. From January 2015 to May 2017, Mr. Castiglione managed MPC Resources, LLC (an energy advisory firm) and was engaged as Senior Advisor to SandRidge Energy, Inc. from January 2015 to June 2016. From 2010 to December 2014, he served as Senior Vice President – Business Development of Quantum Resources Management, LLC and QR Energy, LP. Prior to joining Quantum Resources, Mr. Castiglione served as Vice President – Acquisitions and Divestitures of El Paso Corporation from 2009 to 2010 and Vice President – Business Development of El Paso Exploration and Production from 2008 to 2009. Mr. Castiglione’s prior background at Encana Corporation, Burlington Resources and Simmons & Company International includes positions of increasing responsibility in corporate development, corporate finance, asset management and engineering. He began his career in 1994 as a reservoir engineer at Burlington Resources. Mr. Castiglione received a Bachelor of Science degree in petroleum engineering from Texas Tech University in 1993 and a Master of Business Administration degree from the Cox School of Business at Southern Methodist University in 1999.

Ronald J. Smith was appointed as our and AMR’s Vice President and Chief Accounting Officer effective upon the closing of the Business Combination. Mr. Smith has over 35 years of accounting experience, primarily in the energy industry. Mr. Smith served as the Chief Accounting Officer of Alta Mesa since 2015. Mr. Smith began working for Alta Mesa in 2008 as the Controller. Mr. Smith has served in numerous senior level management positions including positions with Calpine Corporation and Mariner Energy. Mr. Smith holds a Bachelor of Science in Accounting from Robert Morris University, an MBA in Finance from the University of Houston and is a Certified Public Accountant.

Audit and Compensation Committees

Our parent company, AMR, has an audit committee and a compensation committee. Effective upon completion of the Business Combination, AMR’s audit committee reviews our financial statements and its compensation committee makes determinations and recommendations to its full Board of Directors with respect to the compensation of its executive officers, with the Board of Directors of AMR ultimately approving such recommendations. A portion of that compensation is allocated to us based on the percentage of support provided to the upstream business by the officer given their respective job responsibilities.

Because we do not have any securities on a national securities exchange or on an inter-dealer quotation system, we are not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, we are not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, our Board of Directors has not made any determination as to whether any of the members of our Board of Directors or committees thereof would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition. Additionally, for the same reason, we have not determined whether any of our directors is an audit committee financial expert.

Code of Ethics

The AMR Board of Directors has adopted a Code of Business Conduct and Ethics, which contains provisions for its Chief Executive Officer and Senior Financial Officers. The Code of Ethics is posted on the investor relations section of our website at www.altamesa.net and is available free of charge upon written request to 15021 Katy Freeway, Suite 400, Houston, Texas 77094.

Item 11. Executive Compensation

On February 9, 2018, AMR consummated the acquisition of (i) all of the limited partnership interest in the Company, (ii) 100% of the economic interests and 90% of the voting interests in AMH GP and (iii) all of the membership interests in Kingfisher Midstream, LLC (“Kingfisher”), which we collectively refer to as the “Business Combination”. As is the case with many partnerships, we do not directly employ officers, directors or employees. Our operations and activities are managed by the Board of Directors and officers of AMH GP. References to our directors and officers are references to the directors and officers of AMH GP. References to our employees are references to the employees of AMS, an entity wholly owned by us.

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012. For as long as we are an emerging growth company, we are not required to include a Compensation Discussion and Analysis section in this Annual Report and have elected to comply with the scaled executive compensation disclosure requirements applicable to emerging growth companies.

For 2018, our named executive officers (“NEOs”) were:

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Name	Title
James T. Hackett	Executive Chairman of the Board and Interim Chief Executive Officer
Michael A. McCabe(1)	Former Vice President and Chief Financial Officer
Kimberly O. Warnica	Vice President, General Counsel, Chief Compliance Officer and Secretary
Harlan H. Chappelle(2)	Former President and Chief Executive Officer
Michael E. Ellis(2)	Former Vice President and Chief Operating Officer- Upstream
Homer “Gene” Cole(2)	Former Vice President and Chief Technical Officer

(1) Mr. McCabe retired from the Company on March 29, 2019.

(2) Messrs. Chappelle, Ellis and Cole resigned effective December 26, 2018.

As discussed above, AMR’s compensation committee (the “Committee”) began making determinations and recommendations to its Board of Directors upon completion of the Business Combination with respect to the compensation of its executive officers, with the Board of Directors of AMR ultimately approving such recommendations. A portion of that compensation is allocated to us based on the percentage of support provided to the upstream business by the officer given their respective job responsibilities. Accordingly, the compensation reflected in each of the tables is a total amount received by the NEO for the year ended December 31, 2018, with an allocation to us based on the percentage of support provided to the upstream business by the NEO given their respective job responsibilities. The compensation program is comprised primarily of the following elements: base salary, cash bonus, long-term incentives and benefits. By design, a significant portion of our NEO’s overall 2018 compensation, including annual cash bonuses and long-term incentive awards, is “performance-based,” and the opportunity to earn value is largely dependent on both corporate and individual performance. The Committee determines a total compensation opportunity for each executive officer based on a review of competitive market data, utilization of third party industry sources and an independent compensation consultant, a review of AMR’s compensation philosophy and the Committee’s subjective judgment. The Committee does not set fixed percentages for each element of compensation, so the mix may change over time as the competitive market moves, governance standards evolve or business needs change. The narrative accompanying the tables reflect actions taken by the Committee with respect to AMR’s executive officers. Prior to the Business Combination the Board of Directors of our general partner was responsible for overseeing our executive compensation program.

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Summary Compensation Table

Name and Principal Position	Year	Salary ($)(1)	Bonus ($)(2)	Stock Awards ($)(3)	Option Awards ($)(3)	Non-Equity Incentive Plan Compensation ($)(4)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)(5)	Total ($)(6)	Allocation to Company (%)(7)	Allocation to Company ($)
James T. Hackett Executive Chairman and Interim CEO
	2018	442,000	0	1,405,660	2,722,288	0	0	0	4,569,948	0	0
	2017	0	0	0	0	0	0	0	0	0	0
Michael A. McCabe Former Vice President and Chief Financial Officer(8)
	2018	449,423	0	1,424,402	1,306,698	0	0	3,014,350	6,194,873	50	4,622,533(10)
	2017	435,000	0	0	0	0	0	619,218	1,054,218	100	1,054,218
Kimberly O. Warnica Vice President, General Counsel, Chief Compliance Officer and Secretary
	2018	311,539	94,740	760,000	724,686	170,918	0	9,613	2,071,496	80	1,657,197
	2017	0	0	0	0	0	0	0	0	0	0
Harlan H. Chappelle Former President and CEO(9)
	2018	780,115	0	1,405,660	2,722,288	0	0	4,526,246	9,434,309	50	4,745,136(11)
	2017	485,000	0	0	0	0	0	1,614,741	2,099,741	100	2,099,741
Michael E. Ellis Former Vice President and COO-Upstream(9)
	2018	516,615	0	843,396	1,633,373	0	0	1,988,878	4,982,262	100	4,982,262
	2017	485,000	0	0	0	0	0	733,742	1,218,742	100	1,218,742
Homer “Gene” Cole Former Vice President and Chief Technical Officer(9)
	2018	436,346	0	1,574,402	1,306,698	0	0	2,403,834	5,721,280	100	5,721,280
	2017	350,000	0	0	0	0	0	536,965	886,965	100	886,965

(1)    Represents salary paid in 2018 both prior to and after closing of the Business Combination through year-end or separation of employment, as the case may be. Ms. Warnica joined the Company in April 2018.

(2)    For Ms. Warnica, this column represents a one-time cash sign-on bonus received upon commencement of employment.

(3)    Reflects the aggregate grant date fair values calculated in accordance with FASB Accounting Standards Codification Topic 718 "Compensation-Stock Compensation" ("ASC Topic 718"). Assumptions used in the calculation of these amounts are included in footnote 19 to our consolidated financial statements in our annual report on Form 10-K for the year ended December 31, 2018. The Stock Awards column also includes the grant date fair value for the first tranche of the performance-based restricted stock units granted in 2018 at target levels. These awards vest over three years at 20% during the first year, 30% during the second year and 50% during the third year. We only recognize expense for these awards when the specified performance thresholds for future periods have been established. Only the performance goals and objectives for 2018 were established as of December 31, 2018. No amounts will be recognized for the 2019 and 2020 performance period until the specific targets have been established and probability of attainment can be measured. The

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value ultimately realized upon the actual vesting of the awards may or may not be equal to this determined value, as these awards are subject to performance criteria and have been valued based on assessment of that criteria as of the grant date. It was determined in January 2019 that the first tranche of 2018 performance-based units would pay out at zero percent. If the highest level of performance conditions had been achieved for the year ending December 31, 2018, the maximum grant date fair value for the first tranche of the performance-based restricted stock units for each executive would have been as follows:

Name	Maximum Grant Date Fair Value ($)
James T. Hackett	2,811,322
Michael A. McCabe	599,749
Kimberly O. Warnica	320,001
Harlan H. Chappelle	2,811,322
Michael E. Ellis	1,686,792
Homer “Gene” Cole	599,749

(4)    This column reflects annual cash bonus payments, determined by the Committee and paid in the first quarter of the following year pursuant to AMR’s Annual Incentive Compensation Plan.

