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 ~~annual~~fiscal ~~period~~year ended: December 31, ~~2017~~2018

☐ 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.)
(State or other jurisdiction ofincorporation or organization)	(I.R.S. EmployerIdentification No.)
15021 Katy Freeway, Suite 400, Houston, Texas	77094
(Address of principal executive offices)	(Zip Code)

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

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



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

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

~~Securities~~Indicate ~~registered~~by ~~pursuant~~check tomark ~~Section 12(g)~~if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act: ¨ Yes x No

~~None~~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 ifwhether the registrant is(1) has afiled ~~well-known~~all ~~seasoned~~reports ~~issuer,~~required asto ~~defined~~be infiled ~~Rule~~by ~~405~~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

~~Indicate~~(Explanatory byNote: ~~check~~The ~~mark~~registrant ifis ~~the~~a ~~registrant~~voluntary filer and is not ~~required~~subject to ~~file~~the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934. However, the registrant has filed all reports ~~pursuant~~required to be filed by Section 13 or ~~Section~~ 15(d) of the Securities Exchange Act~~: ☐ Yes ☒ No~~ 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 ~~(1)~~ has ~~filed~~submitted ~~all~~electronically ~~reports~~every Interactive Data File required to be ~~filed~~submitted bypursuant ~~Section 13~~to orRule ~~15(d)~~405 of ~~the~~Regulation ~~Securities~~S-T ~~Exchange~~(§232.405 ~~Act~~ of ~~1934~~this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to ~~file~~submit such ~~reports), and (2) has been subject to such filing requirements for the past 90 days~~files.) Yes ☒x No ☐ ¨

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

~~Indicate~~Large byaccelerated ~~check~~filer ~~mark~~¨ ~~whether~~Accelerated ~~the~~filer ~~registrant~~¨ ~~has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S~~Non-Taccelerated ~~(§232.405~~filer of¨ ~~this~~Smaller ~~chapter)~~reporting ~~during~~company ~~the~~¨ ~~preceding~~Emerging 12growth ~~months~~company ~~(or for such shorter period that the registrant was required to submit and post such files.) Yes ☒ No ☐~~ x

~~Indicate~~If an emerging growth company, indicate by check mark if ~~disclosure~~the ofregistrant ~~delinquent~~has ~~filers~~elected ~~pursuant~~not to ~~Item 405~~use ofthe ~~Regulation~~extended ~~S-K~~transition ~~(S229.405~~period offor ~~this~~complying ~~chapter)~~with isany ~~not~~new ~~contained~~or ~~herein,~~revised ~~and~~financial ~~will~~accounting ~~not~~standards beprovided ~~contained,~~pursuant to ~~the~~Section ~~best~~13(a) of ~~registrant’s~~the ~~knowledge,~~Exchange ~~in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K~~Act. ☒ ☐

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

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. (Check one):

Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒ (Do not check if smaller reporting company) Smaller reporting company ☐ Emerging growth company ☒

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

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

TABLE OF CONTENTS

		Page
	Glossary	ii
	Cautionary Statement Regarding Forward-Looking Statements	1
	PART I
Item 1.	Business	32
Item 1A.	Risk Factors	279
Item 1B.	Unresolved Staff Comments	4530
Item 2.	Properties	4530
Item 3.	Legal Proceedings	4535
Item 4.	Mine Safety Disclosures	4637
	PART II
Item 5.	Market ~~For~~for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	4637
Item 6.	Selected Financial Data	4738
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4838
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	6561
Item 8.	Financial Statements and Supplementary Data	6662
Item 9.	Changes in and Disagreements ~~With~~with Accountants on Accounting and Financial Disclosure	66102
Item 9A.	Controls and Procedures	66102
Item 9B.	Other Information	66106
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	67106
Item 11.	Executive Compensation	69108
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	78120
Item 13.	Certain Relationships and Related Transactions, and Director Independence	80122
Item 14.	Principal ~~Accountant~~Accounting Fees and Services	84126
	PART IV
Item 15.	Exhibits, ~~and~~ Financial Statement Schedules	84127
Item 16.	Form 10-K Summary	86129
	Signatures	130

~~Table of ContentsIndex to Financial Statements~~ i

~~CAUTIONARY~~Glossary ~~STATEMENT~~of ~~REGARDING FORWARD-LOOKING STATEMENTS~~ Terms

The ~~information~~definitions ~~in this 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~~abbreviations ofset ~~the~~forth ~~Securities~~below ~~Exchange~~apply ~~Act~~to ~~of 1934, as amended (~~the ~~“Exchange~~indicated Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial condition, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project,” the negative of such terms ~~and~~throughout 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 “Item 1A.Risk Factors” included in this ~~report~~filing. ~~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:



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

~~· business strategy;~~ii

·Enhanced ~~reserve~~recovery ~~quantities~~- The recovery of oil and natural gas through the ~~present~~injection ~~value~~of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of ~~our~~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.

~~· exploration and drilling prospects, inventories, projects and programs;~~iii

· our horizontal drilling, completion, and production technology;



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.

~~· ability to replace the reserves we produce through drilling and property acquisitions;~~iv

· financial strategy, liquidity and capital required for our development program;



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.

~~· future oil and natural gas prices;~~v

·Cautionary ~~timing~~Statement ~~and~~Regarding ~~amount~~Forward-Looking ~~of future production of oil and natural gas;~~Statements

·The ~~hedging~~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 ~~results;~~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 ~~drilling~~statements ~~and~~may ~~completion~~include ~~of wells, including~~ statements about ~~future horizontal drilling plans;~~:

·• ~~competition~~our ~~and~~ability ~~government~~to ~~regulation~~continue as a going concern;

·• ~~ability~~our tobusiness ~~obtain permits and governmental approvals~~strategy;

·• ~~changes~~our inreserve quantities and the ~~Oklahoma~~present ~~forced~~value ~~pooling~~of ~~system~~our reserves;

·• ~~pending~~our ~~legal~~exploration and ~~environmental~~drilling ~~matters~~prospects, inventories, projects and programs;

·• ~~marketing~~our ~~of oil~~drilling, ~~natural~~completion ~~gas~~ and ~~natural~~production ~~gas liquids~~technology;

·• ~~leasehold~~our orability ~~business~~to replace the reserves we produce through drilling and through acquisitions;

·• ~~costs~~future ofoil ~~developing~~and ~~our~~gas ~~properties~~prices;

·• ~~liquidity~~the supply and ~~access~~demand tofor ~~capital~~our production;

·• ~~ability~~the totiming ~~hire,~~and ~~train~~amount orof ~~retain~~our ~~qualified~~future ~~personnel~~production;

·• ~~general~~our ~~economic~~hedging ~~conditions~~strategy and expected results;

·• ~~future~~competition ~~operating results, including initial production values~~ and ~~liquids~~government ~~yields in our type curve areas~~regulation;

·• ~~the~~our ~~costs,~~ability ~~terms~~to ~~and~~obtain ~~availability~~permits ~~of gathering, processing, fractionation,~~ and ~~other~~governmental ~~midstream services~~approvals; ~~and~~

·• ~~plans,~~expected ~~objectives,~~or ~~expectations~~anticipated ~~and~~changes ~~intentions contained~~ in ~~this~~the ~~report~~Oklahoma ~~that~~forced ~~are~~pooling ~~not historical.~~system;

We• ~~caution~~pending ~~you~~legal ~~that these forward-looking statements are subject to all of the risks~~ and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, gathering and sale natural gas and natural gas liquids. These risks include, but are not limited to, commodity price volatility, low prices for oil, natural gas and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties and the other risks described under “Item 1A. Risk Factors” in this report. 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.

~~Table~~We caution you that any forward-looking statements are subject to all of ~~ContentsIndex~~the risks and uncertainties, most of which are difficult to ~~Financial~~predict ~~Statements~~ 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.

~~Reserve~~Estimating ~~engineering~~quantities of oil, natural gas and NGL reserves is acomplex ~~process~~and ofinexact. The ~~estimating~~process ~~underground~~relies ~~accumulations~~on interpretations of ~~oil~~geologic, ~~natural~~geophysical, ~~gas~~engineering and ~~natural~~production ~~gas~~data. ~~liquids~~The ~~that~~extent, ~~cannot~~quality, bereliability ~~measured~~and ininterpretation anof ~~exact~~these ~~way~~data can vary. The ~~accuracy~~process also requires a number of ~~any~~economic ~~reserve~~assumptions, ~~estimate~~such ~~depends~~as onoil, ~~the~~natural ~~quality~~gas ofand ~~available~~NGL ~~data~~prices, the ~~interpretation~~relative mix of ~~such~~oil, ~~data~~natural gas and ~~price~~NGLs that will be ultimately produced, drilling and ~~cost~~operating ~~assumptions~~expenses, ~~made~~capital byexpenditures, ~~reservoir~~the ~~engineers.~~effect ~~Specifically~~of government regulation, ~~future~~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 ~~natural~~ gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this ~~report~~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.

~~All~~Except ~~forward-looking~~as ~~statements,~~otherwise ~~expressed~~required orby ~~implied~~applicable law, ~~included~~we indisclaim ~~this~~any ~~report~~duty ~~are~~to ~~expressly~~update ~~qualified~~any inforward-looking ~~their~~statements, ~~entirety~~all byof ~~this~~which ~~cautionary~~are ~~statement.~~expressly ~~This~~qualified ~~cautionary~~by ~~statement~~the ~~should~~statements ~~also be considered~~ in ~~connection~~this ~~with~~section, ~~any~~to ~~subsequent~~reflect ~~written~~events or ~~oral~~circumstances ~~forward-looking~~occurring ~~statements~~after ~~that~~the wedate ~~may~~of ~~issue.~~this Annual Report.

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 after the date of this report.

Table of ContentsIndex to Financial Statements

PART I

Item 1. Business

Overview

Alta Mesa Holdings, LP, ~~(“Alta~~together ~~Mesa,”~~with ~~the~~its ~~“Company,”~~consolidated ~~“us,”~~subsidiaries (“~~our~~we,” or the “weCompany,”), is an independent exploration and production company ~~primarily~~focused ~~engaged~~on in the acquisition, ~~exploration~~development, ~~development~~exploration and ~~production~~exploitation of ~~oil,~~unconventional ~~natural~~onshore ~~gas~~oil and natural gas ~~liquids~~reserves ~~within~~in the ~~United~~eastern ~~States.~~portion Weof ~~have~~the ~~transitioned~~Anadarko ~~our~~Basin ~~focus~~in ~~from~~Oklahoma. We ~~our~~were ~~diversified~~formed ~~asset~~in ~~base~~1987 ~~composed~~as of a ~~portfolio~~private ofTexas ~~conventional~~limited ~~assets~~partnership. Our toprincipal anoffices ~~oil~~are ~~and~~at ~~liquids-rich~~15021 ~~resource~~Katy ~~play~~Freeway, inSuite ~~the~~400, ~~eastern~~Houston, ~~portion~~Texas of77094 ~~the~~and ~~Anadarko~~our ~~Basin~~main inphone ~~Oklahoma~~number ~~(the~~is ~~“STACK”~~(281) ~~with an extensive inventory of drilling opportunities~~530-0991.

~~The~~Beginning ~~STACK~~in isthe an1990’s, ~~acronym~~our ~~describing~~predecessor ~~both~~operations ~~its~~were ~~location—Sooner~~focused ~~Trend~~on ~~Anadarko~~vertical ~~Basin~~wells, ~~Canadian~~waterfloods and ~~Kingfisher~~analyzing ~~County—and~~ the ~~multiple,~~commercial ~~stacked~~productivity ~~productive~~of ~~formations present in~~ the ~~area.~~stacked ~~The~~formations ~~STACK~~on isour aacreage. Since ~~prolific~~2012, ~~hydrocarbon~~our ~~system~~activities ~~with~~have ~~high~~become ~~oil~~primarily ~~and~~directed ~~liquids-rich~~at ~~natural~~the ~~gas content, multiple~~ horizontal ~~target~~development ~~horizons,~~of ~~extensive~~an ~~production~~oil ~~history~~ and ~~high~~liquids-rich ~~drilling~~resource ~~success~~play ~~rates.~~in Asan ofarea ~~December 31, 2017, we have assembled a highly contiguous position~~ of ~~approximately~~the ~~130,000~~Anadarko ~~net~~Basin ~~acres~~commonly ~~largely~~referred into as the ~~up-dip,~~Sooner ~~naturally-fractured~~Trend ~~oil~~Anadarko ~~portion~~Basin ofCanadian ~~the~~and ~~STACK in eastern~~ Kingfisher County, ~~Oklahoma~~(“STACK”). The ~~Our~~STACK ~~drilling~~is ~~locations~~a ~~primarily~~prolific ~~target~~hydrocarbon ~~formations~~system ~~comprised~~with ofhigh ~~the~~oil ~~Osage, Meramec~~ and ~~Oswego.~~liquids-rich Wenatural ~~continue~~gas tocontent, ~~acquire acreage within and adjacent to our acreage footprint~~ with ~~the~~potential ~~goal~~for ofmultiple ~~operating~~horizontal ~~the~~target ~~drilling~~horizons, ~~completion~~extensive ~~and~~ production ~~operations~~history inand ~~such~~high ~~locations. At present, we are operating seven horizontal~~ drilling ~~rigs~~success inrates. ~~the~~We ~~STACK~~generally ~~with~~maintain ~~plans~~operational tocontrol ~~increase the number~~ of ~~rigs by~~ the ~~end~~majority of ~~2018. Following~~ our ~~business combination with Alta Mesa Resources~~properties, ~~Inc.~~either ~~(formerly~~through ~~Silver~~directly ~~Run~~operating ~~Acquisition~~them ~~Corporation~~or ~~II,~~through aoperating ~~Delaware~~arrangements ~~corporation~~with ~~(“AMR”))~~other ~~(as~~interest ~~described~~owners. We ~~below),~~conduct ~~our~~all ~~anticipated capital expenditures for 2018~~ of ~~$568~~our ~~million~~operations ~~are~~in ~~all allocated to~~ the ~~STACK~~Upstream segment.

WeAs ~~intend~~of toDecember ~~grow~~31, ~~our~~2018, ~~reserves~~we ~~and~~have ~~production~~assembled ~~through~~a ~~the~~highly ~~development~~contiguous ofposition ~~our multi-year inventory~~ of ~~identified~~approximately ~~drilling~~140,000 ~~locations~~net ~~within~~acres in the ~~STACK.~~up-dip, ~~From~~naturally-fractured ~~2012~~oil toportion ~~December~~of ~~31,~~the ~~2017~~STACK, weprimarily ~~increased~~in ~~our~~eastern ~~STACK~~Kingfisher ~~production~~and atsoutheastern aMajor ~~compound~~Counties ~~annual~~in ~~growth~~Oklahoma. ~~rate~~Our ~~(“CAGR”)~~drilling oflocations ~~approximately~~primarily ~~80%.~~target Wethe ~~increased~~Osage, ~~our~~Meramec ~~leasehold~~and ~~interests~~Oswego ~~from~~formations. When ~~approximately~~we ~~45,000~~consider ~~net~~acquiring ~~acres~~STACK inacreage, ~~early~~we ~~2015~~prioritize toopportunities ~~approximately~~where ~~130,000~~we ~~net~~can ~~acres~~be asthe ofoperator. ~~December~~During 312019, ~~2017~~we ~~primarily~~expect ~~through~~to ~~the~~focus ~~acquisition~~on ofoptimizing ~~largely~~completion ~~undeveloped leasehold.~~

Beginning in the early 1990s, our operations in the area later to become known as the STACK were focused on vertical wells, waterfloods and analyzing the commercial productivity of the stacked formations on our acreage. Since late 2012, however, we have concentrated on the horizontal development of the Mississippian-age Osage and Meramec formations, as well as the Pennsylvanian-age Oswego formation. We intend to expand this activity with horizontal wells to further develop other formations with demonstrated vertical production, including the Pennsylvanian-age Big Lime, Prue, Skinner, Red Fork and Cherokee Shale formations; Mississippian-age Manning Lime formation; Devonian-age Woodford Shale formation; and Silurian-age Hunton Lime formation. 2

Wedesign ~~consider our operations in the STACK to be in the early phase of a systematic, long-term development program. Our initial focus has been to delineate the Osage, Meramec~~ and Oswego formations through the drilling of horizontal wells in ten contiguous townships in Kingfisher County and one adjacent township in Garfield County. We have commenced infill development with seven multi-well ~~patterns of three to ten wells each~~spacing, ~~given~~reducing ~~that~~our wewell ~~expect~~costs ~~full~~and ~~development~~lowering of our ~~leasehold~~operating tocost ~~require~~structure ~~multiple~~(including ~~wells~~lease ~~per~~operating ~~drilling~~and ~~unit~~general ~~to maximize economic recovery of oil~~ and ~~natural~~administrative ~~gas from each formation~~expenses).

AsBusiness ofCombination December 31, 2017, our estimated total proved reserves were approximately 182.7 MMBOE, of which 96% were in the STACK. The estimated total proved reserves in the STACK were approximately 176.2 MMBOE, representing a 36% increase over 2016 year-end estimated proved reserves of 129.6 MMBOE in the STACK. Our total proved reserve mix is approximately 40% oil, 40% natural gas, and 20% natural gas liquids.

~~Business~~As ~~Combination~~described ~~with~~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”).

OnDuring ~~August 16, 2017, we entered into a Contribution Agreement (~~the ~~“AM~~fourth ~~Contribution~~quarter ~~Agreement”)~~of ~~with AMR~~2017, ~~High~~we ~~Mesa~~sold ~~Holdings,~~certain ~~LP, a Delaware limited partnership (the “AM Contributor”), High Mesa Holdings GP, LLC, a Texas limited liability company and the sole general partner~~ of ~~the~~our AMnon-STACK ~~Contributor,~~oil ~~Alta Mesa Holdings GP, LLC, a Texas limited liability company~~ and ~~our~~gas ~~sole~~assets ~~general partner (“AMH GP”),~~ and, ~~solely for certain provisions therein, the equity owners of the AM Contributor~~liabilities. Immediately ~~Simultaneous~~prior ~~with~~to the ~~execution~~closing of the AMBusiness ~~Contribution Agreement~~Combination, ~~AMR~~we ~~entered~~distributed ~~into~~our ~~(i)~~remaining anon-STACK ~~Contribution~~oil ~~Agreement~~and ~~(the~~gas ~~“KFM~~assets ~~Contribution~~and ~~Agreement”)~~liabilities ~~with~~to ~~KFM~~High ~~Holdco,~~Mesa ~~LLC~~Holdings, aLP ~~Delaware limited liability company~~ (the “~~KFM~~AM Contributor”), ~~Kingfisher~~such ~~Midstream,~~that ~~LLC,~~our aonly ~~Delaware~~remaining ~~limited~~oil ~~liability~~and ~~company~~gas ~~(“Kingfisher”),~~assets and, ~~solely~~liabilities ~~for~~were ~~certain~~located ~~provisions~~in ~~therein,~~ the ~~equity~~STACK. Information ~~owners~~related ofto ~~the~~our ~~KFM~~non-STACK ~~Contributor;~~oil and ~~(ii)~~gas aassets ~~Contribution Agreement (the “Riverstone Contribution Agreement”~~ and, ~~together~~liabilities ~~with~~that ~~the~~were AMsold ~~Contribution~~or ~~Agreement~~distributed ~~and~~is ~~the~~disclosed ~~KFM~~as ~~Contribution~~discontinued ~~Agreement,~~operations ~~the~~in ~~“Contribution~~Item ~~Agreements”)~~8 ~~with~~of ~~Riverstone~~this VIAnnual ~~Alta Mesa Holdings, L~~Report.~~P., a Delaware limited partnership (the “Riverstone Contributor”).~~

OnPursuant ~~February 9,~~to ~~2018 (~~the ~~“Closing~~Business ~~Date”)~~Combination, weour ~~consummated~~assets ~~the~~and ~~transactions~~liabilities ~~contemplated~~were byrecorded ~~the~~at ~~Contribution~~their ~~Agreements~~estimated ~~and~~fair ~~SRII Opco LP~~values, awhich ~~Delaware~~values ~~limited~~have ~~partnership~~been ~~(“SRII~~pushed ~~Opco~~down ~~LP”)~~to ~~acquired~~us. This ~~(a)~~resulted ~~(i) all~~in ofour ~~the~~financial ~~limited~~presentation ~~partner~~being ~~interests~~separated ininto ustwo ~~and~~distinct ~~(ii) 100%~~periods of- the ~~economic~~period ~~interests~~before ~~and 90% of~~ the ~~voting~~Business ~~interests~~Combination inon ~~AMH~~February GP9, ~~(with~~2018 (i“Predecessor”) and ~~(ii)~~the ~~collectively,~~period after the ~~“AM~~Business ~~Contribution”)~~Combination ~~and~~ (b“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.

Operating Summary:

Table of ContentsIndex to Financial Statements



	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

100% of the economic interests in Kingfisher (the “Kingfisher 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.” Seasonality

~~SRII~~Weather ~~Opco~~conditions ~~GP,~~affect ~~LLC,~~the ademand ~~Delaware~~for, ~~limited~~and ~~liability~~prices ~~company~~of, ~~(“SRII~~oil ~~Opco~~and ~~GP”),~~gas. During the ~~sole~~winter, ~~general~~natural ~~partner~~gas ofdemand ~~SRII~~for ~~Opco~~heating ~~LP,~~by isresidential aand ~~wholly~~commercial ~~owned~~consumers ~~subsidiary~~generally ofincreases ~~AMR. The~~whereas ~~limited~~high ~~partners~~summer oftemperatures ~~SRII~~can ~~Opco~~result LPin ~~are~~an ~~the~~increase AMin ~~Contributor,~~demand from the ~~KFM~~power ~~Contributor~~sector. Natural ~~and~~gas ~~the~~in ~~Riverstone~~storage ~~Contributor~~typically ~~(collectively,~~increases ~~the~~from ~~“Contributors”),~~April ~~AMR~~through ~~and~~October. Crude ~~certain~~oil ~~funds~~markets ~~managed~~tend byto ~~Highbridge. As~~be astronger ~~result~~in of the ~~Transactions,~~fourth ~~AMR~~quarter ~~has~~when ~~obtained~~demand ~~control~~for ~~over~~heating ~~the~~oil ~~management~~is ofimpacted ~~AMH~~by GPcolder weather and, ~~consequently,~~inventory usbuild. Hurricanes ~~AMR~~and isother asevere ~~publicly~~weather ~~traded~~(particularly ~~corporation~~along ~~that~~the isGulf ~~not~~Coast) ~~under~~can ~~the~~also ~~control~~impact ofsupplies ~~any~~by ~~person.~~causing ~~Prior~~disruptions toin the ~~closing~~level of ~~the~~oil ~~Transactions,~~and ~~AMH~~gas ~~GP,~~production. Due ~~and~~to ~~consequently,~~these usfluctuations, ~~was~~results ~~controlled~~of byoperations ~~High~~for ~~Mesa~~individual ~~and~~quarterly ~~indirectly~~periods bymay ~~our~~not ~~founder~~be ~~and~~indicative ~~Chief~~of ~~Operating~~the ~~Officer,~~results ~~Michael~~that E.may ~~Ellis.~~be realized on an annual basis.

Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company (“Bayou City”), and HPS Investment Partners, LLC, a Delaware limited liability company (“Highbridge”), continue to own an aggregate 10% voting interest in AMH GP following the closing. These existing owners were a party to a voting agreement with the AM Contributor and AMH GP, pursuant to which they agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the closing of the Transactions, 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 amended and restated 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. The closing of the business combination did not constitute a change of control under the indenture governing our 7.875% senior unsecured notes due December 15, 2024 (the “2024 Notes”). Competition

~~Consideration~~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:

~~Pursuant~~• toacquisitions ~~the AM Contribution Agreement, at the closing~~ of ~~the~~oil ~~Transactions~~and ~~(the~~gas ~~“Closing”)~~properties, ~~the~~exploratory AMprospects ~~Contributor~~and ~~received~~mineral 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco LP. The AM Contributor also acquired from AMR a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), corresponding to the number of Common Units received by the AM Contributor at the Closing. leases;

In• ~~addition~~evaluations ~~to the above, for a period~~ of ~~seven~~properties; ~~years following the Closing, the AM Contributor will be entitled to receive an aggregate of up to $800 million in earn-out consideration to be paid in the form of Common Units (~~and acquire a corresponding number of shares of Class C Common Stock) as specified below if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock of AMR equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):

	20-Day
	VWAP	Earn-Out Consideration
$	14.00	10,714,285 Common Units
$	16.00	9,375,000 Common Units
$	18.00	13,888,889 Common Units
$	20.00	12,500,000 Common Units


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

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

AMR also contributed $554 million in cash to us at the Closing. AMR’s source for these funds was from the sale of its securities to investors in a public offering and in private placements. We used a portion of the amount to repay all outstanding balances under the senior secured revolving credit facility.

Exchange or Redemption of Common Units

Beginning 180 days after the Closing, the AM Contributor will have the right to exchange its Common Units for shares of AMR Class A Common Stock or cash (at AMR’s election). Upon any redemption of Common Units by the AM Contributor, a corresponding number of shares of Class C Common Stock owned by the AM Contributor will be cancelled.

~~Table~~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 ~~ContentsIndex~~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 ~~Financial~~predict ~~Statements~~ when, or if, such future shortages will occur or their impact on our operations.

~~Amended~~With ~~Limited~~decreased ~~Partnership~~activity ~~and~~in ~~Limited~~the ~~Liability~~STACK ~~Company~~since ~~Agreement~~ 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.

InRegulatory connection with the closing of the business combination on February 9, 2018, AMH GP and SRII Opco LP entered into a Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa (the “Seventh Amended Partnership Agreement”). The Seventh Amended Partnership Agreement reflects, among other things, that SRII Opco LP is now the sole limited partner of Alta Mesa. Environment

InOur ~~addition,~~upstream onoperations ~~February 9,~~are ~~2018,~~subject ~~the~~to ~~owners~~stringent offederal, ~~AMH~~state GPand ~~entered~~local ~~into~~laws aand ~~Sixth~~regulations ~~Amended~~governing ~~and~~occupational ~~Restated~~safety ~~Limited~~and ~~Liability~~health, ~~Company~~the ~~Agreement~~discharge of ~~AMH~~materials GPinto (the ~~“Sixth~~environment ~~Amended~~and ~~LLC~~environmental ~~Agreement”),~~protection. ~~which~~Numerous ~~was~~governmental ~~amended to~~agencies, ~~reflect~~including ~~that SRII Opco LP, now~~ the ~~holder~~U.S. ofEnvironmental ~~all~~Protection ofAgency ~~the Class A Units~~ (~~as defined therein~~“EPA”) isand ~~entitled~~analogous tostate ~~100%~~agencies ofhave the ~~economic~~power ~~rights~~to ~~with~~enforce ~~respect~~compliance towith ~~AMH~~these ~~GP,~~laws and ~~that~~regulations ~~SRII~~and ~~Opco LP is now~~ the ~~holder~~permits ofissued ~~90%~~under ofthem, ~~the~~often ~~Class B~~requiring ~~Units~~difficult ~~(as~~and ~~defined~~costly ~~therein)~~actions. ~~which~~Among ~~are~~other ~~entitled~~things, tothese ~~100%~~laws ofand ~~the~~regulations ~~voting rights with respect to AMH GP.~~ may:

As• ~~described~~require ~~above,~~various onpermits ~~February 9,~~before ~~2018,~~drilling ~~all of the owners of AMH GP entered into an amended~~ and ~~restated~~other ~~voting~~regulated ~~agreement~~activities ~~(the “Voting Agreement”) regarding the voting of their interests in AMH GP.~~ commence;

~~Appointment~~• ~~and~~require ~~Departure~~installation of ~~Directors~~pollution control equipment and place other conditions on our operations;

In• ~~connection~~place ~~with~~restrictions ~~the~~on ~~business combination, Michael A. McCabe, Homer “Gene” Cole, Mickey Ellis, Don Dimitrievich, William W. McMullen and Mark Stoner resigned from~~ the ~~board~~use of ~~AMH~~materials ~~GP.~~for Inour ~~connection~~operations ~~with the business combination, James T. Hackett was appointed to the board of AMH GP. Harlan H. Chappelle~~ and ~~Michael~~upon ~~E. Ellis remain directors on~~ the ~~board~~disposal of ~~AMH~~by-products ~~GP. Our~~from ~~executive~~our ~~management team remains the same, except that Mr. Hackett is now Chairman of the Board.~~ operations;

~~Distribution~~• restrict the types, quantities and concentrations of ~~Non-Stack~~various ~~Assets~~ substances that can be released into the environment or used for our operations;

In• ~~connection~~limit ~~with~~our ~~the~~operations ~~closing~~on oflands ~~the~~lying ~~business~~within ~~combination~~wilderness, wewetlands ~~have completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil~~ and ~~liquids-rich~~other ~~resource~~protected play in the STACK. On February 8, 2018, we distributed the remainder of our non-STACK assets to AM Contributor as a dividend. At the time of the disposition, management estimated the carrying value of our remaining non-STACK assets to be $42.8 million with liabilities of $52.5 million, which liabilities include $44.6 million of asset retirement obligations. The remaining non-STACK assets distributed subsequent to year end will be reflected as discontinued operations in future filings when the criteria for discontinued operations for the remaining non-STACK are met under ASC 205-20, “Discontinued Operations”. areas;

~~Amended~~• require remedial measures to mitigate pollution from former and ~~Restated~~ongoing ~~Senior~~operations, ~~Secured~~including ~~Revolving~~site ~~Credit~~restoration, ~~Facility~~ pit closure and plugging of abandoned wells; and

In• ~~connection~~impose ~~with~~specific ~~the~~safety ~~closing of the business combination, we entered into the Eighth Amended~~ and ~~Restated~~health ~~Credit~~criteria ~~Agreement~~addressing ~~with~~worker ~~Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”)~~protection. The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base limit. The Eighth A&R credit facility does not permit us to borrow funds if at the time of such borrowing we are not in pro forma compliance with our financial covenants. As of February 9, 2018, all outstanding balances under our credit facility were paid in full.

~~For~~These ~~further~~laws, ~~details~~rules ofand ~~the~~regulations ~~business~~often ~~combinations~~impose ~~please~~difficult ~~Note~~and 19costly —compliance ~~Subsequent~~measures ~~Events~~that carry substantial administrative, civil and criminal penalties and may result in ~~the~~remedial ~~consolidated~~or ~~financial~~corrective ~~statements~~action obligations.

~~Weeks~~Resource ~~Island~~Conservation ~~Sale~~ and Recovery Act

~~During~~The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the ~~fourth~~generation, ~~quarter~~transportation, oftreatment, ~~2017~~storage, wedisposal ~~sold~~and ~~our~~cleanup ~~oil~~of non-hazardous and ~~natural~~hazardous ~~gas~~wastes. ~~properties~~Pursuant into rules issued by the ~~Weeks~~EPA, ~~Island~~the ~~field. Results~~individual ofstates ~~operations~~administer ~~for~~some ~~Weeks~~or ~~Island~~all ~~field~~of ~~are~~the ~~reflected~~provisions asof ~~discontinued~~RCRA, ~~operations~~sometimes in ~~our~~conjunction ~~consolidated~~with ~~financial~~their ~~statements~~own, ~~for~~more ~~all~~stringent ~~periods presented~~requirements. ~~See~~ ~~Note~~As 6part —of ~~Discontinued~~our ~~Operations~~operations, towe ~~the~~generate ~~consolidated~~some ~~financial~~amounts ~~statements~~of ~~for~~ordinary ~~details~~industrial wastes that may be regulatorily-deemed hazardous wastes. ~~Operating~~ ~~revenues~~Drilling fluids, produced waters, and ~~expenses~~most ~~for~~of ~~all~~the ~~periods~~other ~~exclude~~wastes ~~discontinued~~associated with our operations, inif ~~the~~properly ~~Weeks~~handled, ~~Island~~are ~~field. As~~currently ~~used~~exempt ~~herein~~from regulation as hazardous waste under RCRA and, ~~unless~~instead, ~~noted~~are ~~otherwise~~regulated under RCRA’s less stringent non-hazardous waste provisions, ~~amounts~~state ~~presented~~laws ~~will~~or ~~not~~other ~~include~~federal ~~the~~laws. ~~Weeks~~However, ~~Island~~it ~~field~~is possible that regulations could change and cause wastes now classified as non-hazardous to be classified as hazardous wastes.

~~2017~~Comprehensive ~~Highlights~~ Environmental Response, Compensation and Liability Act

~~During~~The ~~2017~~federal Comprehensive Environmental Response, weCompensation, ~~concentrated~~and ~~our~~Liability ~~efforts~~Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability on ~~developing~~classes ~~our~~of ~~assets~~persons inconsidered to be responsible for the ~~STACK~~release ~~play~~of hazardous substances and other classes of materials. ~~Highlights~~ ~~from~~Under ~~2017~~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 ~~total~~Water ~~estimated~~Pollution ~~proved~~Control reserves increased by 43.9 MMBOE or 32% from 138.8 MMBOE (including Weeks Island) in 2016 to 182.7 MMBOE in 2017, primarily as a result of our focus on the successful drilling activity and development in the STACK;Act

· total production increased by 41% from 6.1 MMBOE in 2016 to 8.6 MMBOE in 2017;

· total average daily production from our assets in the STACK increased by 58% from approximately 13.0 MBOE/d in 2016 to 20.6 MBOE/d in 2017;

~~Table~~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 ~~ContentsIndex~~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 ~~Financial~~help ~~Statements~~ 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 ~~total~~Drinking ~~revenues~~Water ~~from hydrocarbons increased 76% in 2017 as compared to 2016, as a result of higher commodity prices and higher production;~~Act

·Our ~~drilled~~underground ~~and~~injection ~~completed~~operations ~~134~~are ~~gross~~regulated ~~wells~~pursuant ~~(59.1~~to ~~net~~the ~~wells~~Underground Injection Control (“UIC”) inprogram ~~2017~~established inunder the ~~STACK~~federal Safe Drinking Water Act (“SDWA”) and 37analogous ~~gross~~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 ~~134~~subsurface ~~gross~~portions of the injection wells ~~drilled~~could ~~and~~cause ~~completed~~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 ~~STACK~~affected ~~were~~resource ~~funded~~and ~~pursuant~~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 ~~joint~~future ~~development~~may ~~agreement~~affect ~~with~~our ~~BCE-STACK~~ability ~~Development~~to ~~LLC~~dispose ~~(“BCE”)~~of ~~(described~~produced ~~below);~~waters and other substances, which could affect our business.

·Furthermore, ~~divested~~in ~~conventional~~response ~~assets~~to inrecent ~~our~~seismic ~~previous~~events ~~core~~near ~~area~~produced ~~Weeks~~water ~~Island~~disposal ~~field~~wells, ~~for~~federal ~~approximately~~and ~~$22~~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.5 ~~million~~In response to these concerns, asregulators ain ~~result~~some states have imposed, or are considering imposing, additional requirements in the permitting of aproduced ~~strategic~~water ~~shift~~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 ~~our~~2014 ~~operations~~that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to ~~become~~faults aand ~~STACK~~also, ~~pure-play~~from ~~company;~~time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations.

·Clean ~~invested~~Air ~~approximately $314 million in our oil and natural gas properties in 2017, as compared to $214 million in 2016 (both totals exclude acquisitions);~~Act

·Our ~~recognized~~operations ~~impairment~~are ~~expense~~subject into ~~2017~~the federal Clean Air Act (“CAA”) and comparable state laws and regulations that restrict the emission of ~~$30~~air pollutants.3 These ~~million~~laws asand ~~compared~~regulations may require us to ~~$16~~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.3 ~~million~~Obtaining insuch ~~2016;~~permits could delay our operations.

~~Industry~~National ~~Operating~~Environmental ~~Environment~~Policy ~~and Outlook~~ Act

~~The~~Our ~~success~~operations ofon ~~our~~federal ~~business~~lands ismay ~~highly~~be ~~dependent~~subject onto the ~~prices~~federal weNational ~~receive~~Environmental ~~for~~Policy ~~our~~Act ~~oil~~(“NEPA”), ~~natural~~which ~~gas~~requires ~~and~~federal ~~natural~~agencies, ~~gas~~including ~~liquids. Our~~the ~~industry has been significantly impacted by lower commodity prices in recent years. Commodity prices remained volatile~~EPA, ~~but~~to ~~generally~~evaluate ~~increased~~major onagency ~~average~~actions inhaving ~~2017~~the ~~relative~~potential to ~~2016~~significantly inimpact ~~response~~the ~~to improving supply and demand fundamentals and other factors~~environment. ~~Oil~~ ~~prices~~As inpart ~~particular showed significant signs~~ of ~~improvement~~such ~~in early 2018~~evaluations, ~~with~~an ~~NYMEX~~agency ~~West~~will ~~Texas~~prepare ~~Intermediate~~an ~~(“NYMEX~~environmental ~~WTI”)~~assessment ~~reaching~~that ~~$66.14~~assesses ~~per~~the ~~barrel~~potential onimpacts ~~January 26, 2018. As~~ of ~~March~~a ~~20,~~proposed ~~2018,~~project ~~NYMEX WTI was $63.40 per barrel~~ and ~~NYMEX~~may ~~Henry~~prepare ~~Hub~~a ~~was~~detailed ~~$2.68~~environmental ~~per~~impact ~~MMBtu. Commodity~~statement ~~prices~~for ~~remain~~public ~~unpredictable~~review and ~~it is uncertain whether the increase in market prices experienced in recent months will be sustained~~comment. ~~Therefore,~~ weOur ~~cannot~~current ~~predict~~and ~~with certainty the~~ future ~~prices~~operations ~~for~~on ~~the~~federal ~~commodities~~lands wewill ~~produce and sell. Forecasts can~~ be ~~impacted~~subject byto ~~many factors~~NEPA, ~~including~~which ~~but~~could ~~not~~delay ~~limited~~or toimpose ~~changes~~additional ~~in worldwide economic~~ conditions, ~~including~~and ~~the~~costs ~~European~~on ~~credit~~us. ~~markets; geopolitical activities~~Moreover, ~~including~~this ~~developments~~process incould ~~the~~experience ~~Middle East~~protest, ~~South~~appeal ~~America~~or ~~and~~litigation, ~~elsewhere;~~any ~~worldwide~~or ~~supply~~all ~~conditions; weather conditions; actions taken by the Organization~~ of ~~Petroleum~~which ~~Exporting~~may ~~Countries;~~impact ~~and~~our ~~the value of the U~~operations.~~S. dollar in international currency markets.~~

~~Our~~Occupational ~~anticipated~~Safety ~~capital expenditures, which include acquisitions, for 2018 are approximately $568 million. Additionally, we anticipate that up to an additional $25 million will be funded for 2018 drilling~~ and ~~completions~~Health activity in the STACK by BCE pursuant to our joint development agreement (described below). Following the business combination with AMR, our 2018 outlook is focused on the development of our assets in the STACK. Accordingly, we have allocated all of our 2018 capital expenditures to the STACK. We currently operate seven drilling rigs in the STACK and anticipate increasing to eight drilling rigs by the end of 2018, which will result in drilling a total of approximately 175 gross wells in the STACK. Act

~~Our~~We ~~Strategy~~ 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.

~~Our~~Hydraulic ~~primary business objective is to increase value through the execution of the following strategies:~~ Fracturing

· Economically grow production, cash flow and reserves by developing our extensive drilling inventory in the core of the STACK. We consider our large inventory of identified horizontal drilling locations in our primary target formations within the STACK to be relatively low-risk based on information gained from our own production history, the large number of existing wells in the area, the industry activity surrounding our acreage and the consistent and predictable geology on and surrounding our position. We intend to grow our reserves and production through the development of a multi-year inventory of identified drilling locations in our primary target formations within the STACK. These drilling locations represent a significant part of our growth strategy.6

·We ~~Maximize~~perform ~~the~~hydraulic ~~present~~fracturing ~~value~~in ofhorizontally ~~future~~drilled ~~cash~~wells. ~~flows~~Currently, ~~from~~most of our ~~acreage~~hydraulic ~~position.~~fracturing Weactivities ~~intend~~are toregulated ~~increase~~at the ~~recovery~~state oflevel ~~oil~~as ~~and~~the ~~natural~~EPA ~~gas~~only ~~from~~has ~~our~~limited ~~acreage~~purview ~~position~~over infracturing ~~the~~activities. ~~most~~However, ~~economically~~several ~~efficient~~federal ~~manner~~agencies ~~possible~~have toasserted ~~enhance~~regulatory ~~future~~authority ~~cash~~or ~~flows.~~pursued Toinvestigations ~~date,~~over ~~this~~certain ~~effort~~aspects ~~has~~of ~~focused~~the onhydraulic ~~developing~~fracturing ~~our~~process. ~~identified~~For ~~drilling~~example, ~~locations~~in December 2016, ~~continuously~~the ~~optimizing~~EPA ~~well~~released ~~completions~~its ~~and~~final ~~horizontal~~report ~~and~~on ~~vertical~~the ~~spacing~~potential impacts of ~~our~~hydraulic ~~horizontal~~fracturing ~~wells~~on ~~based~~drinking onwater ~~the~~resources, ~~results~~concluding ofthat ~~our~~“water ~~seven~~cycle” ~~spacing~~activities ~~tests.~~associated Wewith ~~also~~hydraulic ~~expect~~fracturing tomay ~~establish~~impact ~~the~~drinking ~~productive~~water ~~capability~~resources of“under ~~additional~~some ~~formations~~circumstances,” including ~~the~~water ~~Big~~withdrawals ~~Lime,~~for ~~Prue,~~fracturing ~~Skinner,~~in ~~Red~~times ~~Fork,~~or ~~Cherokee~~areas ~~Shale,~~of ~~Manning~~low ~~Lime,~~water ~~Woodford~~availability; ~~Shale~~surface ~~and~~spills ~~Hunton~~during ~~Lime~~the ~~formations.~~management ~~Based~~of onfracturing ~~results~~fluids, ~~from~~chemicals ~~our~~or ~~horizontal~~produced ~~drilling~~water; ~~program~~injection ~~and~~of ~~those~~fracturing offluids ~~offset~~into ~~operators,~~wells wewith ~~believe~~inadequate ~~significant~~mechanical ~~development~~integrity; ~~opportunities~~injection ~~exist~~of infracturing ~~these~~fluids ~~formations~~directly ininto ~~the~~groundwater ~~STACK~~resources; asdischarge ~~well~~of asinadequately ~~downspacing~~treated ~~opportunities~~fracturing ~~throughout~~wastewater ~~our~~into ~~acreage~~surface ~~position,~~waters; ~~thus~~and ~~potentially~~disposal ~~increasing~~or ~~our~~storage ~~horizontal~~of ~~drilling~~fracturing ~~inventory~~wastewater ~~significantly~~in unlined pits.

·Climate ~~Expand~~Change ~~drilling~~Regulations ~~inventory through strategic acquisitions. We believe that our highly contiguous acreage position~~ and extensive knowledge of the STACK will allow us to add acreage through grassroots leasing, acquisitions, pooling of interests and farm-ins. We believe our understanding of the geology, geophysics and reservoir properties of potential acquisition targets will allow us to identify and acquire highly prospective acreage in order to further grow our resource base. We increased our position in the STACK from approximately 45,000 net acres in early 2015 to approximately 130,000 net acres as of December 31, 2017 primarily through the acquisition of undeveloped acreage. We have 6Legislation

~~Table~~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 ~~ContentsIndex~~government to ~~Financial~~monitor ~~Statements~~ 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.

~~significant~~At ~~experience~~the infederal ~~successfully sourcing~~level, ~~evaluating~~no ~~and~~comprehensive ~~executing~~climate ~~acquisition~~change ~~opportunities~~legislation ~~and~~has ~~intend~~been implemented to ~~pursue~~date. ~~future~~The ~~acquisitions~~EPA has, ~~farm-ins~~however, adopted regulations that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and ~~forced~~Title ~~pooling~~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 ~~our~~“best ~~strategic~~available control technology” standards for those GHG emissions. Additionally, the EPA has adopted rules requiring the monitoring and ~~financial~~annual ~~objectives~~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 ~~Maximize~~agencies ~~single-well~~also ~~returns~~directly byregulate ~~optimizing~~emissions ~~drilling~~of ~~and~~methane, ~~completion~~a ~~techniques~~GHG, ~~through~~from ~~the~~oil ~~experience~~ and ~~expertise~~gas ofoperations. ~~our~~In ~~operating~~August ~~team.~~2016, ~~Our~~the ~~team~~EPA ~~uses~~issued a ~~multi-disciplinary~~final ~~approach~~New onSource anPerformance ~~ongoing~~Standards ~~basis~~(“NSPS”) torule, ~~evaluate~~known ~~our~~as ~~techniques~~Subpart ~~for well targeting~~OOOOa, ~~drilling,~~which ~~completions~~requires ~~and~~certain ~~operating~~new, ~~results~~modified ~~and~~or ~~compares~~reconstructed ~~our~~facilities ~~methods and results against other operators~~ in ~~our~~the ~~area~~oil ~~in order to improve our performance~~ and ~~identify~~gas ~~opportunities~~sector to ~~optimize~~reduce ~~our~~these ~~drilling~~methane gas and ~~completion~~volatile ~~techniques.~~organic Wecompound ~~have~~emissions. ~~incorporated~~These ~~increased~~Subpart ~~understanding~~OOOOa ofstandards ~~rock~~expand ~~properties~~previously toissued ~~target~~NSPS ~~landing~~published ~~zones~~by ~~for~~the ~~horizontal~~EPA ~~wells~~in 2012, asand ~~well~~known as ~~optimized~~Subpart ~~completion designs. A key element of cost reduction has been efficiency gains in drilling time~~OOOO, ~~improving~~by ~~from~~using ancertain ~~average~~equipment-specific ofemissions ~~over~~control ~~40 days from wells spud in 2012 to an average of 15 days in 2017~~practices.