(5)    The following table describes each component of the All Other Compensation column for 2018 in the Summary Compensation Table.

Name	Company Physicals ($)(a)	Tax & Financial Planning ($)(b)	Miscellaneous ($)(c)	Company Contributions to Defined Contribution Plan ($)(d)	Partnership Appreciation Rights ($)(e)	Total All Other Compensation ($)
James T. Hackett	0	0	0	0	0	0
Michael A. McCabe	0	0	600	13,750	3,000,000	3,014,350
Kimberly O. Warnica	0	5,000	300	4,313	0	9,613
Harlan H. Chappelle	0	0	4,513,819(f)	12,427	0	0
Michael E. Ellis	0	5,000	1,970,128(g)	13,750	0	10,000
Homer “Gene” Cole	0	3,505	1,636,579(h)	13,750	750,000	2,403,834

(a)    Executives are entitled to reimbursement for the full cost of an annual physical examination through their employment agreements.

(b)    Executives are entitled to up to $5,000 in reimbursement for the cost of tax preparation and planning by a certified financial planner or certified public accountant.

(c)    Includes personal use of club memberships, personal use of company vehicle and health club dues, with such health club dues being capped at $600 per year.

(d)    Reflects amounts contributed by us under the 401(k) employee savings and protection plan.

(e)    Amount is the difference between the aggregate of the stipulated initial designated values of the Partnership Appreciation Rights (PARs) at the grant date and the designated value of the PAR as of its payment valuation date, which was the date of the Business Combination.

(f)    This amount includes (i) $31,271 for personal use of club memberships; (ii) $707,548, which reflects the in-the-money value of the stock options (currently $0) and the value of performance units and restricted stock for which vesting was accelerated upon Mr. Chappelle’s resignation, all as of December 26, 2018 at a stock price of $0.90, the grant date fair market value of which is reported in the Stock Awards and Option Awards columns of the Summary Compensation Table, as applicable; and (iii) $3,775,000, which represents the value of the benefits to which Mr. Chappelle was entitled to pursuant to his employment agreement. Please read “-Termination or Change in Control” for additional information.

(g)    This amount includes (i) $600 for health club dues; (ii) $424,528, which reflects the in-the-money value of the stock options (currently $0) and the value of performance units and restricted stock for which vesting was accelerated upon Mr. Ellis’ resignation, all as of December 26, 2018 at a stock price of $0.90, the grant date fair market value of which is reported in the Stock Awards and Option Awards columns of the Summary Compensation Table, as applicable; and (iii) $1,545,000, which represents the value of the benefits to which Mr. Ellis was entitled to pursuant to his employment agreement. Please read “-Termination or Change in Control” for additional information.

(h)    This amount includes (i) $1000 for personal use of club memberships; (ii) $295,329, which reflects the in-the-money value of the stock options (currently $0) and the value of performance units and restricted stock for which vesting was accelerated upon Mr. Cole’s resignation, all as of December 26, 2018 at a stock price of $0.90, the grant date fair market value of which is reported in the Stock Awards and Option Awards columns of the Summary Compensation Table, as applicable; and (iii) $1,340,250, which represents the value of the benefits to which Mr. Cole was entitled to pursuant to his employment agreement. Please read “-Termination or Change in Control” for additional information.

(6)The amounts reflected here for Mr. Hackett and Ms. Warnica are the same as will be disclosed in the 2019 Proxy Statement of AMR, with an allocation to us based on the percentage of support provided to the upstream business by the NEO given their respective job responsibilities.

(7)    Allocation based on the percentage of support provided to the upstream business by the NEO given respective job responsibilities. As Mr. Hackett did not become Interim Chief Executive Officer to the Company until December 26, 2018, the allocation to the Company for 2018 is zero.

(8)     Mr. McCabe retired effective March 29, 2019.

(9)    Messrs. Chappelle, Ellis and Cole resigned effective December 26, 2018.

(10) Base Salary for 2018 includes (i) $50,192, which represents of Mr. McCabe’s pre-Business Combination base salary and (ii) $399,231 which is the base salary paid in 2018 from the closing of the Business Combination. The allocation of the base salary to us is 100% of the $50,192 and 50% of the $399,231. The All Other Compensation for 2018 includes (i) $14,350 for Miscellaneous and Company Contributions to Defined Contribution Plans and (ii) $3,000,000 in PARs. The allocation of the All Other Compensation to us is 50% of the $14,350 and 100% of the $3,000,000. All other amounts of compensation for 2018 were allocated at 50% to us.

(11)    Base Salary for 2018 includes (i) $55,962, which represents Mr. Chappelle’s pre-Business Combination base salary and (ii) $724,154 which is the base salary paid in 2018 from the closing of the Business Combination. The allocation of the base salary to us is 100% of the $55,962 and 50% of the $724,154. All other amounts of compensation for 2018 were allocated at 50% to us.

Narrative Disclosure to Summary Compensation Table

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The Committee determined 2018 base salaries, annual incentive cash bonus opportunities and long-term incentive (“LTI”) awards in February 2018. The Committee determined the amount of 2018 annual cash bonuses in February 2019, after preliminary 2018 business results were known.

Base Salary

Base salaries are intended to provide a level of stability and certainty each year with respect to compensation. We pay base salary to recognize and reward overall responsibilities, experience and established skills. In setting base salary, the Committee compares each NEO’s current salary to the market and considers each individual’s experience and expertise, the value and responsibility associated with the role and internal pay equity. The Committee does not use a formula to calculate base salary increases for NEOs. In February 2018, in connection with the Business Combination, the Committee reviewed base salaries in light of the considerations noted above.

Annual Cash Bonus

The annual cash bonus rewards executives for achieving short-term financial, operational and strategic goals that drive stockholder value, as well as for individual performance during the year.

When determining target bonus opportunities for our executives, the Committee considers the range of market practices, as well as each executive’s experience, relative scope of responsibility, internal pay equity considerations and any other information the Committee deems relevant in its discretion. Targeted performance goals, established by the Committee during the first quarter of the year, are defined to focus and challenge our NEOs to perform at a high level. Payout results may be above or below target based on actual corporate and individual performance.

The Committee determined the 2018 annual cash bonus payout for each NEO based on its assessment of the following:

•Quantitative corporate performance goals; and

•Individual performance, including leadership and ethics, and overall value that the officer created.

The illustration below summarizes the framework the Committee uses to determine individual officer bonus payouts:

Target Bonus Opportunity X Corporate Performance Score X Individual Performance Factor = Annual Bonus Payment

Target bonus opportunity consists of base salary multiplied by bonus target, which is expressed as a percentage of base salary. The quantitative corporate performance score can range between 0% and 200%, with 100% being the target. Individual performance factors can range between 0 and 1.5.

2018 Quantitative Performance Metrics

During the first quarter of 2018, the Committee established quantitative performance goals for the bonus program by taking into consideration key safety, financial and operational performance measures that are important indicators of success in our industry. Each of these metrics was based on fiscal year 2018 performance and this included periods prior to the Business Combination.

The following table shows the targets and weightings established by the Committee and the performance achieved during 2018.

Upstream

The upstream quantitative performance metrics for 2018 were tied to a mix of growth, cost control and capital efficiency metrics. The higher than expected capital and operating costs experienced in 2018 coupled with lower than expected reservoir performance resulted in underperformance of the targeted upstream quantitative metrics. Only the net production growth achieved in 2018 was within the range of target metrics set. The upstream production growth achieved was done so with

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significantly higher than expected capital and operating costs. As a result, the upstream business failed to reach the target range on any of the cost or capital efficiency targets.

Performance Metric	Weight	Threshold	Target	Over-Achieve	Weighted Payout
LOE/BOE, $BOE(1)	15%	$5.33	$5.08	$4.85	0%
Production, MBOE/ Day(2)	30%	27.8	32.7	38.5	22%
Drillbit F&D, $/ BOE(3)	15%	$10.50	$9.50	$8.50	0%
Reserve Replacement, %(4)	10%	125%	150%	175%	0%
Upstream EBITDAX, $MM(5)	30%	$270	$317	$380	0%
				Weighted Average	22%

(1) Lease operating expense calculated based on operated horizontal production in Kingfisher County. Excludes other counties, legacy vertical wells, activities from other operators and revenues generated from working interest partners on the owned saltwater disposal facilities.