·Other ~~Strategically~~Regulation ~~manage infrastructure and midstream services contracts to lower our costs. We seek to leverage existing legacy infrastructure, as well as exploit new infrastructure, to support our development~~ of multi-well pad drilling. We also utilize various midstream and marketing solutions to increase realizations and to provide access to multiple downstream natural gas and NGL markets. We currently have preferred access to the ~~Kingfisher~~Oil system through a firm processing commitment without any minimum volume commitment obligations as our midstream commitments pertain to acreage dedications only. Several midstream companies have recently expanded their gathering systems and ~~added~~Gas processing capacity to serve the STACK. The Kingfisher system and plant are located primarily within our acreage footprint and began operation in the second quarter of 2016. With the planned Kingfisher expansion underway, the Kingfisher system provides us with dedicated offtake while improving NGL realizations as well as the opportunity to expand our volumes delivered to the system once the expansion has been completed.Industry

·Our ~~Preserve~~operations aare ~~strong~~also ~~and~~subject ~~flexible capital structure~~ to ~~pursue~~various ~~our~~other ~~development~~types ~~program~~of ~~and~~regulation ~~acquisition~~at ~~opportunities.~~the Wefederal, ~~seek~~state ~~to maintain a strong capital structure that protects our balance sheet~~ and ~~liquidity~~local level. WeThese ~~expect~~types toof ~~fund~~regulation ~~our~~include ~~growth~~requiring ~~with~~permits ~~cash~~for ~~flow~~the ~~from~~drilling ~~operations~~of wells, ~~availability~~drilling ~~under~~bonds ~~our senior secured revolving credit facility~~ and ~~debt~~reports ~~and~~concerning ~~equity offerings when appropriate~~operations. ~~Consistent~~The ~~with~~state, ~~our~~and ~~disciplined~~some ~~approach~~counties toand ~~financial management~~municipalities, wein ~~expect~~which towe ~~maintain~~operate anmay ~~active~~also ~~hedging program to protect our cash flow and the funding of our capital program.~~regulate:

~~Our~~• ~~Strengths~~the location of wells;

We• ~~believe that~~ the ~~following~~method ~~strengths~~of ~~provide~~drilling ~~us with significant competitive advantages~~ and ~~position~~casing ~~us to continue to successfully execute our strategies:~~ wells;

·• ~~High quality acreage in~~ the ~~up-dip~~timing ~~oil window~~ of ~~the~~conducting STACK. The geology of the STACK presents numerous liquids-rich targets with large estimated ultimate recoveries per well, which results in very attractive wells and multiple well locations covering a given vertical section. We believe that the up-dip, naturally fractured oil window in eastern Kingfisher County, Oklahoma, where a substantial portion of our ~~acreage is located~~activities, isincluding aseasonal ~~particularly~~wildlife attractive portion of the STACK. We believe the geology underlying our acreage results in a higher oil component of our production stream relative to the rest of the STACK, which enhances the equivalent per-unit revenue of our production at current commodity prices. The productive areas on our highly contiguous acreage position are located at approximately 4,000 to 8,000 total vertical depth. Our target formations are shallower in eastern Kingfisher County than in other parts of the STACK, which results in significantly lower capital costs and an increase in our return on capital.closures;

·• ~~Large, highly contiguous acreage position with multi-year inventory of low-risk horizontal drilling locations. Our acreage in~~ the ~~STACK~~rates ~~is characterized by a liquids-weighted inventory~~ of ~~horizontal drilling locations that provides attractive growth opportunities. Our core~~ production area in the STACK has supported production since the 1940s and has a well-established infrastructure from historical operations. Our large, highly contiguous acreage blocks and focus on maintaining operational control provide us the flexibility to adjust our drilling and completion techniques in order to optimize our well results. Additionally, our highly contiguous acreage allows us to leverage existing infrastructure for more cost-efficient development and transportation. Our acreage position in the STACK also provides growth potential from an inventory of identified gross horizontal drilling locations to develop the Osage and Meramec formations, and identified gross horizontal drilling locations to develop the Oswego formation. Based on results from our horizontal drilling program and those of other operators, we believe significant development opportunities exist in other formations in the STACK.;

·• ~~Substantial experience in~~ the ~~STACK~~surface ~~and~~use ~~unconventional drilling techniques. We have owned portions of our current acreage position since 1992~~ and ~~developed~~restoration ~~a deep familiarity with STACK geology due to the length~~ of ~~our~~properties ~~operating~~where ~~history. Additionally,~~ we have an experienced and technically-adept management team, averaging more than 24 years of industry experience. We have built a strong technical staff of geologists and geophysicists, field operations managers, and engineers. Our technical expertise, coupled with our STACK experience has enabled us to grow proved reserves and production in the STACK since 2012. Our recent focus in the STACK has been to implement a multi-year, multi-rig program to develop the Osage, Meramec and Oswego formations using horizontal drilling and multi-stage hydraulic fracturing technology. Our completion design has increased in number of stages and sand per stage with each new generation of wells. Since early 2013, our completion practices have progressed through four major generations in 7operate;

~~Table~~• ofthe ~~ContentsIndex~~plugging toand ~~Financial~~abandoning ~~Statements~~ of wells;

~~completion~~• ~~hardware,~~interactions ~~hydraulic~~with ~~fracture~~surface ~~spacing,~~owners ~~fluid selection~~ and ~~proppant~~other ~~loading~~third inparties; ~~order to optimize single-well returns. We have proactively modified completion designs with each generation of new wells, which has led to improved well response.~~and

·• ~~Robust~~abandonment ~~midstream~~of ~~infrastructure~~pipelines ~~supports production growth~~ and access to markets. We have relationships with multiple gas gathering and processing companies including DCP Midstream, LLC (“DCP”), Mustang Gas Products, LLC (“Mustang”), EnLink Midstream Partners, LP (“EnLink”), MarkWest Energy Partners, L.P. (“MarkWest”) and Energy Transfer Partners, L.P. (“Energy Transfer”). These companies, in conjunction with Kingfisher, provide the midstream ~~and operational infrastructure necessary to support our drilling schedule and expected production growth~~facilities. Kingfisher commissioned its system to be “purpose built” to synchronize with our gathering needs, and those of other STACK operators, stemming from the expected horizontal development of our acreage position. The Kingfisher system and plant began operation in the second quarter of 2016, which enhanced our takeaway capacity given our dedicated 60 MMcf/d contracted volume with Kingfisher. Additionally, Kingfisher’s planned 200 MMcf/d plant expansion is under way, and we have contracted for up to 100% of the additional capacity. We believe this will ensure the continuous development of our horizontal inventory.

·State ~~Financial~~laws ~~strength~~regulate the size and ~~flexibility~~shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. We ~~have~~rely aupon ~~strong~~the ~~financial~~Oklahoma ~~position~~“forced ~~and~~pooling” aprocess ~~prudent~~to ~~financial~~facilitate ~~management~~working ~~strategy~~interest owners’ participation in our operations. Under this process, ~~which~~if ~~will~~a ~~allow~~party usproposes to ~~actively~~drill ~~allocate~~the ~~capital~~initial well to a particular formation in ~~order~~a tospecific ~~grow~~drilling ~~production,~~and ~~reserves~~spacing unit but cannot obtain the agreement of all other oil and ~~cash~~gas ~~flow.~~interest Weholders ~~believe~~and ~~our~~other ~~cash~~leaseholders ~~flow~~within ~~from~~the ~~operations~~unit as to how the unit should be developed, ~~along~~the ~~with~~party ~~borrowing~~may ~~capacity~~initiate ~~and~~“forced ~~existing~~pooling”. ~~cash~~Under current regulations, ~~will~~drilling ~~provide~~and usspacing ~~with~~units ~~sufficient~~for ~~liquidity~~our targeted horizons are based on a maximum of four to ~~execute~~eight horizontal wells, depending on ~~our~~the ~~2018~~formation, ~~capital~~on ~~program~~a 640-acre section. ~~Additionally~~In a forced pooling action, wethe ~~have~~proposed operator files an ~~effective~~application ~~hedging~~for ~~program~~a inpooling ~~place~~order towith ~~protect~~the ~~our~~Oklahoma ~~future~~Corporation ~~cash~~Commission ~~flows~~(“OCC”) and ~~provide~~names ~~more~~all ~~certainty~~other ~~for~~persons with the ~~budgeting~~right ofto ~~our~~drill ~~capital~~the ~~plan~~unit as respondents. WeThe ~~plan~~proposed operator is required to ~~continue~~demonstrate ~~our~~that ~~hedging~~it ~~program~~has made a good faith effort to ~~protect~~bargain ~~future~~with ~~revenues~~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.

~~Partnership Structure~~ 7

WeAssuming ~~are~~the ~~structured~~application asfor a ~~private~~forced ~~partnership. Since~~pooling ~~our~~order ~~inception~~is ~~in 1987~~granted, wethe respondents then have ~~funded~~20 ~~exploration~~days to elect either to participate in the proposed well or accept fair value for their interest, ~~development~~usually ~~and~~in ~~operating~~the ~~activities~~form ~~primarily~~of ~~through~~a cash ~~from operations~~payment, ~~contributions~~an byoverriding ~~our~~royalty, ~~limited~~or ~~partners~~some combination, ~~borrowings~~based ~~under~~on ~~our~~the ~~senior~~fair ~~secured~~value ~~credit~~established ~~facilities~~and approved through the administrative hearing. The pooling order typically addresses the time frame for drilling the well and ~~proceeds~~provides ~~from~~for the ~~issuance~~manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of ~~senior~~the ~~unsecured~~wells ~~notes~~subject to the pooling order.

~~Our~~The ~~partnership~~availability ~~agreement~~of ~~currently~~forced ~~provides~~pooling normally means that it is difficult for ~~interests~~a tosmall benumber ~~divided~~of ~~into~~owners ~~economic~~to ~~units~~block ~~held~~or bydelay the ~~partners~~drilling ~~referred~~of toa asparticular ~~“LP~~well ~~Units”~~proposed by another interest holder. Oil and ~~non-economic~~gas ~~general~~companies ~~partner~~in Oklahoma generally attempt to lease as much of the mineral interests ~~owned~~in bya ~~AMH~~particular GParea (as ~~defined~~are ~~below)~~readily ~~referred~~available at acceptable rates, and then use the forced pooling process to asproceed ~~“GP~~with ~~Units”~~the desired development of the well. ~~AMH~~ In GPthis ~~owns~~manner, ~~all~~we have the GPability ~~Units~~to expand into and ~~SRII~~develop ~~Opco~~areas LPnear ~~owns~~our existing acreage even if we are unable to lease all of the LPmineral ~~Units~~interests in those areas.

AsThe agross ~~limited~~production ~~partnership~~tax, ~~our~~or ~~operations~~severance ~~and~~tax, ~~activities~~is ~~are~~a ~~managed~~value-based bytax ~~the~~levied ~~board~~at a basic rate of ~~directors~~7% (upon the ~~“Board~~production of ~~Directors”)~~oil ofand ~~our~~gas ~~general~~in ~~partner, AMH GP~~Oklahoma. ~~The~~ ~~limited~~As ~~liability~~an ~~company~~economic ~~agreement~~incentive ofto ~~AMH~~develop GPits ~~provides~~resources, ~~for~~Oklahoma ~~two~~has ~~classes~~historically ofoffered ~~interests:~~a ~~(i)~~“tax ~~Class~~holiday” Awith ~~Units,~~rates ~~which~~ranging ~~hold~~from ~~100~~1% offor ~~the~~48 ~~economic~~months ~~interests~~to in2% ~~AMH~~for GP36 ~~and~~months ~~(ii)~~for ~~Class~~production Bfrom ~~Units,~~horizontal ~~which~~wells. ~~hold~~Through ~~100%~~June of2018, ~~the~~Oklahoma ~~voting~~imposed ~~interests~~a intax ~~AMH~~of ~~GP. SRII~~2% ~~Opco~~of LPgross isproduction for the ~~sole~~first ~~owner~~36 months of ~~Class~~production ~~A Units~~ and ~~owns~~then 90at 7% ofthereafter ~~the~~on ~~Class~~wells Bdrilled ~~Units. Harlan~~after HJuly 1, 2015. ~~Chappelle~~Effective July 2018, ~~our~~the ~~Chief~~2% ~~Executive~~tax ~~Officer~~rate ~~and~~was aincreased ~~director,~~to ~~Michael~~5% ~~Ellis,~~for ~~the~~wells ~~founder~~drilled after July 1, ~~our~~2015 ~~Chief~~that ~~Operating~~were ~~Officer~~still ~~and~~within ~~Chairman~~their offirst ~~the~~36 ~~Board~~months of ~~Directors~~production. For ~~and~~the ~~certain~~period ~~affiliates~~beyond of36 ~~Bayou City~~months, ~~and~~the ~~Highbridge,~~tax ~~own~~rate anremains ~~aggregate~~at 107% offor the ~~Class~~remaining Bproductive ~~Units~~life of each well. ~~AMH~~ All ~~GP’s~~wells ~~Board~~drilled ofafter ~~Directors~~July 1, 2018 are ~~selected~~taxed byat ~~the~~5% ~~Class~~of Bgross ~~Members. Notwithstanding~~production for the ~~foregoing,~~first ~~voting~~36 ~~control~~months of ~~AMH~~production GPand isthen ~~vested~~at in7% ~~SRII~~thereafter. ~~Opco~~In LPaddition, ~~pursuant~~a tolongstanding aexcise ~~voting~~tax ~~agreement~~of 0.095% continues to be levied.

~~All~~Federal, ~~distributions~~state ~~under~~and ~~our~~local ~~partnership~~regulations ~~agreement~~provide ~~are~~detailed ~~made~~requirements tofor the ~~limited~~abandonment ~~partners~~of ~~pro~~wells, ~~rata~~closure ~~when~~or ~~AMH~~decommissioning GPof soproduction ~~directs~~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.

~~Reserve~~Regulation ~~and~~of ~~Production~~Natural ~~Overview~~Gas Sales and Transportation

The ~~following~~rates, ~~table~~terms ~~describes~~and ~~our~~conditions ~~proved~~applicable ~~reserves~~to the interstate transportation of oil and ~~production~~natural ~~profile~~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 ~~December~~Title 31XVIII 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, ~~2017:~~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.

	Total							Average
	Estimated		Liquids as %					Daily Net
	Proved		of Total		PV-10		Net	Production
	Reserves	% Proved	Proved		($ in Millions)	Net	Producing	2017
	(MMBOE)	Developed (1)	Reserves (1)		(2)	Acreage (3)	Wells (4)	(MBOE/d) (5)
STACK	176.2	30%	61%	$	1,100.4	131,403	411.2	20.6
Other	6.5	83%	38%		5.5	328,663	60.9	2.9
All Properties	182.7	32%	60%	$	1,105.9	460,066	472.1	23.5

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 (1ethane, propane, butane, iso-butane and natural gasoline) ~~Computed~~by asrail ais ~~percentage~~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 ~~total~~train ~~reserves~~accidents and the increase in the rail transportation of flammable liquids. In October 2015, the ~~area~~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.

(2) PV-10 was calculated using oil and natural gas price parameters established by current Securities and Exchange Commission (“SEC”) guidelines and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the twelve months ended December 31, 2017. Because we are a partnership and, as such, are 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 United States generally accepted accounting principles, which is reduced for the discounted value of estimated future income taxes. Calculation of PV-10 does not give effect to derivatives transactions. The unweighted arithmetic average prices as of the 8

~~Table of ContentsIndex to Financial Statements~~ Other

~~first~~The ~~of each month during the twelve months ended December 31, 2017 were $51.34 per Bbl of~~ oil and ~~$2.98 per MMBtu of natural~~ gas. ~~The~~industry ~~estimated~~is ~~realized~~also ~~prices~~subject ~~for~~to ~~natural~~other ~~gas~~federal, ~~liquids~~state ~~using a $51.34 per Bbl benchmark~~ and ~~adjusted~~local ~~for~~regulations ~~average differentials were $26.06. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket~~ and ~~current~~laws ~~prices~~relating ~~for~~to ~~various~~resource ~~components~~conservation ~~thereof, such as butane, ethane,~~ and ~~propane,~~employment ~~among others~~standards.

~~(3) Includes developed and undeveloped acreage.~~Employees

~~(4)~~As ~~Calculated~~of asMay ~~gross~~1, ~~wells~~2019, ~~times~~we ~~our~~had ~~working~~138 ~~interest~~full-time ~~percentage~~employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.

(5) Average daily net production in the year ended December 31, 2017. The average daily net production excludes the Weeks Island field, which we sold during the fourth quarter of 2017. See Note 6 — Discontinued operations for further details.Insurance

~~Our~~We ~~Properties~~ 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.

~~STACK~~We regularly execute master services contracts with our third-party vendors, ~~Oklahoma~~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.

AsAvailable of December 31, 2017, we have assembled a highly contiguous position of approximately 130,000 net acres largely in the up-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma, which makes up about 96% of our proved reserves. This position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet. The legacy operations within our acreage are primarily shallow-decline, long-lived oil fields developed on 80-acre vertical well spacing associated with waterfloods in the Oswego, Big Lime and Manning Limestones. We continue to maintain production in these historical pay zones. Information

AsWe ofperiodically ~~December~~disseminate ~~31,~~information ~~2017,~~about wethe ~~had~~Company athrough ~~68%~~required ~~average~~filings ~~working~~we ~~interest~~make inwith ~~608~~the ~~gross~~SEC ~~producing~~and, ~~wells. We~~at ~~produced~~our 7discretion,~~513~~ ~~MBOE~~on our parent company’s website at www.altamesa.net. Information tocontained uson ~~from~~or connected to our ~~STACK~~website ~~properties~~is innot ~~2017,~~incorporated anby ~~increase~~reference ofinto ~~58%~~this asAnnual ~~compared~~Report toand ~~4,768~~should ~~MBOE~~not inbe ~~2016. During~~considered ~~2017,~~part weof ~~spent~~this ~~approximately~~Annual ~~$356 million~~Report inor ~~the~~any ~~STACK~~other ~~for~~filings ~~the~~we ~~drilling~~make ~~and~~with ~~completion~~the ofSEC. The ~~wells,~~SEC asmaintains ~~well~~a assite ~~other~~that ~~expenditures~~contains ~~for~~reports, ~~facilities~~proxy and ~~acquisition~~information ofstatements ~~leaseholds. For~~and ~~the~~other ~~twelve~~information ~~months~~regarding ~~ended~~issuers ~~December~~that ~~31,~~file. Our ~~2017,~~annual wereports ~~have~~on ~~received~~Form ~~approximately~~10-K, ~~$92.7~~quarterly ~~million~~reports ~~from~~on ~~BCE~~Form ~~under~~10-Q, ~~our~~current ~~joint~~reports ~~development~~on ~~agreement. We~~Form ~~currently~~8-K, ~~operate~~are ~~seven~~filed ~~drilling~~electronically ~~rigs~~and inare ~~the~~available ~~STACK~~free ~~for~~of ~~horizontal~~charge ~~development~~at http://www. Wesec.gov ~~plan~~. Our toreports ~~increase~~are tonot ~~eight~~separately ~~drilling~~available ~~rigs~~on byour ~~the~~parent ~~end~~company’s ~~of 2018~~website. Accordingly, ~~targeting~~ the ~~Mississippian-age~~Company ~~Osage,~~will ~~Meramec,~~provide ~~and~~electronic ~~Manning~~or ~~formations~~paper ~~and~~copies ~~the~~free ~~Pennsylvanian-age~~of ~~Oswego~~charge ~~formation~~upon ~~with~~request ~~horizontal~~to ~~drilling. We~~our ~~will~~parent ~~also~~company’s ~~participate~~Secretary inat ~~other~~15021 ~~horizontal~~Katy ~~wells~~Freeway, asSuite a400, ~~non-operator~~Houston, ~~primarily~~Texas ~~targeting~~77094 ~~the~~or ~~Oswego~~by ~~Lime,~~calling ~~Meramec~~(281) ~~and Osage~~530-0991.

Following the closing of the business combination, our capital expenditure budget for 2018 of approximately $568 million is all allocated to the STACK. Additionally, we anticipate that up to an additional $25 million will be funded for 2018 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement (described below). We currently operate seven drilling rigs in the STACK and anticipate increasing to eight drilling rigs by the end of 2018, which will result in drilling a total of approximately 175 gross wells in the STACK. ໿

~~Bayou~~Item 1A. ~~City~~Risk ~~Joint Development Agreement~~ Factors

InEach ~~January~~of ~~2016,~~the wefollowing ~~entered~~risk ~~into~~factors acould ~~joint~~adversely ~~development~~affect ~~agreement~~our ~~with BCE~~business, aoperating ~~fund~~results ~~advised~~and byfinancial ~~Bayou~~condition ~~City,~~(which towe ~~fund~~individually aand/or ~~portion~~collectively ofrefer ~~our~~to ~~drilling~~as ~~operations~~having ~~and~~“an toadverse ~~allow~~effect on us.” toIt ~~accelerate~~is ~~development~~not ofpossible ~~our~~to ~~STACK~~foresee ~~acreage.~~or Onidentify ~~December 31,~~all ~~2016,~~such ~~High~~factors. ~~Mesa~~Investors ~~purchased~~should ~~from~~not ~~BCE~~consider ~~and~~this ~~contributed~~list ~~interests~~an inexhaustive ~~the~~statement ~~Contributed~~of ~~Wells~~all ~~drilled~~risks ~~under~~and ~~the~~uncertainties. ~~joint~~This ~~development~~report ~~agreement~~also tocontains usforward-looking ~~with~~statements anthat ~~effective~~involve ~~date~~risks ofand ~~October~~uncertainties. 1,Our ~~2016. The~~actual ~~drilling~~results ~~program~~may ~~will~~differ ~~fund~~from ~~the~~those ~~development~~anticipated ofin 80these ~~additional~~forward-looking ~~wells,~~statements inas ~~four~~a ~~tranches~~result of 20both ~~wells~~the ~~each.~~risks Asdescribed ofbelow ~~December~~and ~~31,~~factors ~~2017,~~described 54elsewhere ~~joint~~in ~~wells~~this ~~have~~report. ~~been~~Please ~~drilled~~read orthe ~~spudded~~section ~~leaving~~above 26entitled ~~joint~~“Cautionary ~~wells~~Statement toRegarding beForward-Looking ~~drilled~~Statements” ~~under~~for ~~the~~further ~~joint~~discussion ~~development~~of ~~agreement.~~these matters.

~~Under the joint development agreement~~Oil, ~~BCE~~gas ~~has committed to fund 100% of our working interest share up to a maximum average of $3.2 million in drilling~~ and ~~completion~~NGL ~~costs~~prices ~~per well for any tranche. We~~ are ~~responsible~~highly ~~for~~volatile ~~any drilling~~ and ~~completion~~a ~~costs~~sustained ~~exceeding~~decrease ~~this~~in ~~limit.~~prices Incan ~~exchange~~significantly ~~for the payment of drilling~~ and ~~completion~~adversely ~~costs,~~affect ~~BCE receives 80% of~~ our ~~working~~financial ~~interest (the “BCE Interest”) in each wellbore~~condition, ~~which~~results ~~the BCE Interest will be reduced to 20%~~ of ~~our~~operations ~~initial~~and ~~working interest upon BCE achieving a 15% internal rate of return on~~ the ~~wells~~carrying ~~within~~value ~~a tranche and automatically further reduced to 12.5%~~ of our ~~initial interest upon BCE achieving a 25% internal rate of return~~assets. ~~Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs and expenses related to such joint well.~~

~~Market~~Historically, ~~Access~~ 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:

We• ~~have~~domestic ~~favorable~~and ~~access~~worldwide tosupply ~~physical markets for our crude oil~~of, ~~natural gas~~ and ~~NGLs~~demand ~~produced from our STACK leasehold. Our operations are located less than 60 miles from the principal North American hub~~ for, ~~crude~~ oil ~~in Cushing~~, Oklahoma, providing access to regional and national refining and petrochemical markets. We are also served by pipelines transporting NGLs to processing centers and market hubs in Kansas and the Gulf Coast region. Numerous natural gas ~~gathering systems~~ and associated processing facilities have been in operation in proximity to our STACK assets for several decades and midstream companies have recently installed more robust gathering infrastructure and modern gas processing facilities to support increasing production volumes in the area. We sell a portion of our natural gas to legacy gas processors, including DCP, Mustang, EnLink, MarkWest and Energy Transfer. 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;

~~Table~~• 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 ~~ContentsIndex~~armed tohostilities, ~~Financial~~or ~~Statements~~ acts of terrorism in the United States or elsewhere;

In• the ~~second~~effect ~~quarter~~ of ~~2016,~~worldwide ~~Kingfisher~~energy ~~commissioned~~conservation a 60 MMcf/d cryogenic gas processing facility within our acreage footprint. This facility receives natural gas from the Kingfisher gathering system, which (i) is designed to accommodate the anticipated larger volumes we expect to produce from multi-well pads and ~~(ii) offers~~environmental ~~assurance~~protection ~~of processing and residue capacity to support future production growth. Kingfisher has commenced a 200 MMcf/d expansion that it expects to be operational by end of April 2018.~~ efforts;

We• ~~have committed~~ the ~~oil~~price and ~~natural~~availability ~~gas production from our Kingfisher County acreage, not otherwise committed to others, to Kingfisher. As part~~ of ~~the~~alternative Kingfisher contract, we have secured firm processing rights of 260 MMcf/d at the expanding Kingfisher facility, which provides multiple sales outlets for marketing residue natural gas from our growing STACK production volumes and ~~minimizes~~competing the effect of future processing limitations due to overall STACK production increases. Beginning June 1, 2018, our subsidiary, Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”), will have residue natural gas firm transport along the Oneok Gas Transmission pipeline for 100,000 dekatherm per day. There is no minimum volume commitment associated with the Kingfisher contract. 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 a third-party operator for any year in which the daily delivered gas volume is less than the daily gas volume committed. Prior to the consummation of the business combination, affiliates of our former Class B limited partner, High Mesa, owned minority equity interests in Kingfisher, as describe more in detail under “Item 13. Certain Relationships and Related Transactions, and Director Independence — Gathering Agreements.” fuels;

~~Other~~• ~~Assets~~ the value of the dollar relative to the currencies of other countries;

~~Through~~• ~~February 8, 2018, we conducted operations in other areas. On February 8, 2018, we distributed~~ the ~~remainder~~level of ~~our~~foreign ~~non-STACK~~imports ~~assets~~of to AM Contributor as a dividend. The remaining non-STACK assets distributed subsequent to year end will be reflected as discontinued operations in future filings when the criteria for discontinued operations for the remaining non-STACK are met under ASC 205-20oil, ~~“Discontinued~~gas ~~Operations”.~~ and NGLs;

~~Our~~• ~~Oil~~domestic and ~~Natural~~foreign ~~Gas~~governmental ~~Reserves~~laws, regulations and taxes;

~~The~~• ~~table~~stockholder ~~below~~activism ~~summarizes~~or ~~our~~activities ~~estimated~~by ~~net~~non-governmental ~~proved~~organizations ~~reserves~~to aslimit certain sources of ~~December~~funding 31for the energy sector or restrict the exploration, ~~2017:~~development and production of oil and gas;

	As of December 31, 2017
	Oil
	and
	NGLs	Gas
	(MBbls)	(MMcf)
Proved Reserves (1)
Developed	32,527	150,183
Undeveloped	77,878	283,336
Total Proved	110,405	433,519


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

~~(1)~~• ~~Our~~general ~~proved~~economic ~~reserves~~conditions as of December 31, 2017 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the twelve months ended on such dateworldwide. These average prices were $51.34 per Bbl for oil and $2.98 per MMBtu for natural gas. The estimated realized price for natural gas liquids using a $51.34 per Bbl benchmark adjusted for average differentials was $26.06. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others. Pricing was adjusted for basis differentials by field based on our historical realized prices. See “Note 21 — Supplemental Oil and Natural Gas Disclosures (Unaudited)” in the accompanying notes to consolidated financial statements included elsewhere in this report for information concerning proved reserves.

The ~~table~~long-term ~~above~~effects represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of ~~funds.~~these ~~The process of estimating reserves is complex. This process requires significant decisions~~ and ~~assumptions~~other infactors the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the ~~same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas~~ prices, ~~revenues, taxes, development expenditures, operating expenses and quantities~~ of ~~recoverable~~ oil ~~and natural gas reserves will most likely vary from those estimated. In addition~~, ~~we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural~~ gas ~~prices~~ and ~~other~~NGLs ~~factors, many of which~~ are ~~beyond our control~~uncertain. ~~Sustained~~ Historical ~~lower~~declines ~~prices~~in ~~will~~commodity ~~cause the unweighted arithmetic average to decrease over time as the lower~~ prices ~~are~~have ~~reflected~~adversely inaffected ~~the average price, which may result in the estimated quantities and present values of~~ our ~~reserves~~business ~~being reduced and may necessitate future write-downs.~~ 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

~~Table~~• ofour ~~ContentsIndex~~ability to ~~Financial~~acquire, ~~Statements~~ locate and produce new reserves.

~~Internal~~On ~~Controls~~April ~~Over~~1, ~~Reserve~~2019, ~~Estimates~~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 ~~Qualifications~~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 ~~Technical~~our ~~Persons~~ 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 ~~policies~~ability ~~and practices regarding internal controls over the recording of reserves is structured~~ to ~~objectively~~continue ~~and accurately estimate our oil and gas reserves quantities and present values in compliance with rules, regulations and guidance provided by the SEC,~~ as ~~well~~a asgoing ~~established~~concern ~~industry~~contemplates ~~practices used by independent engineering firms and our peers, and in accordance~~ the ~~2007~~realization ~~Petroleum~~of ~~Resources~~assets ~~Management System sponsored~~ and ~~approved by~~ the ~~Society~~satisfaction of ~~Petroleum~~liabilities ~~Engineers,~~in the ~~World~~normal ~~Petroleum~~course ~~Council, the American Association~~ of ~~Petroleum~~business, ~~Geologists~~including ~~and~~ the ~~Society~~effective ofimplementation ~~Petroleum Evaluation Engineers. The reserve estimation process begins with our Corporate Planning~~ and ~~Reserves~~success ~~department, which gathers and analyzes much~~ of ~~the data used in estimating reserves. Working and net revenue interests are cross-checked and verified by~~ our ~~land~~plans ~~department. Lease~~to ~~operating~~mitigate ~~and capital expenses are provided by our accounting department and reviewed by~~ the ~~Corporate~~conditions ~~Planning~~that ~~and~~raise ~~Reserves~~substantial ~~department. Our~~doubt ~~Vice~~about ~~President of Corporate Planning and Reserves is the technical person primarily responsible for overseeing the preparation of~~ our ~~reserve~~ability ~~estimates.~~to ~~His~~continue ~~qualifications~~as ~~include~~a ~~the~~going ~~following:~~ concern.

·Our ~~Over~~consolidated 30financial ~~years~~statements have been presented on the basis that we would continue as a going concern, which contemplates the realization of ~~practical~~assets ~~experience~~and satisfaction of liabilities in ~~petroleum~~the ~~engineering~~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 ~~estimation~~pressures created by lower commodity prices in late 2018 and ~~evaluation~~early 2019. Based on our current operating and commodity price forecast and our current capital structure, and in the absence of ~~reserves;~~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 ~~Bachelor~~March of2019, ~~Science~~our ~~Degree~~parent’s inboard ~~Petroleum~~of ~~Engineering~~directors ~~from~~authorized the ~~University~~retention of ~~Texas~~financial inadvisors ~~1980,~~to ~~Masters~~assist ofin ~~Business~~evaluating ~~Administration~~the ~~from~~available ~~Oklahoma~~financial ~~City~~alternatives, ~~University~~including inwithout ~~1988;~~limitation:

·• ~~Registered~~amending ~~Professional~~or ~~Engineer~~waiving inthe ~~Oklahoma.~~covenants or other provisions of our debt;

~~Our~~• ~~methodologies~~raising ~~include~~new ~~reviews~~capital of production trends, material balance calculations, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on volumetric analysis or analogy to offset production in ~~the~~private ~~same~~ or ~~similar~~public ~~fields.~~markets; and

We• ~~maintain~~taking ~~internal~~other ~~controls~~actions ~~including~~to ~~the~~address ~~following~~our tobalance ~~ensure~~sheet ~~the~~either ~~reliability~~in court or through an out of ~~reserves~~court ~~estimations:~~agreement with creditors.

·We noare ~~employee’s~~also ~~compensation~~considering isoperational ~~tied~~matters tosuch ~~the~~as ~~amount~~reducing our forecasted capital plan. Any combination of ~~reserves~~such ~~booked;~~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 ~~follow~~pursue ~~comprehensive~~a ~~SEC-compliant~~restructuring, ~~internal~~it ~~policies~~may be necessary for us to ~~determine~~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 ~~report~~consummation ~~proved~~of ~~reserves;~~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 ~~reserve~~business ~~estimates~~strategy ~~are~~involves ~~made~~the byuse ~~experienced~~of ~~reservoir~~technology, ~~engineers~~which orinvolves ~~under~~risks ~~their~~and ~~direct~~uncertainties ~~supervision;~~in ~~and~~its application.

·Our ~~each~~operations ~~quarter~~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 ~~Chief~~development ~~Operating~~plan ~~Officer~~for ~~and~~2019 ~~Chief~~relies ~~Executive~~upon ~~Officer~~less ~~review~~innovation ~~all~~than ~~significant~~in ~~reserves~~prior ~~changes~~years, our use of emerging technologies may not prove successful and ~~all~~could ~~new~~result ~~proved~~in ~~undeveloped~~unexpected costs or decreases to production or the expected recoverability of reserves ~~additions~~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:

Ryder Scott Company, L. P. (“Ryder Scott”), a third party consulting firm, audited 97% of our 2017 proved reserves on a 6:1 MCF/BBL conversion basis.

Copies of the audit letters issued by Ryder Scott are filed with this report as Exhibits 99.1, and 99.2. The qualifications of the technical persons at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.

Michael Stell earned a B.S. in Chemical Engineering at Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. Mr. Stell is a licensed Professional Engineer in the State of Texas. Based on his educational background, professional training and over 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

The reserve audit by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202.

A reserves audit and a financial audit are separate activities with unique and different processes and results. These two activities should not be confused. As currently defined by the SEC within Regulation S-K, Item 1202, a reserves audit 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. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

Proved Undeveloped Reserves

At December 31, 2017, we had PUDs of 125.1 MMBOE, or approximately 68% of total proved reserves.

Total PUDs at December 31, 2016 were 98.4 MMBOE, or 71% of our total proved reserves. The following table reflects the changes in PUDs during 2017:

~~Table~~• oflanding ~~ContentsIndex~~our towellbore ~~Financial~~in ~~Statements~~ the desired drilling zone;

		MBOE
Proved undeveloped reserves, December 31, 2016		98,386
Converted to proved developed		(4,083)
Proved undeveloped reserve extensions and discoveries		32,972
Proved undeveloped reserves acquired		1,846
Proved undeveloped reserves sold		(746)
Proved undeveloped reserve revisions		(3,274)
Proved undeveloped reserves, December 31, 2017		125,101


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

~~PUDs~~• ~~converted~~running ~~to proved developed reserves were primarily in the STACK,~~ our ~~most~~production ~~active~~casing ~~development area. During 2017, we incurred approximately $26.3 million in expenditures to convert~~ the ~~December~~entire ~~31,~~length ~~2016~~of ~~PUDs to proved developed reserves. Extensions and discoveries were due to increases in PUD reserves associated with our successful drilling activity in~~ the ~~STACK. In 2017, we had negative revisions of 3,274 MBOE primarily due to PUD~~ wellbore; ~~interest assignments~~ and extension of tranche reversions related to the BCE joint development agreement, which were partially offset by positive price revisions. Estimated future development costs, including plugging and abandonment cost (“P&A”), for PUDs remaining are approximately $978.4 million at December 31, 2017.

~~Under~~• ~~current~~running ~~SEC~~tools requirements, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the original date of booking unless specific circumstances justify a longer time. We will be required to remove our PUDs if we do not drill those reserves within the required five year time frame, unless specific circumstances justify a longer time. All of our PUDs at December 31, 2017 are scheduled to be drilled within five years of the original date of booking. The future development of such proved undeveloped reserves is dependent on future commodity prices, costs and other ~~economic~~equipment ~~assumptions~~consistently inthrough ~~our forecasts. Lower prices for oil and natural gas may cause us to forecast less capital to be available for development of our PUDs in~~ the ~~future,~~horizontal ~~which may cause us to decrease the amount of our PUDs we expect to develop within the five-year time frame~~wellbore. ~~In addition, lower oil and natural gas prices may cause our PUDs to become uneconomic to develop at future SEC pricing, which would cause us to remove them from the proved undeveloped category.~~

WeThe ~~reevaluate~~difficulties ~~our five year PUD schedule quarterly. However, the relative proportion of total PUD reserves~~ that we ~~develop~~face ~~over~~while ~~the~~completing ~~next~~our ~~five years will not be uniform year to year, but will vary by year depending on several factors, including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory~~ wells ~~(wells~~include ~~where a third-party operator has elected to drill a well and we are faced with either drilling~~ the well or incurring penalties or where we need to drill or recomplete a well to preserve a lease), drilling acreage to hold it with production, and the inclusion of new acquisitions with associated PUDs. When developing our long range plan, we prioritize drilling based on many factors including product prices, capital availability and expected rates of return. As a result, we may drill PUDs with smaller net reserves but with higher returns. following:

~~During~~• ~~2016~~designing and ~~2017,~~executing wethe ~~focused~~optimum onfracture ~~drilling~~stimulation ~~wells~~program ~~to hold our acreage and expand our proved reserves, as opposed to drilling PUD locations~~ for ~~development~~a ~~purposes~~specific astarget most of our PUDs are currently held by production. We anticipate drilling in excess of 170 wells in each of the following five years. At year-end 2017, we had approximately 398 PUD locations in our inventory and, of these locations, approximately 300 are operated by us. During 2018 and 2019, we are only required to drill 30 PUD wells and will begin pattern development as we continue to focus on drilling other wells to expand our proved reserves. By 2020 and 2021, we will need to have drilled 83 and 147 wells, respectively. Accordingly, we anticipate drilling the large majority of our currently booked PUDs in the aggregate before drilling commitments become due in 2020 and 2021. 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.

~~Table~~In addition, we will require significant additional capital over a prolonged period in order to pursue the development of ~~ContentsIndex~~these locations, and we may not be able to ~~Financial~~access ~~Statements~~ 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.

~~Production,~~Our ~~Prices~~undeveloped ~~and~~properties ~~Production~~include ~~Cost~~leases ~~History~~that will expire over the next several years if production is not established on units containing that acreage.

~~The~~Leases ~~following~~on ~~table~~oil ~~sets~~and ~~forth~~gas ~~certain~~properties ~~information~~typically ~~regarding~~have ~~the~~a ~~production~~term ~~volumes~~of three to five years, ~~average~~after ~~prices~~which ~~received~~they expire unless renewed or, prior to expiration, a well is drilled and ~~average~~production of hydrocarbons in paying quantities is established. Although the majority of our reserves are located on leases that are held by production, ~~costs~~the ~~associated~~leases ~~with~~included in our ~~sale~~unproved properties typically have provisions whereby a lease will expire at the end of ~~oil,~~the ~~natural~~lease ~~gas~~term unless certain conditions are met, ~~and~~such ~~natural~~as ~~gas~~commencement ~~liquids~~of ~~for~~drilling or the existence of production in paying quantities within defined time periods. A ~~indicated~~reduction ~~below~~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. ~~For~~ The ~~additional~~cost ~~information~~to onrenew ~~price~~such ~~calculations~~leases may increase significantly, ~~please~~and ~~see~~we ~~information~~may ~~set~~not ~~forth~~be inable ~~“Item~~to 7renew such leases on commercially reasonable terms or at all. ~~Management’s~~This ~~Discussion~~could result in a reduction in our acreage and ~~Analysis~~growth opportunities (or the incurrence of ~~Financial~~significant ~~Condition~~costs). Our drilling plans for undeveloped acreage are subject to change based upon various factors, including drilling results, oil, gas and ~~Results~~NGL prices, the availability and cost of ~~Operations~~capital, ~~Results~~drilling and production costs, availability of ~~Operations”:~~ drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

	Year Ended December 31,
	2017		2016		2015
Net production:
Oil (MBbls)		4,167		2,904		2,813
Natural gas (MMcf)		18,115		13,384		10,478
Natural gas liquids (MBbls)		1,387		956		678
Total (MBOE)		8,573		6,090		5,238
Total (MMcfe)		51,440		36,542		31,426
Average sales price per unit before hedging effects:
Oil (per Bbl)	$	49.44	$	40.54	$	46.22
Natural gas (per Mcf)		2.63		2.20		2.52
Natural gas liquids (per Bbl)		24.36		16.38		16.01
Combined (per BOE)		33.52		26.74		31.95
Combined (per MMcfe)		5.59		4.46		5.32
Average sales price per unit after hedging effects:
Oil (per Bbl)	$	49.13	$	68.96	$	76.39
Natural gas (per Mcf)		3.01		2.69		4.63
Natural gas liquids (per Bbl)		23.31		16.04		16.01
Combined (per BOE)		34.00		41.31		52.37
Combined (per MMcfe)		5.67		6.88		8.73
Average costs per BOE:
Lease and plant operating expense	$	7.10	$	7.62	$	10.28
Marketing and transportation expense		3.56		2.11		0.60
Production and ad valorem taxes		0.84		0.68		1.20
Workover expense		0.69		0.58		0.99
Average costs per Mcfe:
Lease and plant operating expense	$	1.18	$	1.27	$	1.71
Marketing and transportation expense		0.59		0.35		0.10
Production and ad valorem taxes		0.14		0.11		0.20
Workover expense		0.11		0.10		0.17

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

~~Table~~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 ~~ContentsIndex~~proved reserves and projections of future cash flows and production rates and the timing of development expenditures may prove to ~~Financial~~be ~~Statements~~ 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 ~~following~~standardized ~~table~~measure ~~provides a summary~~ of our ~~production,~~proved ~~average~~reserves ~~sales~~will ~~prices~~not ~~and~~be ~~average~~the ~~production~~same ~~costs~~as ~~for~~ the ~~STACK~~current ~~area,~~fair ~~which~~value ~~contributes approximately 96%~~ of our ~~total~~oil ~~proved~~and ~~reserves~~gas ~~as of December 31, 2017;~~ properties.

	Year Ended December 31,
STACK	2017		2016		2015
Net production:
Oil (MBbls)		3,907		2,570		2,006
Natural gas (MMcf)		13,973		8,247		4,276
Natural gas liquids (MBbls)		1,277		823		499
Total (MBOE)		7,513		4,768		3,217
Total (MMcfe)		45,077		28,610		19,310
Average sales price per unit before hedging effects:
Oil (per Bbl)	$	49.76	$	41.16	$	45.90
Natural gas (per Mcf)		2.70		2.43		2.51
Natural gas liquids (per Bbl)		24.62		17.21		16.74
Combined (per BOE)		35.10		29.35		34.55
Average production costs per BOE:
Lease and plant operating expense	$	5.32	$	4.75	$	6.40
Marketing and transportation expense		3.92		2.44		0.49
Production and ad valorem taxes		0.74		0.58		0.58
Workover expense		0.57		0.72		0.78
Average production costs per Mcfe:
Lease and plant operating expense	$	0.89	$	0.79	$	1.07
Marketing and transportation expense		0.65		0.41		0.08
Production and ad valorem taxes		0.12		0.10		0.10
Workover expense		0.09		0.12		0.13

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:

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

As• ofactual ~~December~~cost ~~31, 2017, we had no commitments to provide a fixed quantity~~ of ~~oil,~~development ~~natural~~and ~~gas~~production ~~or natural gas liquids.~~ expenses;

~~Drilling~~• ~~Activity~~ the amount and timing of actual production;

~~The~~• ~~following~~transportation ~~table sets forth, for each of the three years ended December 31, 2017, 2016~~ and ~~2015,~~processing ~~the~~cost ~~number of net productive~~ and ~~dry~~availability; ~~exploratory~~ and developmental wells completed, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

	Year Ended December 31,
	2017	2016	2015
Development wells (net):
Productive	59.0	29.9	34.6
Dry	—	—	2.0
Total development wells	59.0	29.9	36.6
Exploratory wells (net):
Productive	0.1	3.0	3.9
Dry	—	—	4.9
Total exploratory wells	0.1	3.0	8.8


•	changes in governmental regulations or taxation.

WeThe ~~had~~timing ~~one~~of both our production and our incurrence of expenses in connection with our operations will affect the timing and amount of actual future net ~~well~~revenue ~~that~~and isthus aour ~~developmental~~oil ~~dry~~and ~~hole~~gas properties’ actual present value. ~~The~~ In ~~well~~addition, ~~was~~the a10% ~~recompletion~~discount ~~related~~factor we use in the standardized measure may not be the most appropriate discount factor to utilize in determining the fair value of our ~~non-STACK~~oil ~~assets~~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.

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

AsA ofkey ~~December~~component ~~31,~~to ~~2017,~~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 43program ~~gross~~for ~~(18~~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 2019.0 We ~~net)~~may ~~wells~~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.