(2) Total reported net production. Includes operated and non-operated net production and is inclusive of acquisitions and divestiture activity.

(3) Calculated as development capital spent divided by increase in proved developed producing reserves, excluding technical revisions.

(4) Proved reserve additions divided by 2018 net production.

(5) Earnings before interest, taxes, depreciation, amortization and exploration adjusted for special items. Represents a full year 2018.

Midstream

The midstream quantitative performance metrics for 2018 were also tied to a mix of growth and cost control. Additionally, midstream quantitative performance metrics included capital budgeting and safety targets. While safety is a priority across the entire enterprise, given the integration of a new business segment with a significantly different operating make up than our legacy upstream operations, management chose to have the safe integration of this business as a quantitative performance metric for 2018. AMR had zero reportable incidents in Midstream in 2018, owing in part to this heightened focus on safety. Midstream cost control and capital budgeting goals were linked to an expectation that the midstream business would be able to rapidly add significant third-party midstream volumes over the course of 2018. Instead, the midstream business experienced an environment where third-party activity on existing acreage dedications was below expectations and the amount of new third-party contracting was limited. The midstream business was still within the target range for operating costs, despite lower than expected gas volumes in the plant, and demonstrated capital discipline as spending on growth capital moderated to be in line with the reduced trajectory of the business development efforts.

Performance Metric	Weight	Threshold	Target	Over-Achieve	Weighted Payout
Plant OPEX, $/ MMBTU(1)	20%	$0.35	$0.25	$0.15	15%
Safety, TRI(2)	10%	2	1	0	20%
CAPEX Control, % Budget(3)	10%	120%	100%	80%	20%
Midstream EBITDA, $MM(4)	60%	$69	$81-$109	$125	0%
			Weighted Average		55%

(1) Calculated for the period from February 9, 2018 - December 31, 2018.

(2) Calculated using the Occupational Safety and Health Administration Recordable Incidents Rate.

(3) Calculated as capital spent as a percentage of approved capital. Excluded expansion area and produced water capital expenditures.

(4) Earnings before interest expense, income taxes, depreciation and amortization, as well as other adjustments.

Annual Cash Bonus Payouts Earned for 2018

Messrs. Hackett, Chappelle and McCabe and Ms. Warnica participated in both upstream and midstream bonus plans with weighting proportionate to the respective upstream and midstream EBITDA(X) targets, resulting in a 30% weighted payout.

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Ms. Warnica’s proportionate weighting was adjusted to 50% for each of upstream and midstream to more accurately align with her 2018 job responsibilities. Messrs. Ellis and Cole participated in only the upstream bonus plan.

The Committee evaluated our NEO’s contributions during 2018 and considered each NEO’s specific contribution to AMR and assigned an individual performance factor to each executive.

Based on AMR’s performance results for the year ended December 31, 2018, Ms. Warnica received 58% of her target bonus. Each of Messrs. Hackett, Chappelle, McCabe, Ellis and Cole received no bonus for 2018.

2018 Long-Term Incentive Awards

After consultation with its independent consultant and considering competitive market data, the demand for talent, and cost considerations, the Committee awarded LTIs to each NEO as of February 9, 2018 in connection with the Business Combination with respect to Messrs. Hackett, Chappelle, Ellis, McCabe and Cole. The Committee determined to grant 30% of the target LTI value in restricted stock awards, 30% in options and 40% in performance-based restricted stock units. The Committee awarded LTIs to Ms. Warnica in connection with her joining the Company in April 2018 in recognition of grants that were forfeited from a prior employer, as well as during the annual grant cycle.

Restricted Stock Awards. The Committee awards restricted stock for diversification of the LTI award mix, for retention purposes and to align NEO interests with those of AMR stockholders. Restricted stock provides recipients with the opportunity for capital accumulation, which leads to retention and stock ownership and a more predictable LTI value than is provided by stock options and performance units. Restricted stock awards vest pro rata over a three-year period on the anniversary of the grant date. Prior to vesting, recipients have the right to vote and accumulate dividends on, to the extent paid, the restricted shares. Any accumulated dividends are subject to the same vesting schedule as the underlying share of restricted stock.

Options. Stock options provide a direct link between officer compensation and the value delivered to stockholders. The Committee believes that stock options are inherently performance-based, as option holders only realize compensation if the value of our stock increases following the grant date. Options vest pro rata over a three-year period on the anniversary of the grant date and generally expire after 7 years unless the officer separates from AMR.

Performance-Based Restricted Stock Units (RSUs). The Committee believes a significant portion of the NEO’s compensation should be “at-risk” and accordingly granted 40% of the LTI value in performance-based RSUs. The RSUs vest ratably over three years. AMR expected that its net production growth on upstream and system volumes growth on midstream, when coupled with a focus on maintaining a low-cost operating environment, would drive a significant increase in operating cash flows, as measured by Earnings Before Interest, Tax, Depreciation, Amortization and Exploration (“EBITDAX”). The Committee set achievement of certain EBITDAX and EBITDAX per debt-adjusted share targets for the 2018 performance period, which was from February 9, 2018 through December 31, 2018. The number of performance-based RSUs that could be earned for the 2018 performance period was established at the lesser of:

•the product of the target performance-based RSUs multiplied by the applicable percentage determined based on AMR’s EBITDAX during the performance period; and

•the product of the Target Performance-Based RSUs multiplied by the applicable percentage determined based on AMR’s EBITDAX per debt-adjusted share during the performance period, each as set forth under the following charts:

Level*	EBITDAX	Performance-Based RSUs (Payout %)
Threshold	$385MM	50% of Target Performance-Based RSUs
Target	$450MM	100% of Target Performance-Based RSUs
Maximum	$540MM	200% of Target Performance-Based RSUs

Level*	EBITDAX/DAS	Performance-Based RSUs (Payout %)
Threshold	$0.85	50% of Target Performance-Based RSUs
Target	$1.00	100% of Target Performance-Based RSUs
Maximum	$1.20	200% of Target Performance-Based RSUs

*The payout percentage for determining the actual number of performance-based RSUs that have become payable will be interpolated for performance between Threshold and Target, and also for performance between Target and Maximum. For the avoidance of doubt, there will be no payout, and no performance-based RSUs will vest, if the Threshold performance level set forth above is not reached for both metrics.

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Ultimately, while the average commodity price in 2018 was higher than in 2017, with lower than expected growth and higher than expected costs, AMR was not able to reach its targets. Based on AMR’s performance results for the period from February 9, 2018 through December 31, 2018, the NEOs did not earn any of the 2018 performance units. Accordingly, other than Messrs. Chappelle, Ellis and Cole, who had employment contracts which provided for vesting and payment at target levels upon their separation, there was no payout associated with these awards.

Outstanding Equity Awards at 2018 Fiscal Year-End

The following table reflects outstanding stock option awards and unvested and unearned stock awards (both time-based and performance-contingent) as of December 31, 2018, assuming a market value of $1.00 per share (the closing stock price of AMR’s common stock on December 31, 2018).

						Stock Awards
		Option Awards				Restricted Stock/Units(3)		Equity Incentive Plan Awards / Performance Units(4)
		Number of Securities Underlying Unexercised Options		Option Exercise Price ($)	Option Expiration Date	Number of Share or Units of Stock that Have Not Vested (#)	Market Value of Shares or Units of Stock that Have Not Vested (#)	Number of Unearned Shares, Units or Other Rights that Have Not Vested (#)	Market or Payout Value of Unearned Shares, Units or Other Rights that Have Not Vested ($)
Name	Grant Date(1)	Exercisable (#)	Unexercisable(2)(#)
James T. Hackett	2/9/2018	0	589,623	9.54	2/8/2025			786,164	786,164
Michael A. McCabe(5)	2/9/2018	0	283,019	9.54	2/8/2025	125,786	125,786	134,172	134,172
Kimberly O. Warnica	4/9/2018	0	192,582	7.01	4/8/2025	85,592	85,592	114,123	114,123
Harlan H. Chappelle(6)	2/9/2018	589,623	0	9.54	12/26/2021
Michael E. Ellis(6)	2/9/2018	353,774	0	9.54	12/26/2021
Homer “Gene” Cole(6)	2/9/2018	283,019	0	9.54	12/26/2021

(1)Awards were established based on the fair market value of a Class A share of AMR on the grant date in the table and, in the case of restricted stock and restricted stock units, were issued upon receipt of an effective registration statement, which was April 12, 2018.

(2)    All stock options listed vest in one-third increments on each anniversary of the grant date.

(3)    Reflects the number of shares of unvested restricted stock held by our NEOs on December 31, 2018. The restricted stock will vest pro rata annually over three years, beginning with the first anniversary of the Business Combination date.

(4)    The number of outstanding units and estimated payout disclosed for each award assumes target payout. However, in January 2019, it was determined that the first tranche of 2018 performance-based units would pay out at zero percent.

(5)    Mr. McCabe retired effective March 29, 2019.

(6)    Messrs. Chappelle, Ellis and Cole resigned effective December 26, 2018. In accordance with their respective employment and separation

agreements, all outstanding options, shares of restricted stock and performance units vested. Performance units were paid out at target per the agreements. The release of these awards was subject to an effective release which was received from each in January of 2019.

Nonqualified Defined Contribution Plan

We established a nonqualified deferred compensation plan in 2013, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”), to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees.  The terms of such contributions included a specified vesting schedule, intended to encourage continuous service to us.  If no schedule was specified with the award, the Retirement Plan provided for vesting

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based on years of service, with full vesting at three years.  Participants would receive a distribution of vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring for a fixed time period or until separation from service.  On February 9, 2018, in connection with the Business Combination, we terminated this plan and certain distributions were made to our executive officers under the Retirement Plan.

Termination or Change in Control

Our NEOs are parties to employment agreements that provide them with post-termination benefits in a variety of circumstances. The amount of compensation payable in some cases may vary depending on the nature of the termination, whether as a result of voluntary termination, involuntary not-for-cause termination, termination following a change of control and in the event of disability or death of the executive. The discussion below describes the varying amounts payable in each of these situations. It assumes, in each case, that the officer’s termination was effective as of December 31, 2018, and, where applicable, uses the closing price of our common stock of $1.00 on such date. In presenting this disclosure, we describe amounts earned through December 31, 2018 and, in those cases where the actual amounts to be paid out can only be determined at the time of such executive’s separation, we estimate the amounts that would be paid out to the executives upon their termination.

Employment Agreements

In connection with the Business Combination, AMR entered into a letter agreement with Mr. Hackett under which, if AMR terminates Mr. Hackett’s employment without cause or he resigns for good reason, within the meaning of and under the letter agreement, he will be entitled to full accelerated vesting of all AMR equity awards granted to him during the three years following closing of the Business Combination that are subject to time-based vesting and accelerated vesting of any such AMR equity awards that are subject to performance-based vesting at the target level of performance. The Board of AMR also approved an annual base salary for Mr. Hackett of $520,000, effective on the Closing Date, and a target annual bonus amount under an annual performance bonus program for 2018 of 95% of his annual base salary.

In addition, in connection with the Business Combination, AMS entered into employment agreements with each of Messrs. Chappelle, Ellis, McCabe and Cole. The employment agreements were for terms of three years. Messrs. Chappelle, Ellis and Cole resigned from the Company effective December 26, 2018 and Mr. McCabe retired from the Company effective March 29, 2019. In addition, AMS entered into an employment agreement with Ms. Warnica in April 2018 when she joined the Company.

The employment agreement for Ms. Warnica entitles her to receive an annual base salary of $450,000 and to participate in an annual performance bonus program with a target bonus award determined by the Board of AMR. For 2018, Ms. Warnica’s target annual bonus amount under this program was 95% of her annual base salary. Ms. Warnica is also entitled to receive an annual physical and reimbursement of up to $5,000 per year for tax planning services. If Ms. Warnica’s employment is terminated without cause or she resigns for good reason, within the meaning of and under the employment agreement, she will be entitled to receive (i) a prorated annual bonus for the year of termination, determined at the discretion of the Committee and based on satisfaction of performance criteria prorated for the partial performance period, (ii) full accelerated vesting of all AMR equity awards that are subject to time-based vesting, accelerated vesting of any AMR equity awards that are subject to performance-based vesting at the target level of performance and full accelerated vesting of any nonqualified deferred compensation account balance or benefit, (iii) a lump-sum payment equal to the sum of $24,000 for outplacement services, (iv) 18 months of her annual base salary and 1.5 times the greater of her target annual bonus and the annual bonus paid to her for the prior year and (v) payment for up to 18 months of premiums for continued coverage in AMR’s group health plans and, thereafter, continued participation in AMR’s group health plans at her cost for up to an additional 6 months. Ms. Warnica would also be entitled to receive the amounts under clauses (i), (iii), (iv) and (v) of the preceding sentence if her employment terminates due to death or disability, under and within the meaning of her employment agreement. If Ms. Warnica’s qualifying termination of employment occurs during the fifteen months following a change in control (within the meaning of her employment agreement) or, only in the case of termination without cause or resignation for good reason, during the three months prior to a change in control and is demonstrated to be in connection with the change in control, then in addition to the foregoing payments and benefits, she will be entitled to an additional lump-sum payment equal to the sum of six months of her annual base salary and 0.5 times the greater of her target annual bonus and the annual bonus paid to her for the prior year. Ms. Warnica’s right to receive termination payments and benefits, other than a prorated annual bonus for the year of termination, are conditioned upon executing a general release of claims in our favor. Ms. Warnica has also agreed to refrain from competing with the Company or soliciting its customers or employees during and for a period of 12 months following her employment with AMS.

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The employment agreement for Ms. Warnica further entitles her, if a termination of employment occurs during the three years following the Closing Date, to payment for any excise taxes imposed under Section 4999 of the Internal Revenue Code as a result of a change in control (within the meaning of her employment agreement), other than the Business Combination, plus an additional amount that puts her in the same after-tax position she would have been absent in the imposition of excise taxes under Section 4999 of the Internal Revenue Code.

General Scenarios

The following are general definitions that apply to the termination scenarios detailed below. These definitions have been summarized and are qualified in their entirety by the full text of the applicable plans or agreements to which our NEOs are parties.

“Anticipatory Termination” generally means a termination of the employment within the three (3) month period ending immediately prior to the Change in Control date (in which the Change in Control is a “change in control event” within the meaning of Code Section 409A), but only if (a) the NEO’s employment was (i) terminated without Cause or (ii) terminated by the NEO for Good Reason, and (b) it is reasonably demonstrated by the NEO that such termination of employment (1) was at the request of a third party who has taken steps reasonably calculated to effect such Change in Control or (2) otherwise arose in connection with or anticipation of such Change in Control.

“Cause” is generally defined as: (A) the NEO’s final conviction by a court of competent jurisdiction of a felony involving moral turpitude, or entering the plea of nolo contendere to such felony by the NEO; (B) the commission by the NEO of a demonstrable act of material fraud, or a proven and material misappropriation of funds or other property, of or upon AMS or any affiliate; (C) the engagement by the NEO, without the written approval of AMS, in any material activity which directly competes with the business of AMS or any affiliate, or which would directly result in a material injury to the business or reputation of AMS or any affiliate; or (D) the breach by the NEO of any material provision of his or her employment agreement. With respect to items (C) and (D) above, in order to constitute “Cause” hereunder, the NEO must also fail to cure such breach within a reasonable time period set by AMS but in no event less than twenty (20) calendar days after NEO’s receipt of such notice.

“Change of Control” means and includes each of the following:

(A) A transaction or series of transactions (other than an offering of common stock to the general public through a registration statement filed with the Securities and Exchange Commission or a transaction or series of transactions that meets the requirements of clauses (1) and (2) of subsection (C) below) whereby any “person” or related “group” of “persons” (as such terms are used in Sections 13(d) and 14(d)(2) of the Exchange Act) (other than AMR, any

of its subsidiaries, an employee benefit plan maintained by AMR or any of its subsidiaries or a “person” that, prior to such transaction, directly or indirectly controls, is controlled by, or is under common control with, AMR) directly or indirectly acquires beneficial ownership (within the meaning of Rule 13d-3 under the Exchange Act) of securities of AMR possessing more than 50% of the total combined voting power of AMR’s securities outstanding immediately after such acquisition; or

(B) During any period of two consecutive years, individuals who, at the beginning of such period, constitute the Board or AMR together with any new Director(s) (other than a Director designated by a person who shall have entered into an agreement with AMR to effect a transaction described in subsections (A) or (C)) whose election by the Board of AMR or nomination for election by AMR’s stockholders was approved by a vote of at least two-thirds of the Directors then still in office who either were Directors at the beginning of such two-year period or whose election or nomination for election was previously so approved, cease for any reason to constitute a majority thereof; or

(C) The consummation by AMR (whether directly involving AMR or indirectly involving AMR through one or more intermediaries) of (x) a merger, consolidation, reorganization, or business combination or (y) a sale or other disposition of all or substantially all of AMR’s assets in any single transaction or series of related transactions, or (z) the acquisition of assets or stock of another entity, in each case other than a transaction:

(1) which results in AMR’s voting securities outstanding immediately before the transaction continuing to represent (either by remaining outstanding or by being converted into voting securities of AMR or the person that, as a result of the transaction, controls, directly or indirectly, AMR or owns, directly or indirectly, all or substantially all of AMR’s assets or otherwise succeeds to the business of AMR (AMR or such person, the “Successor Entity”)) directly or indirectly, at least a majority of the combined voting

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power of the Successor Entity’s outstanding voting securities immediately after the transaction; and

(2) after which no person or group beneficially owns voting securities representing 50% or more of the combined voting power of the Successor Entity; provided, however, that no person or group shall be treated for purposes of this clause (2) as beneficially owning 50% or more of the combined voting power of the Successor Entity solely as a result of the voting power held in AMR prior to the consummation of the transaction.