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

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

~~The~~Our ~~following~~business ~~table~~activities ~~sets~~are ~~forth~~subject ~~information with respect~~ to ~~our~~operational ~~ownership interest in productive wells as of December 31~~risks, ~~2017~~including:

	December 31, 2017
	Gross	Net
Oil wells:
STACK	575	394.5
Other	62	22.4
All properties	637	416.9
Natural gas wells
STACK	33	16.7
Other	74	38.5
All properties	107	55.2


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

Of• ~~the~~facility ~~total~~or ~~well~~equipment ~~count as of December 31, 2017, 1 gross wells (0.6 net) are multiple completions.~~ malfunctions;

~~Productive~~• ~~wells are producing wells, shut-in wells we deem capable of production, wells awaiting completion, plus wells that are drilled/cased and completed, but awaiting~~ pipeline ~~hook-up. A~~or ~~gross~~tank ~~well~~ruptures isor ~~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.~~ spills;

~~Developed~~• ~~and~~surface ~~Undeveloped~~fluid ~~Acreage~~spills ~~Position~~and water contamination;

~~The~~• ~~following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31~~fires, ~~2017~~blowouts, ~~all~~well ofcollapses ~~which~~and isexplosions; ~~located in the United States:~~ and

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Property:
STACK	124,326	98,587	35,237	32,816	159,563	131,403
Other	69,431	36,747	343,254	291,916	412,685	328,663
All properties	193,757	135,334	378,491	324,732	572,248	460,066


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

AsIn isaddition, ~~customary~~a inportion ~~the~~of ~~oil~~our ~~and natural~~ gas ~~industry,~~production weis ~~can~~processed ~~generally~~to ~~retain~~separate anNGLs. If ~~interest~~the inprocessing ~~undeveloped~~plants ~~acreage through drilling activity~~ that ~~establishes~~service ~~commercial~~us ~~production~~were ~~sufficient~~ to ~~maintain~~cease ~~the leases~~operations, bywe ~~paying~~would ~~delay~~need ~~rentals~~to ~~during~~arrange ~~the~~for ~~remaining~~alternative ~~primary~~transportation ~~term~~and ofprocessing ~~leases~~facilities, ~~pooling~~which ~~process,~~may ~~automatic~~not ~~extensions~~be oravailable. If ~~negotiated extensions of the leases~~unavailable, ~~and~~we ~~other~~might ~~terms~~have ofto ~~the leases such as~~ shut- in ~~payments.~~our ~~The~~gas ~~oil~~ and, ~~natural~~therefore, ~~gas~~other ~~leases~~production, in which wecould ~~have~~reduce anour ~~interest~~operating ~~are~~cash ~~for varying primary terms and~~flow. Further, ifany ~~production~~alternative ~~under~~facilities acould ~~lease~~be ~~continues~~more ~~from~~expensive ~~developed~~than ~~lease acreage beyond~~ the ~~primary~~facilities ~~term,~~ we ~~are~~currently ~~entitled to hold the lease for as long as oil or natural gas is produced~~use. ~~The oil and natural gas properties consist primarily of oil and natural gas wells and interests in leasehold acreage, both developed and undeveloped.~~

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.

~~Table~~Our ofderivative ~~ContentsIndex~~program tocould ~~Financial~~result ~~Statements~~ in financial losses or could reduce our net income.

~~Undeveloped~~To ~~Acreage~~achieve ~~Expirations~~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.

~~The~~Our ~~following~~policy ~~table~~has ~~sets~~been ~~forth~~to ~~information~~meet ~~with~~the ~~respect~~minimum required hedging levels under the Alta Mesa RBL and to opportunistically hedge an additional portion of our ~~gross~~near-term estimated production. Other than the compliance with minimum and ~~net~~maximum ~~undeveloped~~hedging ~~oil~~levels, our price hedging strategy and ~~natural~~future ~~gas~~hedging ~~acreage~~transactions ~~under~~will ~~lease~~be asdetermined ofusing ~~December~~Board ~~31,~~and ~~2017~~management discretion, ~~all~~depending ofon the financial and future commodity expectations at the time. The prices at which iswe ~~located~~hedge our production in the ~~United~~future ~~States,~~will ~~that~~be ~~will~~dependent ~~expire~~upon ~~over~~commodities prices at the ~~following~~time ~~three~~we ~~years~~enter byinto ~~core~~these ~~area~~transactions, ~~unless~~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 ~~established~~also ~~within~~possible ~~the~~that ~~spacing~~a ~~units~~substantially ~~covering~~larger ~~the~~percentage ~~acreage~~of ~~prior~~our future production will not be hedged, as compared to ~~the~~current ~~expiration~~or ~~dates:~~historic levels, which would result in our oil and gas revenue becoming more sensitive to commodity price fluctuations.

	2018		2019		2020
	Gross	Net	Gross	Net	Gross	Net
Property:
STACK	10,181	9,707	12,875	12,355	3,638	3,187
Northwest	23,686	16,350	36,737	25,236	13,713	9,453
Other	18,945	10,999	3,273	2,826	11,131	10,454
All properties	52,812	37,056	52,885	40,417	28,482	23,094

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

WeEven ~~have~~when ~~lease~~properly ~~acreage~~used ~~that~~and ~~is generally subject to lease expirations if initial wells are not drilled within a specified period~~interpreted, ~~generally~~2-D aand ~~period~~3-D ofseismic ~~three~~data toand ~~five~~visualization ~~years. As~~techniques ishelp ~~customary~~geoscientists in ~~the~~identifying ~~oil~~subsurface structures and ~~gas~~hydrocarbon ~~industry~~indicators, webut ~~can~~do ~~retain~~not ~~our~~prove ~~interest in undeveloped acreage by maintaining~~ the ~~lease through: (i) commencing operations for drilling~~amount, ~~completion~~if ~~and production operations~~any, ~~(ii)~~of ~~pooling~~hydrocarbons ~~process,~~present ~~(iii)~~in ~~production,~~those ~~(iv)~~structures. ~~automatic~~The ~~extensions~~use ~~or negotiated extensions~~ of ~~the~~seismic ~~leases~~data and ~~(v)~~ other ~~terms~~advanced oftechnologies ~~the~~requires ~~leases~~greater ~~such as shut~~pre-indrilling ~~payments. As~~expenditures ofthan ~~December~~traditional ~~31,~~drilling ~~2017~~strategies, ~~the~~which ~~vast~~may ~~majority~~result ofin ~~our~~additional ~~acreage~~costs ~~does~~without ~~not~~an ~~have~~uplift ~~associated proved undeveloped reserves, and proved undeveloped reserves attributed~~ to ~~acreage~~a inwell’s ~~which~~economics. As ~~the~~a ~~lease~~result, ~~expiration~~even ~~date~~our ~~precedes~~successful ~~the scheduled initial~~ drilling ~~date~~activities ismay not ~~material.~~prove ~~Our leases are mainly fee leases with primary terms of three to five years~~economic. ~~We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests.~~

~~Marketing~~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 ~~Customers~~ analyze seismic data without the prospect of future benefit of production.

~~The~~Competition ~~market~~in ~~for~~ our ~~oil~~industry ~~and~~is ~~natural gas production depends on factors beyond our control~~intense, ~~including~~making ~~the~~it ~~extent~~more ofdifficult ~~domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand~~ for ~~oil~~us ~~and~~to ~~natural~~acquire ~~gas~~properties, ~~the~~market ~~marketing of competitive fuels and the effect of state and federal regulation. The~~ oil ~~and~~or ~~natural~~ gas ~~industry also competes with other industries in supplying the energy~~ and ~~fuel~~secure ~~requirements~~trained ~~of industrial, commercial and individual consumers~~personnel.

WeOur ~~sell~~ability ~~the~~to ~~oil~~acquire ~~and~~additional ~~natural gas from several~~ properties weand ~~operate~~pursue ~~primarily~~our ~~through~~operational aobjectives ~~marketing~~is ~~agreement~~dependent ~~with~~upon ~~ARM~~our ~~Energy~~ability ~~Management, LLC (“AEM”). Prior~~ to ~~the~~evaluate ~~Closing, we were a part owner of AEM at less than 10%. AEM markets our oil~~ and ~~natural~~select ~~gas~~suitable ~~and~~properties ~~subsequently sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location,~~ and ~~quality taken into account. AEM remits monthly collections of these sales~~ to ~~us,~~consummate ~~and~~transactions ~~receives~~in a 1%highly ~~marketing~~competitive ~~fee~~market. Our ~~marketing~~competitors ~~agreement~~may ~~with~~be ~~AEM~~able ~~commenced~~to inpay ~~June~~more ~~2013. The agreement will terminate in 2018, with additional provisions~~ for ~~extensions~~oil ~~beyond~~and ~~five~~gas ~~years,~~properties and ~~for~~pursue ~~early~~a ~~termination. During~~greater ~~the~~number ~~second half~~ of ~~2013~~properties ~~and~~than ~~throughout~~we ~~2014~~can. In ~~to 2016~~addition, ~~AEM marketed majority of~~ our ~~production~~industry ~~from~~has ~~operated~~periodically ~~fields. Production~~experienced ~~from~~shortages ~~non-operated fields, the most significant~~ of ~~which~~drilling ~~were~~rigs, ~~our Eagleville field in South Texas~~equipment, pipe and ~~our Hilltop natural gas field in East Texas prior to their sale~~personnel, ~~was~~which ~~marketed~~has onadversely ~~our~~affected ~~behalf~~the bytiming ~~the~~and ~~operators~~cost of ~~those properties~~operating. ~~Production~~ Competition ~~from~~has ~~our~~been ~~interests~~historically strong in ~~Eagleville~~hiring ~~was~~experienced ~~sold by the operator~~personnel, ~~Murphy~~particularly ~~Oil Corporation. We sold our remaining interests~~ in ~~Eagleville in~~ the ~~third~~engineering ~~quarter~~and oftechnical, ~~2015. See~~accounting, ~~“Note~~legal ~~4 — Significant Acquisitions~~ and ~~Divestitures”~~land indisciplines. ~~the~~An ~~accompanying~~inability ~~notes~~ to ~~the~~compete ~~consolidated~~effectively ~~financial~~with ~~statements~~our ~~included~~competitors ~~elsewhere~~could inhave ~~this~~a ~~report~~material ~~for~~adverse ~~additional~~impact ~~information~~on us.

~~Natural~~We ~~gas~~may ~~liquids~~not ~~are~~be ~~sold~~able ~~under~~to ~~various~~keep ~~contracts~~pace with ~~processors~~technological ~~typically~~developments in ~~the~~our ~~vicinity of the production at spot market rates, after processing costs~~industry.

~~For~~Our ~~the~~industry ~~year~~has ~~ended December~~been ~~31,~~characterized ~~2017~~by rapid and significant technological advancements and introductions of new products and services using new technologies, ~~revenues~~all ~~marketed~~of bywhich ~~AEM~~could ~~were~~either ~~$199~~generate better recoveries or reduce development costs.2 As ~~million~~others use or develop new technologies, we may be placed at a competitive disadvantage or ~~approximately~~competitive ~~70.9%~~pressures ofmay ~~total~~force ~~revenue~~us ~~excluding~~to ~~the~~implement ~~Weeks~~those ~~Island~~new ~~field~~technologies ~~sales~~at ~~marketed~~substantial bycosts. In ~~AEM~~addition, other oil and ~~hedging~~gas ~~activities.~~ companies may be better able to leverage

We believe that the loss of any of our significant customers, or of our marketing agent AEM, would not have a material adverse effect on us because alternative purchasers are readily available. Trade accounts receivable are not collateralized or otherwise secured.

Competition

We encounter intense competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and natural gas business for a much longer time than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory

~~Table~~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 ~~ContentsIndex~~the technologies we use now or in the future were to ~~Financial~~become ~~Statements~~ obsolete or if we are unable to use the most advanced commercially available technology, it may have a material adverse effect on us.

~~prospects~~Deficiencies ~~and~~in ~~mineral~~title ~~leases and~~ to ~~define, evaluate, bid for and purchase a greater number of properties and prospects than~~ our ~~financial~~leased orinterests human resources permit. Larger competitors may be able to absorb the decline in prices for oil and natural gas and the burden of any changes in federal, state and local laws and regulations more easily than we can, which could ~~adversely~~have ~~affect~~a ~~our~~material ~~competitive~~adverse ~~position.~~effect ~~Our~~on ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environmentus.

WeIf ~~are~~an ~~also~~examination ~~affected~~of bythe ~~competition~~title ~~for~~history ~~drilling~~of ~~rigs~~a ~~and~~property reveals that an oil or gas lease or other developed rights has been purchased in error from a person who is not the ~~availability~~owner of ~~related~~the ~~equipment.~~mineral interest desired, our interest would substantially decline in value. In ~~the~~such ~~past~~cases, the ~~oil~~amount ~~and~~paid ~~natural~~for such oil or gas ~~industry~~lease ~~has~~or ~~experienced~~leases ~~shortages~~or ofother ~~drilling~~developed ~~rigs,~~rights ~~equipment,~~would ~~pipe~~be ~~and~~lost. In ~~personnel~~acquiring mineral rights, ~~which~~we ~~have~~typically ~~delayed~~choose ~~development~~not to incur the expense of retaining title attorneys, ~~exploitation~~instead ~~and~~we ~~exploration~~rely ~~activities.~~upon Wethe ~~are~~judgment ~~unable~~of tooil ~~predict~~and ~~when,~~gas lease brokers or ~~if,~~landmen ~~such~~who ~~shortages~~perform ~~may~~the ~~occur~~fieldwork orin ~~how~~examining ~~they~~records ~~would~~before ~~affect~~we ~~our~~attempt ~~exploitation~~to ~~and~~acquire ~~development~~a ~~program.~~lease or other mineral interest.

WePrior ~~compete~~to ~~for~~drilling ~~capital~~a inwell ~~the~~that ~~domestic~~we ~~financial~~operate, ~~marketplace~~however, towe ~~fund~~do ~~our~~obtain ~~exploration~~a ~~and~~preliminary ~~development~~title ~~activities~~review toof the ~~extent~~spacing ~~our~~unit ~~operations~~to ~~cannot~~ensure ~~support~~there ~~them~~are atno ~~any~~obvious ~~given~~defects ~~time.~~in ~~See~~title ~~“Item~~to 1Athe well. If ~~Risk~~we ~~Factors—~~do ~~Our~~find ~~exploration~~defects, ~~exploitation~~we must perform or fund curative work to correct deficiencies in the marketability of the title, ~~development~~such ~~and~~as ~~acquisition~~obtaining ~~operations~~affidavits ~~will~~of ~~require~~heirship ~~substantial~~or ~~capital~~causing ~~expenditures.~~an estate to be administered. We may bealso ~~unable~~elect to ~~obtain~~proceed ~~needed~~with ~~capital~~a orwell ~~financing~~despite ondefects ~~satisfactory~~to ~~terms,~~the ~~which~~title ~~could~~identified ~~lead~~in the preliminary title opinion. If we fail to aobtain ~~decline~~defensible intitle to our ~~production~~leasehold, ~~and~~we may be unable to develop additional reserves or benefit from the expected ownership.”

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

~~Weather~~Water ~~conditions~~is ~~affect~~an ~~the~~essential ~~demand~~component ~~for,~~of unconventional oil and ~~prices~~gas ~~of,~~upstream ~~oil~~during both the drilling and ~~natural~~hydraulic ~~gas~~fracturing processes. Historically, ~~Demand~~we ~~for~~have ~~oil~~been ~~and~~able ~~natural~~to ~~gas~~purchase iswater ~~typically~~from ~~higher~~local inland ~~the~~owners ~~fourth~~ and ~~first~~other ~~quarters~~sources ~~resulting~~for use in ~~higher~~our ~~prices~~operations. However, ~~Due~~our access to ~~these~~such ~~seasonal~~water ~~fluctuations,~~supplies ~~results~~may ofbecome ~~operations~~limited by factors such as extended drought, competition for ~~individual~~water ~~quarterly~~or ~~periods~~governmental ~~may~~regulation. If ~~not~~we beare ~~indicative~~unable to obtain sufficient amounts of ~~the~~water, ~~results~~our ~~that~~ability ~~may~~to develop our reserves could be ~~realized~~restricted onor anmade ~~annual~~less ~~basis.~~economic, which could have a material adverse effect on us.

~~Oklahoma~~Litigation ~~Forced~~and ~~Pooling~~investigations ~~Process~~by private plaintiffs or government officials or entities could adversely affect our performance.

InOil ~~the past we have used,~~ and wegas ~~expect~~upstream toactivities ~~continue~~are tocomplex ~~use,~~and ~~the~~involve ~~Oklahoma~~risks ~~“forced~~that ~~pooling”~~could ~~process~~lead to ~~ensure~~legal ~~all~~proceedings. We ~~working~~currently ~~interest~~are ~~owners~~defending ~~participate~~litigation ~~in drilling~~ and ~~spacing~~anticipate ~~units~~that ~~for wells~~ we ~~propose~~will tobe ~~drill~~required ~~as operator on our STACK acreage. Where applicable, this process allows us~~ to ~~increase~~defend ~~our~~new ~~working~~litigation ~~interest~~ in ~~those~~the ~~units~~future. ~~Any~~ ~~such~~The ~~increase~~subject inmatter ~~working~~of ~~interest~~such ~~would~~litigation ~~lead~~may toinclude areleases ~~proportionate increase in our share~~ of ~~the~~hazardous ~~production~~substances ~~and~~from ~~reserves~~our ~~associated~~facilities, ~~with~~contract, ~~any~~title ~~such~~or ~~successfully~~royalty ~~drilled~~disputes, ~~well.~~regulatory ~~Under~~compliance ~~Oklahoma law~~matters, ifpersonal ainjury ~~party~~or ~~proposes~~property todamage ~~drill~~matters ~~the~~or ~~initial~~disputes ~~well~~related to aany ~~particular~~other ~~formation~~laws inor aregulations ~~specific~~that ~~drilling~~apply ~~and~~to ~~spacing~~our ~~unit~~operations. In ~~but~~some ~~cannot~~cases, ~~obtain~~ the ~~agreement~~plaintiff ofor ~~all~~plaintiffs ~~other~~seek ~~oil~~alleged ~~and~~damages ~~natural~~involving ~~gas~~large ~~interest~~classes ~~holders~~of ~~and~~potential ~~other~~litigants ~~leaseholders~~and ~~within~~may ~~the~~allege ~~unit~~damages asrelating to ~~how~~extended ~~the~~periods ~~unit~~of ~~should~~time beor ~~developed,~~other ~~the~~alleged ~~party~~facts ~~may~~and ~~commence a “forced pooling” process~~circumstances. For ~~Under current regulations~~instance, ~~drilling and spacing units for~~ our ~~targeted~~parent ~~horizons~~company inand ~~our~~certain ~~STACK acreage are based on drilling a maximum~~ of ~~four~~its toformer ~~eight~~and ~~horizontal~~current ~~wells,~~directors ~~depending~~and onofficers ~~the~~were ~~formation,~~named onas adefendants ~~land~~in ~~section~~three ~~consisting~~putative ofsecurities ~~640~~class ~~acres. In a forced pooling~~ action, ~~which~~claims isalleging ~~common~~that ~~in Oklahoma,~~ the ~~proposed~~defendants ~~operator~~disseminated ~~files~~a anfalse ~~application~~and ~~for~~misleading aproxy ~~pooling~~statement ~~order~~in connection with the ~~Oklahoma~~Business ~~Corporation~~Combination ~~Commission~~as ~~(“OCC”)~~well ~~and~~as ~~names~~alleged ~~all~~misstatements ~~other~~after ~~persons with~~ the ~~right~~Business toCombination. In ~~drill~~addition, the ~~unit~~SEC ~~as respondents. The proposed operator~~ is ~~required~~conducting ~~to demonstrate in an administrative proceeding that it has made~~ a ~~good~~formal ~~faith~~investigation ~~effort~~into ~~to bargain with all of~~ the ~~respondents~~facts ~~prior~~involved ~~to filing its application. The fair market value of the mineral interests~~ in the ~~unit~~material isweakness ~~determined~~ in ~~the~~our ~~administrative~~internal ~~proceeding~~controls byover ~~reference~~financial toreporting ~~market transactions involving nearby oil~~ and ~~natural gas rights, especially what has been paid for mineral leases in~~ the ~~particular~~impairment ~~drilling~~disclosed ~~and~~previously ~~spacing unit~~ and ~~the~~in ~~immediately~~this ~~surrounding~~annual ~~drilling and spacing units~~report.

~~Assuming~~These ~~the~~and ~~application~~other islegal ~~granted~~proceedings are inherently uncertain and atheir ~~forced~~results ~~pooling~~cannot ~~order~~be ispredicted. ~~granted,~~Regardless of the ~~respondents~~outcome, ~~then~~such proceedings could have 20an ~~days~~adverse toimpact ~~elect~~on ~~either~~us tobecause ~~participate~~of inlegal ~~the~~costs, ~~proposed~~diversion ~~well~~of ormanagement ~~accept~~and ~~fair~~other ~~market~~personnel ~~value~~and ~~for~~other ~~their~~factors. ~~interest~~In addition, ~~usually~~it inis ~~the~~possible ~~form~~that ofsuch aproceedings ~~cash~~could ~~payment,~~result anin ~~overriding royalty~~liability, penalties or ~~some~~sanctions, ~~combination~~judgments, ~~based~~consent ondecrees, ~~the~~injunctive ~~fair~~relief ~~market~~or ~~value~~orders ~~established~~requiring ~~and~~a ~~approved~~change ~~through~~in ~~the~~our ~~administrative~~business ~~hearing.~~practices, ~~The~~which ~~pooling~~could ~~order~~have ~~usually~~a ~~also~~material ~~addresses~~adverse ~~the~~effect ~~time~~on ~~frame~~us. Accruals for ~~drilling~~such ~~the~~liabilities, ~~well~~penalties ~~and~~or ~~provides~~sanctions ~~for~~may ~~the~~be ~~manner~~insufficient, inand ~~which~~judgments ~~future~~and ~~wells~~estimates ~~within~~to ~~the~~determine ~~unit~~accruals ~~may~~or berange ~~drilled.~~of ~~The~~losses ~~applicant~~related ~~for~~to ~~the~~legal ~~pooling~~and ~~order~~other isproceedings ~~ordinarily~~could ~~designated~~change asfrom ~~the~~one ~~operator~~period ofto the ~~wells~~next, ~~subject~~and tosuch ~~the~~changes ~~pooling~~could ~~order.~~be material.

~~The~~Our ~~availability~~operations ofare ~~forced~~regulated ~~pooling~~and ~~means~~the ~~that~~costs ~~it normally is difficult for a small number of owners~~ to ~~block~~comply or ~~delay the drilling of~~ a ~~particular~~failure ~~well proposed by another interest holder. Exploration and production companies in Oklahoma often negotiate~~ to ~~lease~~comply ascould ~~much~~be ofcostly ~~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~~a ~~ability~~material toadverse ~~expand~~effect ~~into~~on ~~and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas~~us.