Notwithstanding the foregoing, in no event shall the following constitute a Change in Control: (i) the Business Combination or any transactions occurring in connection therewith, or (ii) any initial public offering of any subsidiary of AMR that owns all or part of AMR’s Midstream Assets or any other sale or disposition of such Midstream Assets directly or indirectly by AMR in connection with such initial public offering.

The Board of AMR as in effect immediately prior to the occurrence of a Change in Control shall have full and final authority, which shall be exercised in its discretion, to determine conclusively whether a Change in Control has occurred pursuant to the above definition, the date of the occurrence of such Change in Control and any incidental matters relating thereto; provided that any exercise of such authority in conjunction with a determination regarding whether a Change in Control is a “change in control event” (as defined in Treasury Regulation Section 1.409A-3(i)(5)) shall be determined on a basis consistent with such regulation.

“Good Reason” means the occurrence of any of the following without the NEO’s prior written consent, if not cured and corrected by AMR or the Company within 60 days after written notice thereof is provided by the NEO to AMS, provided such notice is delivered within 90 days after the occurrence of the applicable condition or event and that NEO resigns from employment with AMS within 90 days following expiration of such 60-day cure period: (a) the demotion or reduction in title or rank of NEO with AMR or the Company, or the assignment to NEO of duties that are materially inconsistent with NEO’s positions, duties and responsibilities with AMR or the Company, or any removal of the NEO from, or any failure to nominate for re- election the NEO to, any of such positions (other than a change due to the NEO’s Disability or as an accommodation under the American with Disabilities Act), except for any such demotion, reduction, assignment, removal or failure that occurs in connection with NEO’s termination of employment for Cause, Disability or death; (b) the reduction of the NEO’s annual base salary and/or target bonus opportunity, as compared to his aggregate base salary and target bonus opportunity as effective immediately prior to such reduction, if such reduction of base salary and/or target bonus opportunity, on an aggregated basis, is five percent (5%) or greater of the aggregate base salary and target bonus opportunity as effective immediately prior to such reduction; (c) a relocation of the NEO’s principal work location to a location in excess of 50 miles from its then current location; or (d) failure to nominate the NEO to be re-elected to the Board of AMR. For the avoidance of doubt, the closing of the Business Combination will not by itself be deemed to provide a basis for the NEO to resign for Good Reason.

“Disability” generally means that (a) the NEO is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or last for a continuous period of not less than 12 months, or (b) by reason of any medically determinable physical or mental impairment which can be expected to result in death or to last for a continuous period of not less than 12 months, the NEO is receiving income replacement for a period of not less than three months under an accident and health plan covering employees of the Company. Evidence of such Disability shall be certified by a physician acceptable to both AMS and the NEO. In the event that the parties are not able to agree on the choice of a physician, each shall select one physician who, in turn, shall select a third physician to render such certification. All reasonable costs directly relating to the determination of whether the NEO has incurred a Disability for purposes of this Agreement shall be paid by AMS. The NEO agrees to submit to any examinations that are reasonably required by the attending physician or other healthcare service providers to determine whether the NEO has a Disability.

Involuntary for Cause or Voluntary Termination without Good Reason. No payment will be paid to the NEOs.

Involuntary Termination without Cause or Termination for Good Reason.

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	Mr. Hackett ($)	Mr. McCabe($)	Ms. Warnica($)
Cash Severance(1)	0	1,457,459	1,340,250
Pro Rata AICP Bonus(2)	0	0	170,918
Accelerated Equity Compensation(3)	786,164	259,958	199,715
Health and Welfare Benefits(4)	0	13,699	43,819
Total	786,164	1,731,116	1,754,702

(1)    Value assumes 1.5 times salary in effect at December 31, 2018 and 1.5 times target bonus for Mr. McCabe and Ms. Warnica. Also includes $24,000 for outplacement services for Mr. McCabe and Ms. Warnica. Includes additional $117,209 lump sum payment for Mr. McCabe pursuant to his Separation Agreement. See “-Post- Termination Compensation” below.

(2) All values in the table are based on base salary earnings for the year and reflect the actual bonuses awarded under AMR’s 2018 AICP.

(3)    Reflects the in-the-money value of unvested stock options (currently $0), the value of unvested performance units and the value of unvested restricted stock, all as of December 31, 2018.

(4)    Reflects value of 18 months of coverage under AMR’s group health plans assuming continued election of the officer’s current level of coverage for the full 18 months at the current rates, except for Mr. Hackett who is not entitled to continued coverage.

Death or Disability

	Mr. Hackett ($)	Mr. McCabe($)	Ms. Warnica($)
Cash Severance(1)	0	1,457,459	1,340,250
Pro Rata AICP Bonus(2)	0	0	170,918
Health and Welfare Benefits(3)	0	13,699	43,819
Total	0	1,471,158	1,554,987

(1)    Value assumes 1.5 times salary in effect at December 31, 2018 and 1.5 times target bonus for Mr. McCabe and Ms. Warnica. Also includes $24,000 for outplacement services for Mr. McCabe and Ms. Warnica. Includes additional $117,209 lump sum payment for Mr. McCabe pursuant to his Separation Agreement. See “-Post- Termination Compensation” below.

(2)    All values in the table are based on base salary earnings for the year and reflect the actual bonuses awarded under AMR’s 2018 AICP.

(3)    Reflects value of 18 months of coverage under AMR’s group health plans assuming continued election of the officer’s current level of coverage for the full 18 months at the current rates, except for Mr. Hackett who is not entitled to continued coverage.

Change in Control or Anticipatory Termination. In the event an NEO is terminated within 15 months after a Change in Control or an NEO incurs an Anticipatory Termination, the following payments would be due.

	Mr. Hackett ($)	Mr. McCabe($)	Ms. Warnica($)
Cash Severance(1)	0	1,896,209	1,779,000
Pro Rata AICP Bonus(2)	0	0	170,918
Accelerated Equity Compensation(3)	786,164	259,958	199,715
Health and Welfare Benefits(4)	0	13,699	43,819
Total	786,164	2,169,866	2,193,452

(1)    Value assumes 2 times salary in effect at December 31, 2018 and 2 times target bonus for Mr. McCabe and Ms. Warnica. Also includes $24,000 for outplacement services for Mr. McCabe and Ms. Warnica. Includes additional $117,209 lump sum payment for Mr. McCabe pursuant to his Separation Agreement. See “-Post- Termination Compensation” below.

(2)    All values in the table are based on base salary earnings for the year and reflect the actual bonuses awarded under AMR’s 2018 AICP.

(3)    Reflects the in-the-money value of unvested stock options (currently $0), the value of unvested performance units and the value of unvested restricted stock, all as of December 31, 2018.

(4)    Reflects value of 18 months of coverage under AMR’s group health plans assuming continued election of the officer’s current level of coverage for the full 18 months at the current rates, except for Mr. Hackett who is not entitled to continued coverage.

Post-Termination Compensation

On December 20, 2018, each of Harlan H. Chappelle, the President and Chief Executive Officer, Michael E. Ellis, the Vice President and Chief Operating Officer, and Homer “Gene” Cole, the Vice President and Chief Technology Officer, informed the Company that he intended to resign, effective December 26, 2018, from his position with the Company. Each of Mr. Chappelle and Mr. Ellis also informed the Company that he intended to resign as a member of the Board of AMR, effective immediately. Mr. Chappelle’s and Mr. Ellis’ decision to resign from the Board of AMR was not due to any disagreement with AMR relating to the operations, practices or policies of AMR.

In connection with Mr. Chappelle’s, Mr. Ellis’ and Mr. Cole’s resignation, AMS entered into a separation agreement with each of them pursuant to which each individual received (a) a prorated annual bonus for the year of termination, determined based on satisfaction of performance criteria prorated for the partial performance period, which was set at $0, (b) full accelerated vesting of all AMR equity awards that are subject to time-based vesting and accelerated vesting of any AMR equity awards that are subject to performance-based vesting at the target level of performance, (c) a lump-sum payment equal to the sum of (i)

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$40,000 for Mr. Chappelle and $24,000 for each of Mr. Ellis and Mr. Cole for outplacement services, (ii) two years for Mr. Chappelle or 18 months for each of Mr. Ellis and Mr. Cole of his annual base salary and (iii) 2 times for Mr. Chappelle or 1.5 times for each of Mr. Ellis and Mr. Cole, the greater of his target annual bonus and the annual bonus paid to him for the prior year and (d) payment for up to 18 months of his premiums for continued coverage in AMR’s group health plans and, thereafter, continued participation in AMR’s group health plans at his cost for up to an additional 18 months for Mr. Chappelle or 6 months for each of Mr. Ellis and Mr. Cole. These amounts are reflected in the All Other Compensation column of the Summary Compensation Table.

In addition, Mr. Chappelle, Mr. Ellis and Mr. Cole retained their rights under their respective employment agreements to payment for any excise taxes imposed under Section 4999 of the Internal Revenue Code on their severance payments and benefits as a result of a change in control (within the meaning of their respective employment agreements) plus an additional amount that puts the executive in the same after-tax position he would have been absent the imposition of excise taxes under Section 4999 of the Internal Revenue Code. Mr. Chappelle’s, Mr. Ellis’ and Mr. Cole’s rights to receive termination payments and benefits, other than a prorated annual bonus for the year of termination, were conditioned upon executing a general release of claims in the Company’s favor, which was executed and became effective on January 3, 2019.

On November 13, 2018, Michael A. McCabe, Vice President, Chief Financial Officer and Assistant Secretary, announced his plans to retire. Mr. McCabe retired from the Company effective March 29, 2019. In connection with his departure, AMS entered into a Separation Agreement with Mr. McCabe pursuant to which he is entitled to (i) vesting acceleration for his outstanding awards under AMR’s 2018 Long-Term Incentive Plan (other than his 2018 performance units, which were canceled), (ii) 150% of his base salary in effect on the separation date, (iii) 150% of the greater of (x) his target bonus or (y) the amount of bonus paid for the year immediately preceding the year containing the separation date, and (iv) a lump sum payment of approximately $117,209, in each case in exchange for certain waivers and releases for the Company’s benefit. Mr. McCabe will also receive certain other benefits, such as continued coverage pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as set forth in the separation agreement. These payments were paid to Mr. McCabe upon receipt of a general effective release of claims in the Company’s favor. These amounts will be reflected in the All Other Compensation column of the Summary Compensation Table next year.

2018 Director Compensation

The members of the Board of Directors do not receive compensation for their services as directors. However, our directors may be reimbursed for their expenses in attending Board of Director meetings.

Securities Trading Policy

AMR’s securities trading policy provides that executive officers, including the named executive officers, and directors, may not, among other things, purchase or sell puts or calls to sell or buy AMR stock, engage in short sales with respect to AMR stock, buy our securities on margin or otherwise hedge their ownership of AMR stock. The purchase or sale of stock by executive officers and directors may only be made during certain windows of time and under the other conditions contained in our policy.

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

The following table sets forth as of February 1, 2019 the limited partnership interests in Alta Mesa beneficially owned by:

• all persons who, to the knowledge of our management team, beneficially own more than 5% of our outstanding limited partnership interests;

• each current director of AMH GP;

• each executive officer of AMH GP named in the Summary Compensation Table; and

• all current directors and executive officers of AMH GP as a group.

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Name of Beneficial Owner (1)	Percentage of Units Beneficially Owned
Certain Beneficial Owners
SRII Opco, LP (2)	100	%
SRII Opco GP, LLC (3)	—
Alta Mesa Resources, Inc. (4)	46.9	%
High Mesa Holdings, LP (5)	35.2	%
HPS Investment Partners, LLC (6)	8.5	%
Riverstone VI Alta Mesa Holdings, LP (7)	5.3	%
Officers and Directors
James T. Hackett	—
Kimberly O. Warnica	—
Harlan H. Chappelle	—
Michael E. Ellis (5)	—
Michael A. McCabe	—
Homer “Gene” Cole	—
Directors and principal officers as a group (6 persons)	—

(1) Unless otherwise indicated, each of the persons listed in the table may be deemed to have solve voting and dispositive power with respect to such shares and the address for all beneficial owners in this table is at 15021 Katy Freeway, Suite 400, Houston, Texas 77094.

(2) SRII Opco LP owns 100% of the economic interests in Alta Mesa and AMH GP. 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, L.P., Michael E. Ellis and Harlan H. Chappelle (collectively, the “Existing Owners”) own a 10% non-voting interest in AMH GP. The Existing Owners and AMH GP are parties to a voting agreement with SRII Opco LP pursuant to which the Existing Owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. 

(3) SRII Opco GP, LLC owns a non-economic general partner interest in SRII Opco, LP.

(4) Alta Mesa Resources, Inc. owns a 46.9% limited partnership interest in SRII Opco, LP and 100% of SRII Opco GP, LLC.

(5) The sole general partner of High Mesa Holdings, LP (the “Alta Mesa Contributor”) is High Mesa Holdings GP, LLC (“High Mesa GP”). High Mesa, Inc. holds a majority of the outstanding limited partner interests in the Alta Mesa Contributor and all of the outstanding limited liability company interests in High Mesa GP. The interests of the Alta Mesa Contributor are beneficially owned (either directly or through interests in HMI) by three groups, each consisting of affiliated parties: (i) AM MME Holdings, LP, Galveston Bay Resources Holdings, LP, Petro Acquisitions Holdings, LP, Petro Operating Company Holdings, Inc., Harlan H. Chappelle, Gene Cole, Mike McCabe, Dale Hayes, AM Equity Holdings, LP and MME Mission Hope, LLC (collectively, the “Management Holders”), (ii) HPS Investment Partners, 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. and United Insurance Company of America, Jade Real Assets Fund, L.P. (collectively, the “HPS Alta Mesa Holders”) and (iii) Bayou City Energy Management, LLC, BCE-MESA Holdings, LLC, and BCE-AMH Holdings, LLC (collectively, the “Bayou City Holders”). Mr. Ellis (who is our former Chief Operating Officer—Upstream), through his ownership in AM MME Holdings, LP, Galveston Bay Resources Holdings, LP, Petro Acquisitions Holdings, LP, Petro Operating Company Holdings, Inc. and AM Equity Holdings, LP, will effectively control the vote of the Management Holders, and as a result, may be deemed to beneficially own the limited partnership interests in Alta Mesa beneficially owned by each such entity. William W. McMullen, through his ownership of the Bayou City Holders may be deemed to beneficially own the shares beneficially owned by the Bayou City Holders. Mr. Ellis, Mr. McMullen, the Management Holders, the

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HPS Alta Mesa Holders and the Bayou City Holders disclaim beneficial ownership of the shares of the Alta Mesa Contributor and the other Alta Mesa Contributor holders except to the extent of their respective pecuniary interests therein.

(6) HPS Investment Partners, LLC (“HPS”) manages each of Mezzanine Partners II Delaware Subsidiary, LLC, KFM Offshore, LLC, KFM Institutional, LLC, AP Mezzanine Partners II, L.P. and Jade Real Assets Fund, L.P., which collectively directly own approximately 8.5% of the limited partner interests in SRII Opco LP. The business address of each of these entities is c/o HPS Investment Partners, LLC, 40 West 57th street 33rd Floor, New York, NY 10019. HPS also manages, directly or indirectly, each of Mezzanine Partners II Delaware Subsidiary, LLC, KFM Offshore, LLC, a wholly-owned subsidiary of Offshore Mezzanine Partners Master Fund II, L.P., KFM Institutional, LLC, a wholly-owned subsidiary of Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., and Jade Real Assets Fund, L.P. (collectively, the “HPS Kingfisher Members”). The HPS Kingfisher Members own an interest in KFM Holdco, LLC, which owns an approximate 4.2% direct interest in SRII Opco, LLC. The amounts set forth in this footnote do not include the amounts that may be beneficially owned by the HPS Alta Mesa Members or the HPS Kingfisher Members indirectly through HMI and KFM Holdco, respectively.