AsWe amay ~~result~~incur ofsignificant ~~forced~~costs pooling processes, we have increased our working interest in approximately 95% of the 269 total operated horizontal wells we have drilled on our STACK acreage since January 1, 2014. In those wells in which forced pooling proceedings were initiated, we increased our working interest by an average of approximately 15% of our initial working interest in the drilling unit. In one instance in 2016, we proposed and ~~drilled~~liabilities ~~a well~~ as ~~operator in~~ a ~~section~~result ~~where our working interest ownership was initially approximately 10%, which through the implementation~~ of ~~the~~wide-ranging ~~forced~~environmental ~~pooling~~requirements ~~process~~applicable ~~increased~~to our ~~working interest to approximately 95%~~operations. InSuch ~~recent~~environmental ~~years,~~laws ~~the~~and ~~collective~~regulations ~~working~~include ~~interest of third party owners of mineral rights in these drilling units who have elected to participate in these wells has been low, which we believe could largely be attributed to~~ the ~~absence of available capital~~ following ~~the~~federal ~~substantial~~laws ~~oil~~(along ~~and~~with ~~gas~~their ~~price~~state ~~downturns~~counterparts): that commenced in late 2014. Due to the increased interest in the STACK as an economic play in the current price and cost environment, we believe that third party interest holders may be more likely to bear their

~~Table~~• the Clean Air Act (“CAA”), which restricts the emission of ~~ContentsIndex~~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 ~~Financial~~GHG ~~Statements~~ emissions;

~~share~~• of the ~~costs~~Federal ofWater ~~the~~Pollution ~~proposed~~Control ~~future wells on our acreage. Nevertheless~~Act, wealso ~~expect~~known ~~that~~as ~~forced~~the ~~pooling~~Clean ~~will~~Water ~~continue~~Act to(“CWA”), ~~increase~~which ~~our~~regulates ~~leasehold~~discharges ~~interests~~of ~~within~~pollutants ~~our~~from ~~STACK~~facilities ~~acreage.~~to ~~The~~state ~~future~~and ~~successful~~federal ~~use~~waters ofand ~~forced~~establishes ~~pooling~~the extent to ~~increase~~which ~~our~~waterways ~~working interest in proposed wells that~~ are ~~attributed~~subject to ~~undeveloped~~federal ~~reserves~~jurisdiction isand ~~not~~rulemaking ~~reflected~~as inprotected ~~our~~waters ~~reserve~~of ~~reports.~~the United States;

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

As• isthe ~~customary~~Safe inDrinking ~~our~~Water ~~industry,~~Act ~~a preliminary review of title records~~(“SDWA”), which ~~may~~ensures ~~include~~the ~~opinions~~quality ~~or reports~~ of ~~appropriate professionals or counsel, is made at~~ the ~~time~~nations’ wepublic ~~acquire~~drinking ~~properties.~~water Wethrough ~~believe~~adoption ~~that our title to all~~ of ~~the~~drinking ~~various~~water ~~interests set forth above is satisfactory and consistent with the~~ standards ~~generally accepted in the oil~~ and ~~gas~~control ~~industry,~~over ~~subject only to immaterial exceptions that do not detract substantially from~~ the ~~value~~subsurface ofinjection the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations and orders of ~~arbitral~~fluids orinto ~~governmental~~belowground authorities. In addition, the interests may be subject to burdens such as net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations. formations;

~~Employees~~• 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;

As• ofthe ~~December~~Comprehensive 31Environmental Response, ~~2017~~Compensation, weand ~~had~~Liability ~~266~~Act ~~full-time~~(“CERCLA”), ~~employees.~~which Weimposes ~~are~~liability ~~not~~on agenerators, ~~party~~transporters ~~to any collective bargaining agreements~~ and ~~have~~arrangers ~~not~~of ~~experienced~~hazardous ~~any~~substances ~~strikes~~sent orfor ~~work~~disposal ~~stoppages.~~to Wesites ~~believe~~where ~~our~~hazardous ~~relationships~~substance ~~with~~releases ~~our~~have ~~employees~~occurred or are ~~good.~~threatening ~~From time~~ to ~~time~~occur, weas ~~utilize~~well ~~the~~as ~~services~~imposes ofliability ~~independent~~on ~~contractors~~present toand ~~perform~~certain ~~various~~past ~~field~~owners and ~~other~~operators ~~services.~~of ~~See~~sites ~~“Item~~were ~~13.~~hazardous ~~Certain~~substance ~~Relationships~~releases ~~and~~have ~~Related~~occurred ~~Transactions,~~or ~~and~~are ~~Director~~threatening ~~Independence.”~~to occur;

~~Insurance~~• 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;

In• ~~accordance~~the ~~with~~Endangered ~~industry~~Species ~~practice,~~Act ~~we maintain insurance against some~~(“ESA”), ~~but not all, of the operating risks to~~ which ~~our~~restricts ~~business~~activities ~~is exposed. We currently have insurance policies~~ that ~~include~~may ~~coverage~~affect ~~for~~federally ~~general~~identified ~~liability~~endangered ~~(includes sudden~~ and ~~accidental~~threatened ~~pollution),~~species ~~physical~~or ~~damage~~their tohabitats ~~our~~through ~~oil~~the ~~and~~implementation ~~gas~~of ~~properties,~~operating ~~control~~limitations ofor ~~well,~~restrictions ~~auto~~or ~~liability,~~a ~~marine liability~~temporary, ~~worker’s~~seasonal ~~compensation~~or ~~and~~permanent ~~employer’s~~ban ~~liability,~~on ~~among~~operations ~~other~~in ~~things.~~affected areas; and

~~Currently,~~• ~~we have general liability insurance coverage up to $1 million per occurrence, which includes sudden and accidental environmental liability coverage for~~ the ~~effects~~National ofEnvironmental ~~pollution~~Policy onAct ~~third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles~~ (~~generally ranging from $25~~“NEPA”),~~000~~ towhich ~~$1.8 million)~~requires ~~that~~federal ~~must~~agencies ~~be met prior~~ to ~~recovery.~~evaluate ~~These~~major ~~insurance~~agency ~~policies~~actions ~~are~~having ~~subject~~the potential to ~~certain~~impact ~~customary~~the ~~exclusions~~environment and ~~limitations.~~that Inmay ~~addition,~~require ~~we maintain excess liability coverage, which is in addition to and triggered if~~ the ~~general~~preparation ~~liability~~of ~~per~~environmental ~~occurrence~~assessments ~~limit~~or isenvironmental ~~reached.~~impact statements.

~~Our~~These ~~offshore~~U.S. ~~reserves~~laws ~~are~~and ~~not~~their aimplementing ~~significant~~regulations, ~~portion~~as ofwell ~~our~~as ~~total~~state ~~reserves;~~counterparts, generally restrict the ~~fields~~level ~~are~~of inpollutants ~~declining~~emitted ~~production~~to ~~with~~ambient noair, ~~drilling~~discharges ~~activity.~~to ~~Our~~surface ~~consolidated~~water, ~~balance~~and ~~sheets~~disposals ~~include~~or ~~asset~~other ~~retirement~~releases ~~liabilities~~to ~~which~~surface weand ~~believe~~below-ground ~~are~~soils ~~sufficient~~and ground water. Failure to ~~cover~~comply ~~the~~with ~~eventual~~these ~~costs~~laws and regulations may result in the assessment of ~~dismantlement~~sanctions, including administrative, civil and ~~abandonment.~~criminal Wepenalties, ~~believe~~the ~~that~~imposition ~~due~~of toinvestigatory, remedial and corrective actions obligations, the ~~nature~~incurrence of ~~the~~capital ~~operations~~expenditures, delays in ~~these~~the ~~fields~~permitting, ~~and~~development ~~the~~or ~~limited~~expansion ~~activity~~of projects, and the ~~risk~~issuance of ~~environmental~~orders ~~damage~~enjoining issome ~~not~~or asall ~~high~~of asour itfuture ~~would~~operations be in ana ~~actively~~particular ~~drilling~~area. Certain ~~offshore~~environmental ~~field.~~laws ~~Our~~and ~~insurance~~regulations ~~program~~impose ~~includes~~strict ~~property~~joint ~~damage,~~and ~~pollution~~several liability, without regard to fault or legality of conduct, for costs required to clean up and ~~control~~restore sites where hazardous substances or other wastes have been disposed of ~~well~~or otherwise released. Moreover, ~~The~~it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage ~~coverage~~allegedly ~~extends~~caused toby ~~total~~the ~~loss~~release of ~~the~~hazardous ~~equipment~~substances, ~~(not~~wastes or other materials into the ~~reserves)~~environment. The ~~with~~trend ~~replacement~~in ~~cost~~environmental ~~coverage~~regulation ~~retained~~is to place more restrictions and limitations on ~~one~~activities ofthat may affect the ~~five~~environment ~~fields.~~and ~~The~~more ~~pollution~~stringent ~~coverage~~laws and regulations may be adopted in the future. Historically, ~~which~~our isenvironmental ~~applicable~~compliance tocosts ~~both~~have ~~offshore~~not ~~and~~had ~~onshore~~a ~~events~~material adverse effect on our results of operations; however, isthere ~~$10~~can ~~million~~be ~~per~~no ~~incident~~assurance ~~with~~that such costs will not be material in the future or that such future compliance will not have a ~~$100,000~~material ~~deductible.~~adverse effect on our business and operating results

WeChanges ~~require all of our third-party contractors, including those that perform hydraulic fracturing operations, to sign master service agreements~~ in ~~which they agree to indemnify us for injuries and deaths of~~ the ~~service~~legal ~~provider’s employees as well as contractors~~ and ~~subcontractors~~regulatory ~~hired~~environment bygoverning ~~the~~our ~~service provider. Similarly~~industry, weparticularly ~~generally~~changes ~~agree~~in tothe ~~indemnify~~Oklahoma ~~each~~forced ~~third-party~~pooling ~~contractor against claims made by our employees and other contractors. Additionally~~system, ~~each~~could ~~party generally is responsible for damage to its own property. We do not currently~~ have ~~any~~a ~~insurance~~material ~~policies~~adverse in effect ~~that~~on ~~are intended to provide coverage for losses solely related to hydraulic fracturing operations~~us.

WeOur ~~re-evaluate~~business ~~the~~is ~~purchase~~subject ofto ~~insurance,~~various ~~coverage~~forms ~~limits~~of ~~and~~extensive ~~deductibles~~government ~~annually.~~regulation, ~~Future~~including ~~insurance~~laws ~~coverage for the oil~~ and ~~gas~~regulations ~~industry~~concerning ~~could~~the ~~increase~~location, inspacing ~~cost~~ and ~~may~~permitting ~~include~~of ~~higher~~the ~~deductibles~~wells orwe ~~retentions.~~drill Inand ~~addition,~~the ~~some~~disposal ~~forms~~ of ~~insurance~~produced ~~may~~water. Changes ~~become unavailable~~ in the ~~future~~legal orand ~~unavailable~~regulatory onenvironment, ~~terms~~particularly ~~that~~any ~~are~~changes ~~economically~~to ~~acceptable.~~Oklahoma’s Noforced ~~assurance~~pooling ~~can~~procedures becould ~~given~~result ~~that we will be able to maintain insurance~~ in ~~the~~increased ~~future~~compliance atcosts ~~rates that we consider reasonable~~ and weadversely ~~may~~affect ~~elect to self-insure or maintain only catastrophic coverage for certain risks in the future~~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.

~~Table~~Title VII of ~~ContentsIndex~~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 ~~Financial~~enact ~~Statements~~ 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.

~~Environmental~~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 ~~Occupational~~option ~~Safety~~contracts in various commodities (including gas) and ~~Health~~for ~~Matters~~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.

~~Our~~The ~~oil~~CFTC ~~and~~issued ~~natural~~a ~~gas~~final ~~exploration~~rule on ~~and~~margin ~~production~~requirements ~~operations~~for ~~are~~uncleared ~~subject~~swap totransactions ~~stringent~~on ~~federal~~January 6, ~~state~~2016, ~~and~~which ~~local~~includes ~~laws~~an ~~and~~exemption ~~regulations~~from ~~governing~~any ~~occupational~~requirement ~~safety~~to ~~and~~post ~~health,~~margin ~~the~~to ~~discharge~~secure ofuncleared ~~materials~~swap transactions entered into ~~the~~by ~~environment~~commercial ~~and~~end-users ~~environmental~~in ~~protection.~~order ~~Numerous~~to ~~governmental~~hedge ~~agencies,~~commercial ~~including~~risks ~~the~~affecting Utheir business.S. In ~~Environmental~~addition, ~~Protection~~the ~~Agency~~CFTC ~~(“EPA”)~~has ~~and~~issued ~~analogous~~a ~~state~~final ~~agencies~~rule authorizing ~~have~~an exemption from the ~~power~~otherwise applicable mandatory obligation to ~~enforce~~clear ~~compliance~~certain ~~with~~types ~~these~~of ~~laws~~swap ~~and~~transactions ~~regulations~~through a derivatives clearing organization and ~~the~~to ~~permits~~trade ~~issued~~such ~~under~~swaps ~~them~~on a regulated exchange, ~~often~~which ~~requiring~~exemption ~~difficult~~applies ~~and~~to ~~costly~~swap ~~actions~~transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The ~~These~~mandatory ~~laws~~clearing requirement currently applies only to certain interest rate swaps and ~~regulations~~credit ~~may~~default swaps, ~~among~~but the CFTC could act to impose mandatory clearing requirements for other ~~things:~~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 ~~require~~of the ~~acquisition~~above regulations could increase the costs to us of ~~various~~entering ~~permits~~into ~~before~~derivatives ~~drilling~~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 ~~regulated~~provisions of the Dodd-Frank Act could cause current counterparties to restructure their derivative activities, ~~commence;~~including the potential that they might cease engaging in the business of commodity derivatives.

·If ~~require~~we ~~the~~voluntarily ~~installation~~or involuntarily reduce our use of ~~pollution~~derivative ~~control~~contracts ~~equipment~~as ina ~~connection~~result ~~with~~of ~~operations~~the ~~and~~new ~~place~~requirements, ~~other~~we ~~conditions~~become onmore exposed to commodity price fluctuations, which could adversely affect our ability to conduct our operations;.

·We ~~place~~are ~~restrictions~~subject onto ~~the~~complex ~~use~~federal, ofstate, ~~the~~local ~~material~~and ~~based~~other onlaws ~~our~~and ~~operations~~regulations ~~and~~that ~~upon~~could adversely affect the ~~disposal~~cost, ofmanner ~~waste~~or ~~from~~feasibility of conducting our operations;.

·Our ~~restrict~~upstream ~~the~~operations ~~types~~are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, ~~quantities~~we must obtain and ~~concentrations~~maintain ofnumerous ~~various~~permits, ~~substances~~approvals ~~that~~and ~~can~~certificates befrom ~~released~~various ~~into~~federal, ~~the~~state ~~environment~~and local governmental authorities. Failure or ~~used~~delay in ~~connection~~obtaining ~~with~~regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, ~~production~~and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and ~~transportation~~the ~~activities;~~protection of correlative rights affect our operations by limiting the quantity of oil and gas we may produce and sell.

·We ~~limit~~are orsubject ~~prohibit~~to ~~drilling~~federal, ~~activities~~state onand ~~lands~~local ~~lying~~laws ~~within~~and ~~wilderness~~regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, ~~wetlands~~production and ~~other~~transportation ~~protected~~of ~~areas;~~oil and gas, and incur costs to comply with such federal, state and local laws and regulations.

·Under ~~require~~the ~~remedial~~Natural ~~measures~~Gas toAct ~~mitigate~~(“NGA”), ~~pollution~~the ~~from~~Federal ~~former~~Energy Regulatory Commission (“FERC”) regulates the interstate transportation and ~~ongoing~~sale ~~operations~~for resale of gas, ~~including~~as ~~site~~well ~~restoration~~as the construction and operation of interstate gas pipelines. As a general matter, ~~pit~~states ~~closure~~regulate the intrastate transportation, local distribution and ~~plugging~~retail sale of ~~abandoned~~gas ~~wells;~~under state laws and regulations.

·Under ~~impose~~the ~~specific~~Interstate ~~safety~~Commerce Act (“ICA”), FERC also regulates the rates and ~~health~~practices ~~criteria~~of ~~addressing~~oil ~~worker~~pipeline ~~protection~~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.

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, occurrence of delays or cancellations in the permitting, performance or expansion of projects and in issuance of orders enjoining performance in particular areas for non-compliance.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, for example, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017 to 2019, although the outlook for this initiative remains unclear with the change in the presidential administration. Consequently, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. 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.

The following is a summary of some of the more significant existing environmental and occupational safety and health laws, and regulations, as amended from time to time, to which our business operations are subject.

Non-hazardous and Hazardous Wastes and Hazardous Substances Handling

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. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of oil or natural gas, 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 certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A

~~Table~~The ofU.S. ~~ContentsIndex~~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 ~~Financial~~recover ~~Statements~~ the resulting costs through insurance or increased revenue, our financial condition would be adversely affected.

~~loss~~Fuel ofconservation ~~the~~measures, ~~RCRA~~alternative ~~exclusion~~fuel requirements, increasing consumer demand for ~~drilling~~alternatives ~~fluids~~to oil and gas, ~~produced~~technological ~~waters~~advances in fuel economy and ~~related~~energy ~~wastes~~generation devices could ~~result~~reduce indemand anfor ~~increase~~oil inand ~~our~~gas. ~~costs~~The toimpact ~~manage~~of ~~and~~the ~~dispose~~changing ofdemand ~~waste,~~for ~~which~~oil ~~could~~and gas may have a material adverse effect on our business, financial condition, ~~and~~ results of operations and cash flows.

~~The~~Should ~~federal~~we ~~Comprehensive~~fail ~~Environmental~~to ~~Response,~~comply ~~Compensation,~~with ~~and~~all ~~Liability~~applicable ~~Act (“CERCLA”)~~statutes, ~~also known as the Superfund law~~rules, regulations and ~~comparable~~orders ~~state~~administered ~~laws~~by ~~impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for~~ the ~~release~~CFTC ~~of a “hazardous substance” (~~or ~~in the case of state laws~~FERC, ~~other~~we ~~classes~~could ~~of materials) into the environment. Under CERCLA, such persons may~~ be subject to ~~joint~~substantial ~~and~~penalties ~~several, strict liability for costs of investigation~~ and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of hazardous substancesfines. These classes of persons, or so-called 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 or more stringent state statutes. We generate materials in the course of our operations that may be regulated as hazardous substances.

WeUnder ~~currently~~the ~~own,~~Energy ~~lease~~Policy orAct ~~operate~~of ~~and~~2005 in(“EPAct”), ~~the~~FERC ~~past~~has ~~have~~civil ~~owned,~~penalty ~~leased~~authority orunder ~~operated~~the ~~numerous~~NGA, ~~properties~~including ~~that~~the ~~have~~ability ~~been~~to ~~used~~impose ~~for~~penalties ~~oil~~of ~~and~~up ~~natural~~to ~~gas~~$1 million ~~exploration~~per ~~and~~day ~~production~~ for ~~many~~each ~~years.~~violation ~~Although~~and wedisgorgement ~~believe~~of weprofits ~~have~~associated ~~utilized~~with ~~operating~~any ~~and~~violation ~~waste~~of ~~disposal~~the ~~practices~~NGA ~~that~~or ~~were~~FERC’s ~~standard~~regulations inunder the ~~industry~~NGA. atWhile ~~the~~neither ~~time,~~we ~~hazardous~~nor ~~substances,~~our ~~wastes~~subsidiaries ~~or hydrocarbons may~~ have been ~~released~~regulated onby orFERC ~~under~~as ~~the~~“natural ~~properties~~gas ~~owned~~companies” orunder ~~leased~~the ~~by us~~NGA, oras ona orcustomer ~~under~~of ~~other~~gas ~~locations,~~transportation ~~including offsite locations~~service, ~~where~~we ~~such~~also ~~materials~~must ~~have~~comply ~~been~~with ~~taken~~the ~~for~~terms ~~treatment~~and orconditions ~~disposal. In addition, some~~ of ~~these~~FERC-jurisdictional ~~properties~~tariffs ~~have~~pursuant ~~been~~to ~~operated~~which bytransportation ~~third~~service ~~parties~~is orprovided ~~by previous owners or operators whose treatment~~ and ~~disposal~~the ofanti-market ~~hazardous~~manipulation ~~substances,~~rules enforced ~~wastes,~~by orFERC ~~hydrocarbons were not~~ under ~~our~~the ~~control~~NGA. ~~These~~If ~~properties~~we ~~and~~fail ~~the~~to ~~materials~~comply ~~disposed~~with orall ~~released~~the onapplicable ~~them~~FERC-administered ~~may~~statues, ~~be subject to CERCLA~~rules, ~~RCRA~~regulations and ~~analogous state laws. In the future~~orders, we could be ~~required~~subject to ~~remediate~~substantial ~~property,~~penalties. ~~including~~FERC ~~groundwater,~~also ~~containing~~has orthe ~~impacted~~power ~~by previously disposed materials (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or~~ to ~~perform~~order ~~remedial~~disgorgement ~~plugging~~of orprofits ~~pit~~from ~~closure~~transactions ~~operations~~deemed to ~~prevent~~violate ~~future contamination,~~ the ~~costs of which could be material~~NGA.

~~Water~~Under ~~Discharges~~the Commodity Exchange Act (as amended by the Dodd-Frank Act) and ~~Subsurface~~regulations ~~Injections~~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.

~~The~~Climate ~~Federal~~change ~~Water~~legislation ~~Pollution~~or ~~Control~~other ~~Act,~~regulatory ~~also~~initiatives ~~known~~restricting asemissions ~~the Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge~~ of ~~pollutants,~~GHGs ~~including~~could ~~discharges,~~result ~~spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except~~ in ~~accordance~~increased ~~with~~operating ~~the~~costs ~~terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control~~ and ~~countermeasure~~reduced ~~plan~~demand ~~requirements~~for ~~imposed under~~ the ~~CWA~~oil ~~require appropriate containment berms~~ and ~~similar~~gas ~~structures~~we ~~to help prevent the contamination of regulated waters in the event of a spill, rupture or leak~~produce. ~~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.~~

~~The~~Climate ~~CWA~~change ~~also~~continues ~~prohibits~~to ~~the~~attract ~~discharge~~considerable ofpublic ~~dredge~~ and ~~fill~~scientific ~~material~~attention. inAs ~~regulated~~a ~~waters~~result, ~~including~~numerous ~~wetlands,~~proposals ~~unless~~have ~~authorized~~been bymade aand ~~permit~~may ~~issued~~continue byto ~~the~~be ~~U.S.~~made ~~Army~~at ~~Corps of Engineers (“Army Corps”). The EPA has issued final rules outlining its position on~~ the ~~federal~~international, ~~jurisdictional~~national, ~~reach~~regional ~~over~~and ~~waters~~state levels of ~~the~~government ~~United~~to ~~States.~~monitor ~~This~~and ~~interpretation~~limit byemissions ~~the EPA may constitute an expansion~~ of ~~federal jurisdiction over waters of the United States~~GHGs. ~~The~~These ~~rule~~efforts ~~was~~have ~~stayed~~included ~~nationwide~~consideration ~~by the U.S. Sixth Circuit Court~~ of ~~Appeals in October 2015 as that appellate court~~ cap-and-trade ~~several~~programs, ~~other~~carbon ~~courts hear lawsuits opposing implementation of the rule. In January 2017~~taxes, ~~the~~GHG ~~United~~reporting ~~States~~and ~~Supreme~~tracking ~~Court~~programs ~~accepted~~and ~~review~~regulations ofthat ~~the~~directly ~~rule~~limit toGHG ~~determine~~emissions ~~whether~~from ~~jurisdiction~~certain ~~rests~~sources. ~~with~~At the federal ~~district or appellate courts. Litigation surrounding this rule is ongoing. In February 2017~~level, ~~President~~no ~~Trump~~comprehensive ~~signed~~climate anchange ~~executive~~legislation ~~order~~has ~~directing~~been ~~the~~implemented ~~EPA and the Army Corps~~ to ~~begin~~date. aThe ~~process~~EPA tohas, ~~revise~~however, oradopted ~~rescind~~regulations ~~these~~under ~~rules;~~ the ~~agencies~~CAA ~~published~~that, aamong ~~notice~~other ~~of intent on March 6~~things, ~~2017~~establish toPSD ~~review~~construction and ~~rescind~~Title orV ~~revise~~operating ~~the~~permit ~~rules~~reviews ~~and~~for ~~the~~GHG ~~U.S.~~emissions ~~Department~~from ofcertain ~~Justice~~large ~~filed~~stationary asources ~~motion~~that ~~with~~are ~~the~~already ~~U.S.~~potential ~~Supreme~~sources ~~Court on March 6, 2017 requesting a court stay~~ of ~~its~~significant ~~review~~pollutant ~~of the rules~~emissions. ~~The~~Sources ~~outlook~~subject ~~for~~to these ~~rules~~permitting isrequirements ~~unclear. Federal~~must ~~and~~meet ~~state~~“best ~~regulatory~~available ~~agencies~~control ~~can~~technology” ~~impose~~standards ~~administrative, civil and criminal penalties, as well as require remedial or mitigation measures,~~ for ~~non-compliance~~those ~~with~~GHG ~~discharge permits or other requirements of the CWA and analogous state laws and regulations~~emissions. ~~The~~Additionally, ~~primary federal law related to oil spill liability is~~ the ~~Oil~~EPA ~~Pollution~~has ~~Act~~adopted ~~(“OPA”),~~rules requiring ~~which amends and augments oil spill provisions of~~ the ~~CWA~~monitoring and ~~imposes~~annual ~~certain~~reporting ~~duties and liabilities on certain “responsible parties” related to the prevention~~ of ~~oil~~GHG ~~spills~~emissions ~~and~~from ~~damages~~specified ~~resulting~~GHG ~~from~~emission ~~such~~sources ~~spills~~ in orthe ~~threatening~~ United States, ~~waters~~including, oramong ~~adjoining~~others, ~~shorelines. A liable “responsible party” includes the owner or operator of an~~ onshore ~~facility,~~and ~~vessel~~offshore ~~or pipeline that is a source of an~~ oil ~~discharge~~and orgas ~~that~~production, ~~poses~~processing, ~~the substantial threat of discharge~~transmission, orstorage inand ~~the~~distribution ~~case of offshore~~ facilities, ~~the lessee or permittee of the area in~~ which ainclude ~~discharging~~certain ~~facility is located. The OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety~~ of ~~public~~our ~~and private damages~~operations. ~~Although defenses exist to the liability imposed by the OPA, they are limited.~~

~~Our~~Federal ~~underground~~agencies ~~injection~~also ~~operations~~directly ~~are~~regulate ~~regulated~~emissions ~~pursuant~~of tomethane, ~~the~~a ~~Underground~~GHG, ~~Injection~~from ~~Control~~oil ~~(“UIC”)~~and ~~program~~gas ~~established~~operations. ~~under~~In August 2016, the ~~federal~~EPA ~~Safe~~issued ~~Drinking~~a ~~Water~~final ~~Act~~NSPS ~~(“SDWA”)~~rule, known as Subpart OOOOa, that requires certain new, modified or reconstructed facilities in the oil and ~~analogous~~gas ~~state~~sector to reduce these methane gas and ~~local~~volatile ~~laws~~organic compound emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and ~~regulations~~known as Subpart OOOO, by using certain equipment-specific emissions control practices. ~~The~~On ~~UIC~~September ~~program~~11, ~~includes~~2018, ~~requirements~~however, ~~for~~the ~~permitting~~EPA proposed changes to the August 2016 final NSPS rule applicable to oil and gas well vapor leaks. These changes, ~~testing~~if implemented, would ease compliance obligations by decreasing fugitive emission monitoring frequency requirements, ~~record~~allowing ~~keeping~~more time for repairs, and ~~reporting~~allowing compliance with certain state regulations in lieu of ~~injection~~complying ~~well~~with ~~activities~~federal regulations. Moreover, ason ~~well~~March as2, 2017 the EPA withdrew a ~~prohibition~~previously ~~against~~issued ~~the~~Information ~~migration~~Collection ofRequest ~~fluid~~that ~~containing~~sought ~~any~~information ~~contaminant~~about ~~into~~methane ~~underground~~emissions ~~sources~~from offacilities ~~drinking~~and ~~water.~~operations ~~State~~in ~~regulations~~the ~~require~~oil aand gas industry.

~~Table~~In December 2015, the United States attended the 21st Conference of ~~ContentsIndex~~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 ~~Financial~~determine, ~~Statements~~ 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.

~~permit~~The ~~from~~adoption ~~the~~and ~~applicable~~implementation ~~regulatory~~of ~~agencies~~any tointernational ~~operate~~treaty, ~~underground~~or ~~injection~~federal ~~wells.~~or ~~Although~~state welegislation, ~~monitor~~regulations ~~the~~or ~~injection~~other ~~process~~regulatory ofinitiative ~~our~~that ~~wells,~~imposes ~~any~~a ~~leakage~~carbon ~~from~~tax, ~~the~~requires ~~subsurface~~reporting ~~portions~~ of ~~the~~GHGs ~~injection~~or ~~wells~~otherwise ~~could~~restricts ~~cause~~emissions ~~degradation~~ of ~~fresh~~GHGs ~~groundwater~~from ~~resources,~~our ~~potentially~~equipment ~~resulting~~and inoperations ~~suspension~~could ofrequire ~~our~~us ~~UIC~~to ~~permit~~incur increased operating costs, ~~issuance~~such ofas ~~fines~~costs to purchase and ~~penalties~~operate ~~from~~emissions ~~governmental~~control ~~agencies~~systems, ~~incurrence~~acquire ofemissions ~~expenditures~~allowances ~~for~~or ~~remediation~~comply ofwith ~~the~~new ~~affected~~regulatory ~~resource~~or ~~and~~reporting ~~imposition~~requirements, ofthat ~~liability~~could byhave ~~third-parties~~an ~~claiming~~adverse ~~damages~~effect ~~for~~on ~~alternative~~our ~~water supplies~~business, ~~property~~financial condition and ~~personal~~results ~~injuries~~of operations. AMoreover, ~~change~~any insuch ~~UIC~~new ~~disposal~~treaty, ~~well~~legislation, ~~regulations~~regulation or initiative could increase the ~~inability~~cost to ~~obtain~~the ~~permits~~consumer, ~~for~~and ~~new~~thereby ~~disposal~~reduce ~~wells~~demand infor ~~the~~oil ~~future~~and ~~may~~gas, ~~affect~~which ~~our~~could ~~ability~~reduce tothe ~~dispose~~demand offor ~~produced~~the ~~waters~~oil and ~~other~~gas ~~substances,~~we ~~which~~produce ~~could~~and ~~affect~~lower the value of our ~~business~~reserves.

~~Furthermore~~Finally, init ~~response~~should tobe ~~recent~~noted ~~seismic~~that ~~events~~some ~~near~~sources ~~underground~~estimate ~~disposal~~that ~~wells~~increasing ~~used~~concentrations ~~for~~of ~~the~~GHGs ~~disposal~~in bythe ~~injection~~Earth’s ofatmosphere ~~produced~~may ~~water~~produce ~~resulting~~climate ~~from~~changes ~~oil~~that ~~and~~have ~~natural~~significant ~~gas~~physical ~~activities~~effects, ~~federal and some state agencies are investigating whether~~ such ~~wells~~as ~~have caused~~ increased ~~seismic~~frequency ~~activity,~~ and ~~some~~severity ~~states have restricted, suspended or shut down the use~~ of ~~such disposal wells. In response to these concerns~~storms, ~~regulators~~floods ~~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~~other ~~use~~climatic ~~of such wells~~events. ~~For~~If ~~example,~~such ~~Oklahoma~~effects ~~issued~~were ~~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~~occur, ~~from~~our ~~time~~development ~~to time, has developed~~ and ~~implemented~~production ~~plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well~~ operations. ~~The~~could ~~OCC has implemented the National Academy of Science’s “traffic light system,” in determining whether new injection wells should~~ be ~~permitted,~~adversely ~~permitted only with special restrictions, or not permitted at all~~affected. InPotential ~~addition,~~adverse ~~the~~effects ~~OCC~~could ~~has~~include ~~established~~damages ~~rules~~to ~~requiring~~our ~~operators~~facilities offrom ~~certain~~powerful ~~produced~~winds ~~water~~or ~~injection~~rising ~~wells~~waters in ~~seismically-active~~low lying areas, ordisruption ~~Areas~~ of ~~Interest,~~our ~~within~~production ~~the~~activities ~~Arbuckle~~because ~~formation~~ of ~~the~~climate ~~state~~related damages to, ~~among~~our ~~other things~~facilities, ~~conduct~~less ~~mechanical~~efficient ~~integrity testing~~ or ~~make~~non-routine ~~certain~~operating ~~demonstrations~~practices ofnecessitated by such ~~wells’~~climate ~~depth that~~effects, ~~depending~~or onincreased ~~the~~costs ~~depth,~~for ~~could~~insurance ~~require~~coverage ~~the~~in ~~plugging back of such wells and/or~~ the ~~reduction~~aftermath of ~~volumes disposed in~~ such ~~wells~~effects. AsSignificant aphysical ~~result~~effects of ~~these~~climate ~~measures,~~change ~~the~~could ~~OCC~~also ~~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~~indirect toeffect ~~mitigate~~on ~~the~~our ~~occurrence~~financing ~~of such incidents. Increased regulation~~ and ~~attention~~operations ~~given~~by todisrupting ~~induced~~the ~~seismicity~~transportation ~~could~~or ~~lead~~process-related toservices ~~greater~~provided ~~opposition,~~by ~~including~~midstream ~~litigation~~companies, toservice ~~oil~~companies ~~and~~or ~~natural~~suppliers ~~gas~~with ~~activities~~whom ~~utilizing~~we ~~injection~~have ~~wells~~a ~~for~~business ~~produced water disposal~~relationship. ~~Court~~At ~~decisions~~this ~~or the adoption of any new laws~~time, ~~regulations~~we orhave ~~directives~~not ~~that~~developed ~~restrict~~a ~~our~~comprehensive ~~ability~~plan to ~~dispose~~address ~~of produced water generated by production and development activities, whether by plugging back~~ the ~~depths of disposal wells~~legal, ~~reducing the volume of produced water disposed in such wells~~economic, ~~restricting~~social ~~injection well locations~~ or ~~otherwise,~~physical orimpacts byof ~~requiring~~climate uschange toon ~~shut~~our ~~down injection wells~~operations. Nor, ~~could~~are ~~significantly~~we ~~increase~~(on our ~~costs~~own) tocapable ~~manage and dispose~~ of doing this ~~produced~~in ~~water,~~a ~~which~~prudent ~~could~~and ~~have~~accurate amanner ~~material~~that ~~adverse~~would ~~effect~~best onserve our ~~financial~~investors’ ~~condition and results of operations~~interests.

~~Hydraulic~~Federal, ~~Fracturing~~ 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.

~~Many~~Hydraulic offracturing ~~our~~is ~~development~~an ~~projects~~essential ~~require~~and ~~hydraulic~~common ~~fracturing~~practice ~~procedures~~we use to ~~economically~~ develop ~~the~~our ~~formations~~reserves. The ~~Generally,~~process weinvolves ~~perform~~the ~~two~~injection ~~types~~ of ~~hydraulic fracturing. In the STACK play~~water, wesand ~~perform~~and ~~hydraulic~~additives ~~fracturing~~under inpressure ~~horizontally~~into ~~drilled~~a ~~wells.~~targeted ~~These~~subsurface ~~procedures~~formation ~~are~~to ~~more~~fracture ~~extensive,~~the ~~time-consuming~~surrounding rock and ~~expensive~~stimulate ~~than hydraulic fracturing of vertical wells~~production. We ~~also~~routinely ~~perform~~apply hydraulic fracturing intechniques ~~vertical~~to ~~wells~~stimulate inproduction ~~our~~from ~~East Texas fields, including primarily Urbana and Cold Springs (both in East Texas); among~~ the ~~target~~wells ~~zones~~we ~~are the Wilcox and Frio formations~~drill.

~~Currently,~~Our ~~most~~ hydraulic fracturing ~~activities~~technique ~~are~~is ~~regulated~~currently atgenerally ~~the~~exempt ~~state~~from ~~level,~~regulation asunder the SDWA’s ~~UIC~~Underground ~~program~~Injection ~~exempts~~Control ~~EPA~~(“UIC”) ~~regulation~~program ofand ~~most~~is ~~hydraulic~~typically ~~fracturing~~regulated ~~except~~by ~~for hydraulic fracturing activities involving~~ the ~~use~~Oklahoma ofCorporation ~~diesel~~Commission. 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 to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In ~~other examples, in~~ June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and ~~natural~~ 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 but, in June 2016 a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, and that decision is currently being appealed by the federal government. ~~However,~~ onOn ~~March~~December 1529, 2017, ~~the~~ BLM ~~filed~~rescinded ~~a motion in~~ the ~~appeal,~~2015 ~~asking the court to hold the case in abeyance pending rescission of the~~ rule. California ~~Additionally, in 2014, the EPA published an advanced notice of public rulemaking regarding Toxic Substances Control Act reporting of the chemical substances~~ and ~~mixture~~certain ~~used~~environmental ingroups ~~hydraulic~~have ~~fracturing.~~sued ~~From~~over ~~time to time,~~ the ~~U.S.~~BLM’s ~~Congress~~rescission ~~has introduced, but not adopted, legislation to provide for federal regulation~~ of ~~hydraulic fracturing and to require disclosure of chemicals used in~~ the ~~fracturing~~2015 ~~process~~rule.

~~Many states~~Additionally, ~~including~~in ~~Oklahoma~~2014, ~~where~~the weEPA ~~conduct~~published ~~operations,~~an ~~and~~advanced ~~other~~notice ~~regional~~of ~~and~~public ~~local~~rulemaking ~~regulatory~~regarding ~~authorities~~Toxic ~~have~~Substances ~~enacted,~~Control ~~and~~Act ~~other~~(“TSCA”) ~~states~~reporting orof ~~other~~the ~~regional~~chemical substances and ~~local~~mixture ~~authorities~~used ~~are~~in ~~considering, laws or other regulatory initiatives on~~ hydraulic fracturing,. ~~including~~From ~~disclosure~~time ~~requirements~~to ~~and~~time, ~~regulations~~Congress ~~that~~has ~~could restrict or prohibit drilling in general or hydraulic fracturing in~~

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

~~particular~~In addition, some states, including Oklahoma, have adopted, regulations that restrict or could restrict hydraulic fracturing in certain circumstances. ~~Some~~and ~~states~~that require the disclosure of the chemicals used in hydraulic fracturing operations. Concerns have ~~also~~been ~~considered~~raised orthat ~~adopted~~hydraulic ~~other~~fracturing ~~restrictions~~activities ormay ~~regulations~~be oncorrelated ~~drilling~~to ~~and~~anomalous ~~completion~~seismic ~~operations~~events. In December 2016, ~~including~~the ~~requirements~~OCC ~~regarding~~Oil ~~casing~~and Gas Conservation Division and ~~cementing~~the ofOklahoma ~~wells;~~Geological ~~testing~~Survey ofreleased ~~nearby~~well ~~water~~completion ~~wells;~~seismicity ~~restrictions~~guidance, onwhich ~~access~~requires operators to, ~~and~~take ~~usage~~certain ofprescriptive actions, ~~water;~~including ~~and~~an ~~restrictions~~operator’s onplanned ~~the~~mitigation ~~type~~practices, offollowing ~~chemical~~certain ~~additives~~unusual ~~that~~seismic ~~may~~activity bewithin ~~used~~1.25 inmiles 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 ~~natural~~ 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 ~~perform~~develop ~~hydraulic~~our ~~fracturing~~reserves ~~activities~~or ~~and~~conduct ~~thereby affect~~ our ~~production~~operations, ~~and~~either ~~increase~~one ~~our cost~~ of ~~doing~~which ~~business. Such increased costs and any delays or curtailments in our production activities~~ could have a material adverse effect on ~~our business, prospects, financial condition, results of operations and liquidity~~us.

~~Air~~Legislation ~~Emissions~~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.

~~Our~~We ~~operations~~dispose ~~are~~of ~~subject~~produced towater ~~the~~gathered ~~federal~~from ~~Clean~~our ~~Air~~operations ~~Act~~pursuant ~~(“CAA”)~~to ~~and~~permits ~~comparable~~issued ~~state~~to ~~laws~~our ~~and~~affiliates ~~implementing~~or ~~regulations~~third-party ~~that~~vendors ~~restrict~~by ~~the~~governmental ~~emission~~authorities ofoverseeing ~~air~~such ~~pollutants~~disposal ~~from~~activities. ~~many~~While ~~sources~~these ~~through~~permits ~~air~~are ~~emissions~~issued ~~standards,~~pursuant ~~construction~~to ~~and~~existing ~~operating~~laws ~~permit programs~~ and ~~the~~regulations, ~~imposition~~these oflegal ~~other~~requirements ~~compliance~~are ~~standards. These~~subject ~~laws~~to ~~and~~change, ~~regulations~~which ~~may~~could ~~require~~result usin ~~to obtain pre-approval for~~ the ~~construction~~imposition ~~or modification~~ of ~~certain~~more ~~projects~~stringent permitting or ~~facilities~~operating ~~expected~~constraints ~~to produce~~ or ~~significantly~~new ~~increase~~monitoring ~~air emissions, obtain~~ and ~~strictly~~reporting ~~comply with stringent air permit~~ requirements orowing ~~utilize~~to, ~~specific~~among ~~equipment~~other orthings, ~~technologies~~concerns ~~to control emissions~~ of ~~certain pollutants. The need to obtain permits has~~ the ~~potential~~public ~~to delay our projects~~ or ~~development~~governmental ofauthorities ~~oil~~regarding ~~and~~such ~~natural~~disposal ~~gas projects~~activities.

~~Over~~One ~~the~~such ~~next~~concern ~~several~~relates ~~years,~~to werecent ~~may~~seismic ~~incur~~events ~~certain~~near ~~capital~~underground ~~expenditures~~injection wells used for ~~air~~the ~~pollution~~disposal ~~control~~of ~~equipment~~produced orwater ~~other~~resulting ~~air~~from ~~emissions~~oil ~~related~~and ~~issues~~gas activities. ~~For~~When ~~example,~~caused inby ~~October~~human ~~2015~~activity, ~~the~~such ~~EPA~~events ~~issued~~are acalled ~~final~~induced ~~rule~~seismicity. ~~under~~Developing research suggests that the ~~CAA~~link between seismic activity and wastewater disposal may vary by region, ~~lowering~~and that only a very small fraction of the ~~National~~tens ~~Ambient~~of ~~Air~~thousands ~~Quality~~of ~~Standard~~injection ~~for~~wells ~~ground-level~~have ~~ozone~~been ~~from~~suspected to be, or have been, the ~~current~~likely ~~standard~~cause of 75induced ~~parts~~seismicity. ~~per~~In ~~million~~March 2016, tothe 70United ~~parts~~States ~~per~~Geological ~~million~~Survey ~~under~~identified ~~both~~six states with the ~~primary~~most ~~and~~significant ~~secondary~~hazards ~~standards~~from induced seismicity, including Oklahoma, where we operate. ~~State~~In ~~implementation~~response ofto these ~~revised~~concerns ~~standards~~regarding ~~could~~induced ~~result~~seismicity, regulators in ~~stricter~~some ~~permitting requirements~~states, ~~delay~~including orOklahoma, ~~prohibit~~have ~~our~~imposed, ~~ability~~and toother ~~obtain~~states ~~such~~are ~~permits~~considering imposing, ~~and~~additional ~~result~~requirements in ~~increased~~the ~~expenditures~~permitting ~~for~~of ~~pollution~~produced ~~control~~water ~~equipment,~~injection wells or otherwise to assess any relationship between seismicity and the ~~costs~~use of ~~which~~such ~~could~~wells. beFor ~~significant. Also~~example, ~~the~~Oklahoma ~~EPA~~issued ~~finalized~~new ~~separate~~ rules for ~~under~~injection ~~the~~wells ~~CAA~~ in ~~June~~2014 ~~2016~~that ~~regarding~~imposed ~~criteria~~certain ~~for~~permitting ~~aggregating~~and ~~multiple~~operating ~~sites~~restrictions ~~into~~and areporting ~~single~~requirements ~~source~~on ~~for~~injection ~~air-quality~~wells ~~permitting~~in ~~purposes~~proximity ~~applicable~~to faults and also, from time to ~~the~~time, ~~oil~~developed and ~~natural~~implemented ~~gas~~plans ~~industry~~directing certain wells where seismic incidents have occurred to restrict or suspend injection well operations. ~~This~~ ~~rule~~The ~~could~~Oklahoma ~~cause~~Corporation ~~small~~Commission ~~production~~(“OCC”) ~~facilities~~has ~~such~~implemented asthe ~~tank~~National ~~batteries~~Academy ~~and~~of ~~compressor~~Science’s ~~stations~~“traffic light system,” onin andetermining ~~aggregate~~whether ~~basis,~~new toinjection wells should be ~~deemed~~permitted, apermitted ~~major~~only ~~source~~with special restrictions, ~~thereby~~or ~~triggering~~not ~~more~~permitted ~~stringent~~at ~~air~~all. ~~permitting~~In ~~requirements~~addition, ~~and~~the ~~increasing~~OCC ~~our~~has ~~expenditures~~established ~~for~~rules requiring ~~permitting~~operators ~~and~~of ~~pollution~~certain ~~control~~produced ~~equipment. Additionally~~water injection wells in seismically-active areas, or Areas of Interest, within the ~~EPA~~Arbuckle ~~issued~~formation ~~final~~of ~~CAA~~the ~~regulations~~state into, ~~2012~~among ~~that~~other ~~include~~things, ~~NSPS~~conduct ~~for~~mechanical ~~completions~~integrity testing or make certain demonstrations of ~~hydraulically~~such ~~fractured~~wells’ ~~natural~~depth ~~gas~~that, depending on the depth, could require the plugging back of such wells and/or ~~issued~~the ~~added~~reduction ~~CAA~~of ~~regulations~~volumes disposed in ~~June~~such ~~2016~~wells. ~~that~~As ~~include~~a ~~new~~result ~~emissions~~of ~~standards~~these ~~for~~measures, ~~methane~~the OCC from time to time has developed and ~~additional~~implemented ~~standards~~plans calling for ~~volatile~~injection ~~organic~~wells ~~compounds~~within ~~from~~Areas ~~certain~~of ~~new,~~Interest ~~modified~~where ~~and~~seismic ~~reconstructed~~incidents ~~equipment~~have ~~and~~occurred ~~processes~~to inrestrict ~~the~~or ~~oil~~suspend ~~and~~disposal ~~natural~~operations ~~gas~~in ~~source~~an ~~category,~~attempt ~~including~~to ~~production~~mitigate ~~activities.~~the ~~Compliance~~occurrence ~~with~~of ~~these~~such ~~and~~incidents. ~~other~~In February 2017, ~~air~~the ~~pollution~~OCC’s ~~control~~Oil and ~~permitting~~Gas ~~requirements~~Conservation ~~has~~District ~~the~~issued ~~potential~~an toorder ~~delay~~limiting future increases in the ~~development~~volume of oil and ~~natural~~ gas ~~projects,~~wastewater ~~increase~~injected ~~our~~belowground ~~costs~~into ~~and~~the ~~reduce~~Arbuckle ~~the~~formation ~~demand~~in ~~for~~an ~~the~~effort ~~oil~~to ~~and~~reduce ~~natural~~the ~~gas~~number ~~that~~of weearthquakes ~~produce.~~in the state.