(7) David M. Leuschen and Pierre F. Lapeyre, Jr. are the managers of Riverstone Management Group, L.L.C. (“Riverstone Management”), which is the general partner of Riverstone/Gower Mgmt Co Holdings, L.P. (“Riverstone/Gower”), which is the sole member of Riverstone Holdings LLC (“Holdings”), which is the sole shareholder of Riverstone Energy GP VI Corp, which is the managing member of Riverstone Energy GP VI, LLC (“Riverstone Energy GP’”) which is the general partner of Riverstone Energy Partners VI, L.P., which is the general partner of AMR Partners, the manager of AMR Partners-U and the managing member of Riverstone Energy VI Holdings GP, LLC, which is the general partner of the Riverstone Contributor. Riverstone Energy GP is managed by a managing committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, E. Bartow Jones, N. John Lancaster, Baran Tekkora and Robert M. Tichio. As such, each of Riverstone Energy GP, Riverstone Energy GP VI Corp, Holdings, Riverstone/Gower, Riverstone Management, Mr. Leuschen and Mr. Lapeyre may be deemed to have or share beneficial ownership of the securities held directly by the Riverstone Contributor. Each such entity or person disclaims any such beneficial ownership. The business address of each of these entities and individuals is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 36th Floor, New York, NY 10019.

Securities Authorized for Issuance under Equity Compensation Plans

We do not have any equity compensation plans.

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

AMR has a policy with respect to the review and approval of related party transactions. A “Related Party Transaction” is any transaction, arrangement or relationship where we are a participant, the Related Party (defined below) had, has or will have a direct or indirect material interest, and the aggregate amount involved is expected to exceed $120,000 in any calendar year. “Related Party” includes (a) any person who is or was (at any time during the last fiscal year) an executive officer, director or nominee for election as a director; (b) any person or group who is a beneficial owner of more than 5% of our voting securities; (c) any immediate family member of a person described in provisions (a) or (b) of this sentence; or (d) any entity in which any of the foregoing persons is employed, is a partner or has a greater than 5% beneficial ownership interest.

High Mesa Agreement

In connection with the closing of the Business Combination, we entered into a management services agreement (the “High Mesa Agreement”) with HMI with respect to its non-STACK assets. Under the High Mesa Agreement, during the 180-day period following the Closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the High Mesa Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requests 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 High Mesa Agreement. Prior to 2018, we also incurred $0.8 million of costs for the

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direct benefit of HMI and the non-STACK assets, outside of the High Mesa Agreement. As of December 31, 2018, approximately $10 million was due from HMI for costs prior to 2018 and pursuant to the High Mesa Agreement. Subsequent to year-end, we billed HMI $0.9 million for incremental MSA costs incurred and have received approximately $1.0 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result, we have recognized an allowance for uncollectible accounts of $9.0 million to fully provide for the unremitted balance and may have future allowances for amounts incurred in 2019 prior to the termination of the MSA. We also may be subject to liabilities for the non-STACK assets for which we should have been indemnified.

Management Services Agreement-Kingfisher

In connection with the closing of the Business Combination, we entered into a management services agreement (the “Kingfisher Agreement”) with KFM. Under the Kingfisher Agreement, we will provide certain administrative, management and operational services necessary to manage the business of KFM and its subsidiaries (the “Services”). As compensation for the Services, KFM will pay us each month (i) a management fee of $10,000 and (ii) an amount equal to our costs and expenses incurred in connection with providing the Services.

We are obligated to provide the Services in accordance with reasonable and prudent practices, as relevant to the Services, of the oil and gas industry, and in material compliance with all applicable laws; provided that we will only be liable under the Kingfisher Agreement for our own gross negligence, willful misconduct and/or fraud. Under the Kingfisher Agreement, KFM will have customary audit rights that will survive the termination or expiration of the Kingfisher Agreement.

Pre-Closing Assignment Agreement

Prior to the closing of the Business Combination, we entered into an Assignment Agreement to transfer to the Alta Mesa Contributor our remaining non-STACK oil and gas assets and all liabilities associated therewith. The subsidiaries of the Alta Mesa Contributor agreed to indemnify us for any losses relating to the non-STACK assets, including any employment, environmental and tax liabilities.

Voting Agreement

Mr. Chappelle, Mr. Ellis and certain affiliates of Bayou City and Highbridge own an aggregate 10% voting interest in AMH GP. These individuals and entities were a party to a voting agreement with the AM Contributor and AMH GP, pursuant to which they have agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the closing of the Business Combination, the parties amended and restated the voting agreement to include SRII Opco LP as a party and the existing owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. The voting agreement will continue in force until SRII Opco LP elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in AMH GP.

Ownership in Us and Our General Partner 

Riverstone was admitted as a limited partner in SRII Opco in connection with its $200 million capital contribution to us on August 17, 2017, in exchange for limited partner interests in SRII Opco with respect to the economic rights to the STACK assets. 

During 2016, our former Class B limited partner, HMI contributed $300 million to us.  On December 31, 2016, HMI purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us.  HMI’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected subsequent to year-end in 2017.

Founder Notes

We were founded in 1987 by Mr. Ellis and we, or our subsidiaries, over time had entered into promissory notes to repay Mr. Ellis for contributions of working capital and other amounts. The Founder Notes, prior to the Business Combination, bore interest at 10.0% paid-in-kind and were unsecured and subordinated to all of our debt at that time. Interest and principal were originally to be payable upon maturity on December 31, 2021.

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The Founder Notes, totaling approximately $28.3 million including interest, were converted into equity interests in the AM Contributor immediately prior to the Business Combination. During the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, no amounts were paid in principal or interest. Interest payable on the Founder Notes was not compounded and amounted to $0.1 million, $1.2 million and $1.2 million in the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, respectively. Such amounts were added to the balance of the Founder Notes. See Note 8 - Discontinued Operations (Predecessor) in Part II, Item 8 for further information.

Land Consulting Services

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $166,000, $28,000, $186,000 and $146,000 for the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, respectively. Following termination of the contract, Brigid Murrell continued to provide services to the Company as an individual contractor and was paid $8,523 for services rendered in that capacity through December 31, 2018. 

Employee and Distribution

David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of approximately $1,157,774, $28,874, $250,000, and $425,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively.

David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of approximately $297,134, $67,322, $150,000, and $180,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively.

Promissory Note Receivables – High Mesa Services, LLC

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, 2018 and 2017, amounts due under the promissory note totaled$1.7 million and $1.5 million, respectively. 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, 2018 and 2017, the note receivable amounted to $11.7 million and $10.8 million, respectively. 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 intend to pursue all available 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 are directing our course of action in this matter. As of December 31, 2018, 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.

NWGP Services Agreement

We are party to a services agreement dated January 1, 2016 with NWGP.  Pursuant to the agreement, we agree to provide administrative and management services to NWGP relating to the midstream assets.  During the year ended December 31, 2018 NWGP was billed for management services provided in the amount of approximately $0.1 million.  HMI owns a controlling interest in NWGP.

Joint Development Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of Alta Mesa’s drilling operations and to allow Alta Mesa to accelerate development of our STACK acreage. The JDA establishes a

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development plan of 60 wells in three tranches, and provides opportunities for the parties to potentially agree to an additional 20 wells. Pursuant to the terms and provisions of the JDA, BCE committed to fund 100% of Alta Mesa’s working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for carrying the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return on each individual tranche. Following the completion of each joint well, Alta Mesa and BCE will each bear its respective proportionate working interest share of all subsequent costs and expenses related to such joint well.  Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time.  During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of December 31, 2018, 61 joint wells have been drilled or spudded. As of December 31, 2018 and 2017, $9.8 million and $23.4 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our consolidated balance sheets. At December 31, 2018, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA.

Gathering Agreements

On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM. The Gas Gathering and Processing Agreement was subsequently amended in February 2017, effective December 2016 and again in June 2018, effective April 2018.  Prior to the business combination, HMI owned a minority interest in KFM. Alta Mesa also indirectly owned a minimal interest in KFM through its 10% ownership of AEM.  In connection with the business combination, KFM is now a wholly owned subsidiary of SRII Opco LP.  We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM.

Under the Crude Oil Gathering Agreement and the Gas Gathering and Processing Agreement, Oklahoma Energy dedicates and delivers to KFM crude oil and natural gas and associated natural gas liquids produced from present and future wells located in certain lands in Kingfisher, Logan, Canadian, Blaine and Garfield Counties in Oklahoma for gathering and processing. The Crude Oil Gathering Agreement and Gas Gathering and Processing Agreements will remain in effect for a primary term of 15 years from the in-service date of July 1, 2016 and, after the primary term, an extended term for as long as there are wells connected to the system that continue to produce crude oil or gas in commercial (paying) quantities.

Under the Crude Oil Gathering Agreement, KFM operates a crude oil gathering system for the purpose of providing gathering services to Oklahoma Energy. KFM receives from Oklahoma Energy a fixed service fee per barrel of crude oil delivered. The fixed service fee consists of a fee for providing gathering services and is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the crude oil gathering system.

Under the Gas Gathering and Processing Agreement, KFM operates a gas gathering and processing system for the purpose of providing gathering and processing services to Oklahoma Energy. KFM provides gathering and processing services for a fixed fee. The fixed service fee consists of (i) a gathering fee assessed on the volume of gas received at the receipt points, (ii) a processing fee assessed on the volume of gas received at the receipt points, (iii) a dehydration fee assessed on the volume of gas received at the receipt points, (iv) a compression fee for each stage of compression for any volume of gas allocated to the central receipt point and (v) a facility fee which is eliminated after December 2020.  Beginning in January 2021, each fee is subject to an annual percentage increase tied to the consumer price index.  Oklahoma Energy also pays KFM its allocated share, if any, of the fuel, inclusive of electricity, consumed in the operation of the gas gathering and processing system. Under the Gas Gathering and Processing Agreement, we have secured firm processing rights of 260 MMcf/d at the expanding KFM plant.

The aggregate amounts paid under the Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement depends on the volumes produced and gathered pursuant to these agreements. Under such agreements, the fees for the years ended December 31, 2018 and 2017 were $24.4 million and $7.5 million, respectively.  The plant commenced operations in the second quarter of 2016.  These fees are recorded as marketing and transportation expense in the consolidated statements of operations.  As of December 31, 2018 and 2017, we accrued approximately $2.0 million and $3.0 million as a reduction of accounts receivable on the consolidated balance sheets for fees related to marketing and transportation for the KFM plant. Oklahoma Energy entered into an agreement with KFM whereby the Company made a deposit of $10.0 million on January 13,

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2017 to KFM to provide us with 100,000 Dth/day for firm transportation.  The deposit was released back to us when we began utilizing the marketing and transportation services in 2018.

In November 2018, we sold our produced water assets, consisting of over 200 miles of produced water gathering pipelines and related facilities, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of KFM, a related party and an entity under common control by our parent, AMR, for $98.0 million, including approximately $90.0 million in cash transferred during 2018. The remaining balance owed of approximately $8.0 million is included in related party receivables. In conjunction with the sale, we entered into a new fifteen-year produced water disposal agreement with KFM, under which we dedicated produced water from present and future wells located in certain lands in Kingfisher, Logan, Canadian, Blaine, Garfield and Major Counties in Oklahoma for gathering and disposal. KFM provides gathering and disposal services for a fixed fee of $1.00/barrel of water received at the receipt points. Beginning in January 2024, the fixed fee is subject to an annual percentage increase tied to the consumer price index.  Under the agreement, we recognized expense of $4.7 million during November and December of 2018. 

Shortfall Fees

On September 21, 2016, we entered into an agreement with KFM that beginning January 1, 2017 through January 31, 2022, we shall reimburse KFM for 50% of any shortfall fee paid by KFM to a third-party operator for any year in which the daily delivered gas volume is less than the daily gas volume committed.   During the period February 9, 2018 through December 31, 2018, cash payments required under our commitments totaled approximately $0.1 million.

Director Independence

Our Board of Directors consists of two members.  Because we do not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, we are not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, our Board of Directors has not made any determination as to whether the directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

Item 14. Principal Accounting Fees and Services 

On July 6, 2018 the Audit Committee approved the engagement of KPMG LLP as the Company’s independent registered public accountants to audit the financial statements of the Company for the periods within the year ended December 31, 2018.

KPMG LLP billed or will bill the Company or its subsidiaries for the aggregate fees set forth in the table below for services provided relating to fiscal year 2018. These amounts include fees paid or to be paid by the Company for professional services rendered for the audit of the Company’s annual financial statements.

	2018
Audit fees	$	1,154,500
Audit-related fees	87,500
Tax fees	—
All other fees	—
Total	$	1,242,000

Audit Fees

The audit fees for the periods within the year ended December 31, 2018 were for professional services rendered for the audit of our consolidated financial statements and review of our quarterly financial statements. 

Audit-Related Fees

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

Tax Fees

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Our independent registered public accountants did not provide income tax compliance, planning and advisory services to us during the periods in the year ended December 31, 2018.

All Other Fees

No other fees were billed by our independent registered public accountants for services rendered that are not reported under “audit fees” or “audit-related fees” above.

Pre-Approval Policies and Procedures

Since the Business Combination, the Audit Committee of the Board of Directors of AMR approves all services to be provided by the independent registered public accountants. All of the services provided by KPMG during fiscal 2018 were approved by the audit committee of AMR. 

PART IV

Item 15. Exhibits and Financial Statement Schedules

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

1. The Consolidated Financial Statements of Alta Mesa Holdings, LP 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:

Exhibit Number	Description of Exhibit
2.1	Contribution Agreement, dated as of August 16, 2017, by and among High Mesa Holdings, LP, High Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, Silver Run Acquisition Corporation II, and, solely for certain provisions therein, the Contributor Owners party thereto (incorporated by reference to Exhibit 2.1 to Alta Mesa Holdings, LP’s Form 8-K filed with the SEC on August 17, 2017 (File No. 333-173751))
3.1	Articles of Organization of Alta Mesa Holdings GP, LLC, dated September 26, 2005 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.2	Sixth Amended and Restated Limited Liability Company Agreement of Alta Mesa Holdings GP, LLC, dated February 9, 2018 (incorporated by reference from Exhibit 3.2 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on February 14, 2018 (File No. 333-173751)).
3.3	Certificate of Limited Partnership of Alta Mesa Holdings, LP, dated September 26, 2005 (incorporated by reference from Exhibit 3.3 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.4	Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa Holdings, LP, dated as of February 9, 2018 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on February 14, 2018 (File No. 333-173751)).
3.5	Certificate of Incorporation of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.7 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.6	Bylaws of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.8 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
4.1	Indenture, dated December 8, 2016, by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated by reference from Exhibit 4.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on December 8, 2016 (File No. 333-173751)).

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4.2	Registration Rights Agreement, dated December 8, 2016, by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp., the Guarantors named therein and Wells Fargo Securities, LLC, as representative of the Initial Purchasers (incorporated by reference from Exhibit 4.2 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on December 8, 2016 (File No. 333-173751)).
10.1	Eighth Amended and Restated Credit Agreement dated as of February 9, 2018 among Alta Mesa Holdings, LP, Alta Mesa Resources, Inc., 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.
10.6	Letter Agreement, dated as of February 9, 2018, by and between Alta Mesa Resources, Inc. 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).
10.7*	Letter Agreement, dated as of December 20, 2018, by and among Alta Mesa Services, LP, Randy Limbacher, John H. Campbell, Jr. and Mark P. Castiglione, and Meridian Energy LLC.
10.8*	Employment Agreement, dated as of January 7, 2019, by and between Alta Mesa Services, LP and John C. Regan.
10.9*	Employment Agreement, dated as of April 9, 2018, by and between Alta Mesa Services LP and Kimberly O. Warnica.
10.10	Employment Agreement, dated as of April 3, 2018, by and between Alta Mesa Services, LP and Craig W. Collins (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 9, 2018).
10.11	Employment Agreement, dated as of February 9, 2018, by and between Alta Mesa Services, LP and Michael A. McCabe (incorporated by reference to Exhibit 10.15 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.12	Employment Agreement, dated as of February 9, 2018, by and between Alta Mesa Services, LP and Ronald J. Smith (incorporated by reference to Exhibit 10.18 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018).
10.13*	Separation Agreement, dated as of December 20, 2018, by and between Alta Mesa Services, LP and Harlan H. Chappelle
10.14*	Separation Agreement, dated as of November 13, 2018, by and between Alta Mesa Services, LP and Michael A. McCabe.
10.15*	Separation Agreement, dated as of December 20, 2018, by and between Alta Mesa Services, LP and Michael E. Ellis.
10.16*	Separation Agreement, dated as of December 20, 2018, by and between Alta Mesa Services, LP and Homer “Gene” Cole.
10.25	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).
10.26	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, L.P., 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).

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21.1*	Subsidiaries of the Registrant.
23.3*	Consent of Ryder Scott Company, L.P.
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 April 25, 2019.
101*	Interactive data files.

* filed herewith.

Item 16. Form 10-K Summary

None.

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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 HOLDINGS, L.P.
		(Registrant)
By	/s/ John C. Regan
	John C. Regan
	Chief Financial Officer (Principal Financial Officer)
Dated	May 17, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on the 17th day of May 2019, by the following persons on behalf of the registrant and in the capacities indicated.

	Signature	Title
By:	/s/ James T. Hackett	Chairman of the Board of Alta Mesa Resources, Inc., Interim Chief Executive Officer and Director (Principal Executive Officer)
	James T. Hackett
By:	/s/ John C. Regan	Chief Financial Officer (Principal Financial Officer)
	John C. Regan
By:	/s/ Ronald J. Smith	Vice President, Chief Accounting Officer (Principal Accounting Officer)
	Ronald J. Smith

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