~~Climate~~Also, ~~Change~~ongoing ~~Regulation~~lawsuits allege that injection well disposal operations have caused damage to neighboring properties or otherwise violated state and ~~Legislation~~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

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 the international, national, regional and state 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 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, or criteria, 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 have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, which require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices. Moreover, in November 2016, the EPA issued an Information Collection Request (“ICR”) seeking information about methane emissions from facilities and operations in the oil and natural gas industry, but on March 2, 2017, the EPA announced that it was withdrawing the ICR so that the agency may further assess the need for the information that it was collecting through the request. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended

~~Table~~well oflocations ~~ContentsIndex~~or otherwise or by requiring us to ~~Financial~~shut ~~Statements~~ 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.

~~nationally~~Laws ~~determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016~~ and ~~entered~~regulations ~~into~~pertaining ~~force in November 2016; however, this agreement does not create any binding obligations for nations~~ to ~~limit~~threatened ~~their~~and ~~GHG~~endangered ~~emissions~~species ~~but, rather, includes pledges to voluntarily limit~~ or ~~reduce~~protective ~~future~~of ~~emissions. After~~environmentally ~~the~~sensitive ~~election,~~areas ~~President~~could ~~Trump~~delay ~~declared~~or ~~that~~restrict ~~the~~our ~~United~~operations ~~States~~and ~~would~~cause ~~not~~us ~~abide~~to byincur ~~the~~significant ~~Paris Agreement~~costs.

~~The~~Our ~~adoption~~operations ~~and~~may ~~implementation~~be ofadversely ~~any~~affected ~~international,~~by ~~federal~~seasonal or ~~state~~permanent ~~legislation,~~restrictions ~~regulations~~ or ~~other~~costly ~~regulatory~~mitigation ~~initiatives~~measures ~~that~~imposed ~~requires~~under ~~reporting~~various offederal ~~GHGs~~and orstate ~~otherwise~~statutes ~~restricts~~in ~~emissions~~order ofto ~~GHGs~~protect ~~from~~endangered ~~our~~or ~~equipment~~threatened species and ~~operations~~their ~~could~~habitats, ~~require~~migratory usbirds, towetlands ~~incur~~and ~~increased~~natural ~~operating~~resources. ~~costs~~Federal statutes, ~~such~~ as ~~costs~~amended from time to ~~purchase~~time, ~~and~~that ~~operate~~are ~~emissions~~protective ~~control~~of ~~systems~~these species, ~~acquire~~birds ~~emissions~~and ~~allowances~~environmentally orsensitive ~~comply~~areas ~~with~~include ~~new~~the ~~regulatory~~ESA, orthe ~~reporting~~Migratory ~~requirements~~Bird Treaty Act (the “MBTA”), ~~including~~the CWA, the ~~imposition~~CERCLA ofand athe ~~carbon~~OPA. ~~tax~~For example, ~~which~~to ~~one~~the orextent ~~more~~that ~~developments~~species ~~could~~are ~~have~~listed anunder ~~adverse~~the ~~effect~~ESA onor ~~our~~similar ~~business,~~state ~~financial~~laws ~~condition~~and live in areas where our oil and ~~results~~gas ofupstream ~~operations.~~activities ~~Moreover~~are conducted, ~~such~~our ~~new~~ability ~~legislation~~to conduct or ~~regulatory~~expand ~~programs~~operations ~~could~~and ~~also~~construct ~~increase~~facilities ~~the~~could ~~cost~~be tolimited ~~the~~or ~~consumer,~~we ~~and~~could ~~thereby~~be ~~reduce~~forced ~~demand~~to ~~for~~incur ~~oil~~material ~~and~~additional ~~gas~~costs. Moreover, ~~which~~our ~~could~~operations ~~reduce~~may ~~the~~be ~~demand~~delayed, ~~for~~restricted ~~the~~or ~~oil~~precluded ~~and~~in ~~natural~~protected ~~gas~~habitat weareas ~~produce~~or ~~and~~during ~~lower~~certain ~~the~~seasons, ~~value~~such ofas ~~our~~breeding ~~reserves.~~and nesting seasons.

~~Finally~~Additionally, itthe ~~should~~U.S. beFish ~~noted~~and Wildlife Service (“FWS”) may designate new or increased critical habitat areas that ~~increasing~~it ~~concentrations~~believes are necessary for survival of ~~GHGs~~threatened inor ~~the~~endangered ~~earth’s~~species, ~~atmosphere~~which ~~may~~designation ~~produce~~could ~~climate~~result ~~changes~~in ~~that~~material ~~have~~restrictions ~~significant~~to ~~physical~~federal ~~effects,~~land ~~such~~use asand ~~increased~~private ~~frequency~~land use and ~~severity~~could ofdelay ~~storms,~~or ~~floods~~prohibit ~~and~~land ~~other~~access ~~climatic~~or ~~events~~oil and gas development. IfAs ~~such~~a ~~effects~~result ~~were~~of toone ~~occur~~or more settlements approved by the federal government, ~~our~~the ~~development~~FWS ~~and~~must ~~production~~make ~~operations~~determinations ~~have~~on the ~~potential~~listing toof benumerous ~~adversely~~specified ~~affected.~~species ~~Potential~~as ~~adverse~~endangered ~~effects~~or ~~could~~threatened ~~include~~under ~~damages~~the ESA pursuant to ~~our~~specified ~~facilities~~timelines. ~~from~~The ~~powerful~~designation ~~winds~~of previously unidentified endangered or ~~rising~~threatened ~~waters~~species incould ~~low~~indirectly ~~lying~~cause ~~areas,~~us ~~disruption~~to ofincur ~~our~~additional ~~production~~costs, ~~activities~~cause ~~because~~our ofoperations ~~climate~~to ~~related~~become ~~damages~~subject to ~~our~~operating ~~facilities~~restrictions or bans, ~~our~~and ~~costs~~limit offuture ~~operations~~development ~~potentially~~activity ~~arising~~in ~~from~~affected ~~such~~areas. ~~climatic~~If ~~effects,~~harm ~~less~~to ~~efficient~~protected species or ~~non-routine~~damages ~~operating~~to ~~practices~~wetlands, ~~necessitated~~habitat byor ~~such~~natural ~~climate~~resources ~~effects~~occur or ~~increased~~may ~~costs~~occur, ~~for~~government ~~insurance~~entities ~~coverage~~or, inat ~~the~~times, ~~aftermath~~private ofparties ~~such~~may ~~effects.~~act ~~Significant~~to ~~physical~~prevent ~~effects~~oil ofand ~~climate~~gas ~~change~~exploration ~~could~~or ~~also~~development ~~have~~activities anor ~~indirect~~seek ~~effect~~damages onfor ~~our~~harm ~~financing~~to ~~and~~species, ~~operations~~habitat byor ~~disrupting~~natural ~~the~~resources ~~transportation~~resulting from drilling or ~~process-related~~construction ~~services~~or ~~provided~~releases byof ~~midstream~~oil, ~~companies~~wastes, ~~service~~hazardous ~~companies~~substances or ~~suppliers~~other ~~with~~regulated ~~whom~~materials, weand, ~~have~~in asome ~~business~~cases, ~~relationship~~may seek criminal penalties. AtThe ~~this~~designation ~~time,~~of wepreviously ~~have~~unprotected ~~not~~species ~~developed~~as athreatened ~~comprehensive~~or ~~plan~~endangered in areas where we conduct operations could cause us to ~~address~~incur ~~the~~increased ~~legal,~~costs ~~economic,~~arising ~~social~~from orspecies ~~physical~~protection ~~impacts~~measures ofor ~~climate~~time ~~change~~delays or limitations on our operations.

~~Activities~~We oncould ~~Federal~~experience ~~Lands~~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.

~~Oil~~Historically, ~~and~~our ~~natural~~capital ~~gas~~and ~~exploration~~operating ~~and~~costs ~~production~~typically ~~activities~~rise onduring ~~federal~~periods ~~lands,~~of ~~including~~sustained ~~Indian~~increasing ~~lands~~oil, ~~may~~gas beand ~~subject~~NGL toprices. ~~the~~These ~~federal~~cost ~~National~~increases ~~Environmental~~result ~~Policy~~from ~~Act~~a ~~(“NEPA”),~~variety ~~which~~of ~~requires~~factors ~~federal~~beyond ~~agencies,~~our ~~including~~control ~~the~~as ~~EPA,~~drilling toactivity ~~evaluate~~increases, ~~major~~such ~~agency~~as ~~actions~~increases ~~having~~in the ~~potential~~cost ~~to significantly impact the environment. In the course~~ of ~~such evaluations~~electricity, antubular ~~agency~~goods, ~~will prepare an Environmental Assessment that assesses the potential direct~~water, ~~indirect~~sand and ~~cumulative~~other ~~impacts~~disposable ofmaterials aused ~~proposed~~in ~~project~~fracture stimulation and, ifother ~~necessary,~~raw ~~will~~materials ~~prepare a more detailed Environmental Impact Statement~~ that ~~may~~we beand ~~made~~our ~~available~~vendors ~~for~~rely ~~public~~upon; ~~review~~ and ~~comment.~~the ~~All~~cost of ~~our~~services ~~current exploration~~ and ~~production activities~~labor, asespecially ~~well~~those asrequired ~~proposed~~in ~~exploration~~horizontal drilling and ~~development~~completion. ~~plans,~~As oncommodity ~~federal~~prices ~~lands~~rise ~~require~~or ~~governmental~~drilling ~~permits~~activity ~~that~~otherwise ~~are~~increases ~~subject~~in to the ~~requirements~~STACK, ofour ~~NEPA. This process has the potential to delay or impose additional conditions and~~ costs ~~upon~~for ~~the~~materials, ~~development~~services ~~of oil~~ and ~~natural~~labor ~~gas~~may ~~projects. Authorizations under NEPA are also subject to protest~~increase, ~~appeal or litigation, any or all of~~ which may ~~delay~~negatively orimpact ~~halt~~our ~~projects. Moreover~~profitability, ~~depending~~cash onflow ~~the~~and ~~mitigation~~cause ~~strategies~~us ~~recommended~~to indelay, ~~the~~reduce ~~Environmental Assessments~~ or ~~Environmental~~curtail ~~Impact~~our ~~Statement,~~drilling ~~we could incur added costs, which may be significant~~program.

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

WeThe ~~are~~marketability ~~subject~~of toour ~~the~~production ~~requirements~~depends ofupon the ~~federal~~availability, ~~Occupational~~proximity ~~Safety~~ and ~~Health~~capacity ~~Act~~of ~~(“OSHA”)~~facilities and ~~comparable~~services, ~~state~~including ~~statutes~~pipelines, ~~whose~~natural ~~purpose~~gas isgathering tosystems, ~~protect~~trucking ~~the~~or ~~health~~terminal facilities and ~~safety~~processing ~~of workers~~facilities. InWe ~~addition~~deliver oil, ~~the~~gas ~~OSHA~~and ~~hazard~~NGLs ~~communication~~through ~~standard,~~gathering ~~the~~systems ~~federal~~and ~~Emergency~~pipelines ~~Planning~~that we do not own. The lack of available capacity on these systems and ~~Community~~facilities ~~Right-~~could impact us by causing our production to be shut-~~Know~~in, ~~Act~~reducing ~~and~~the ~~comparable~~price ~~state~~we ~~statutes~~receive ~~and~~for ~~any~~our ~~implementing~~production ~~regulations~~or ~~require~~delaying ~~that~~or eliminating our future development plans. Although we ~~organize~~have some contractual control over this risk by virtue of the underlying contracts, such systems and~~/or~~ ~~disclose~~facilities ~~information~~may ~~about~~be ~~hazardous~~temporarily ~~materials~~unavailable ~~used~~due to market conditions or ~~produced~~operational reasons. Further, in ~~our~~the ~~operations~~future, ~~and~~they ~~that~~may ~~this~~not ~~information~~ be ~~provided~~available to ~~employees,~~us ~~state~~at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these systems and ~~local~~facilities, ~~governmental~~as ~~authorities~~well as any delays in constructing new systems and ~~citizens.~~facilities, could have a material adverse effect on us.

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

Our ~~operations~~operated ~~are~~production, ~~also~~not ~~subject~~otherwise topreviously ~~regulations~~dedicated, ~~governing~~is ~~the~~dedicated ~~handling,~~to ~~transportation~~KFM, ~~storage~~an ~~and~~entity ~~disposal~~under ofcommon ~~naturally~~control ~~occurring~~by ~~radioactive~~our ~~materials~~parent. In ~~Furthermore,~~November ~~owners~~2018, ~~lessees~~we ~~and~~sold ~~operators~~our ofproduced ~~natural~~water ~~gas~~assets ~~and~~to ~~oil~~a ~~properties~~subsidiary ~~are~~of ~~also~~KFM. ~~subject~~In toconjunction ~~increasing~~with ~~civil~~the ~~liability~~sale, ~~brought~~we byentered ~~surface~~into ~~owners~~a ~~and~~new ~~adjoining~~15-year ~~property~~water ~~owners.~~gathering ~~Such~~and ~~claims~~disposal ~~are~~agreement ~~predicated~~with onsuch ~~the~~subsidiary. As ~~damage~~a toresult, orwe ~~contamination~~are ofsubstantially ~~land~~dependent ~~resources~~upon ~~occasioned~~KFM byfor ~~drilling~~our ~~and production~~ operations. If ~~and~~KFM ~~the~~were ~~products~~unable ~~derived~~to ~~therefrom,~~continue ~~and~~to ~~are~~provide ~~often~~these ~~based~~services, onit ~~negligence,~~could ~~trespass,~~result ~~nuisance,~~in ~~strict~~the ~~liability~~shut-in orof ~~fraud.~~ our

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our

~~Table~~production ofor ~~ContentsIndex~~cause delays and additional costs to ~~Financial~~find ~~Statements~~ alternate providers for those services, any one of which could have a material adverse effect on us.

~~profitability,~~The ~~these~~parties ~~burdens~~on ~~generally~~whom dowe ~~not~~rely ~~affect~~for usgathering, ~~any~~transportation ~~differently~~and orprocessing toservices ~~any~~are ~~greater~~subject orto ~~lesser~~complex ~~extent~~federal, ~~than~~state ~~they~~and ~~affect~~ other ~~companies~~laws inthat ~~the~~could ~~industry~~adversely ~~with~~affect ~~similar~~the ~~types~~cost, ~~quantities~~manner ~~and~~or ~~locations~~feasibility of ~~production.~~conducting our business.

~~The availability~~Gathering, ~~terms~~transportation and ~~cost~~processing ofoperations ~~transportation~~are ~~significantly~~subject ~~affect~~to ~~sales~~complex oflaws ~~oil~~ and ~~natural~~regulations ~~gas.~~that ~~The~~require ~~interstate~~parties ~~transportation~~providing ofthese ~~oil~~services ~~and~~to ~~natural~~obtain ~~gas~~and ismaintain ~~subject~~numerous ~~to federal regulation~~permits, ~~including~~approvals ~~regulation~~and ofcertifications ~~the~~with ~~terms,~~various ~~conditions~~levels ~~and~~of ~~rates~~government. ~~for~~These ~~interstate~~operations ~~transportation,~~could ~~storage~~require ~~and~~substantial ~~various~~costs ~~other~~in ~~matters,~~order ~~primarily~~to bycomply ~~the~~with ~~Federal~~existing ~~Energy~~laws ~~Regulatory~~and ~~Commission, (the “FERC”)~~regulations. ~~Federal~~If laws and ~~state~~ regulations ~~govern~~governing ~~the~~such ~~rates~~operations ~~and~~are ~~other~~enacted, ~~terms~~revised ~~for~~or ~~access~~reinterpreted, tothese ~~oil~~changes ~~and~~may ~~natural~~affect ~~gas~~the ~~pipeline~~costs ~~transportation.~~that ~~FERC’s~~we ~~regulations~~pay for ~~interstate~~such ~~oil~~services. There ~~and~~could ~~natural~~be ~~gas~~a ~~transmission~~material byadverse ~~pipeline~~effect inon ~~some~~us ~~circumstances~~if ~~may~~the ~~also~~gathering, ~~affect~~transportation ~~the~~and ~~intrastate~~processing ~~transportation~~operations ofthat ~~oil~~we ~~and~~rely ~~natural~~upon ~~gas~~were materially impacted by ~~other~~those ~~means.~~laws and regulations.

~~Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation.~~ We ~~cannot~~have ~~predict~~limited ~~whether~~control ~~new~~over ~~legislation~~activities toon ~~regulate~~properties ~~oil~~we ~~and~~do ~~natural~~not ~~gas sales might be proposed~~operate, ~~what~~which ~~proposals,~~could ifreduce ~~any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on~~ our ~~operations.~~production ~~Sales of condensate, oil~~ and ~~natural gas liquids are not currently regulated and are made at market prices~~revenue.

~~Exports~~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 Uthe underlying properties.S The failure of another operator to adequately perform operations or that operator’s financial difficulties could reduce our production and revenue. ~~Crude~~The ~~Oil~~success ~~Production~~and timing of our drilling and development activities on properties operated by others, ~~Natural~~depends ~~Gas~~upon a number of factors outside of our control, including the operator’s timing of development and ~~Liquefied~~amount ~~Natural~~of ~~Gas~~capital expenditures, expertise and financial resources.

~~The~~Turnover ~~federal government has recently ended its decades-old prohibition~~ of ~~exports of oil produced in the lower 48 states of the United States. It is too recent an event to determine the impact this regulatory change may have on~~ our ~~operations~~key orexecutives ~~our~~and ~~sales~~Board of ~~oil.~~Directors ~~The~~and ~~general~~difficulty ~~perception in the industry is that ending the prohibition~~ of ~~exports~~recruiting of oil produced in the United States will be positive for producers of U.S. oil. In addition, the U.S. Department of Energy (the “DOE”) authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, which are expected to increase significantly with the changes taking place in the Mexican government’s regulation of the energy sector in Mexico. In addition, the DOE authorizes the export of LNG through LNG export facilities, the construction of which are regulated by FERC. In the third quarter of 2016, the first quantities of natural gas produced in the lower 48 states of the U.S. were exported as LNG from the first of several LNG export facilities being developed and ~~constructed~~retaining inkey ~~the~~employees ~~U.S.~~could ~~Gulf~~have ~~Coast~~a ~~region.~~material ~~While~~adverse ~~it is also too recent an event to determine the~~ impact ~~this change may have~~ on our ~~operations or our sales of natural gas, the perception in the industry is that this will be a positive development for producers of U~~business.~~S. natural gas.~~

~~Drilling~~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 ~~Production~~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 ~~operations~~success ~~are~~will ~~subject~~depend to ~~various~~a ~~types~~large extent upon the efforts and abilities of ~~regulation~~our atmanagement ~~the~~team ~~federal,~~and ~~state~~having experienced individuals serving on our Board of Directors who are also knowledgeable about our operations and ~~local~~our ~~level~~industry. If ~~These~~we ~~types~~are ofunable ~~regulation~~to ~~include~~retain ~~requiring~~or ~~permits~~find ~~for~~replacement employees, the ~~drilling~~loss of ~~wells,~~the ~~drilling~~services ~~bonds~~of ~~and~~one ~~reports~~or ~~concerning~~more ~~operations~~of these key employees could have a material adverse effect on us. We ~~The~~do ~~state,~~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 ~~some~~retain ~~counties~~qualified personnel. Acquiring and ~~municipalities,~~keeping inthese ~~which~~personnel wecould ~~operate~~prove more difficult or cost substantially more than estimated. We also ~~regulate~~may be unable to timely replace the talents and skills of our Directors if one or more ofdid ~~the~~not ~~following:~~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 ~~the~~operate ~~location~~in an area of ~~wells;~~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 ~~method~~STACK ofhas ~~drilling~~been quite active in recent years. As a result, demand for qualified personnel in this area, and ~~casing~~the ~~wells;~~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 ~~the~~may ~~timing~~encounter ofobstacles ~~construction~~marketing orour ~~drilling~~oil ~~activities~~and gas, ~~including~~which ~~seasonal~~could ~~wildlife~~adversely ~~closures;~~impact our revenue.

·The marketability of our production will depend in part upon the ~~rates~~availability of ~~production~~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 ~~“allowables”;~~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 ~~the~~availability ~~surface~~of ~~use~~markets ~~and~~is ~~restoration~~beyond ofour ~~properties~~control. ~~upon~~If market factors dramatically change, our revenue could be substantially impacted, which ~~wells~~could ~~are~~have ~~drilled;~~a material adverse effect on us.

· the plugging and abandoning of wells; and

· notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, which could negatively affect the economics of production from these wells or to limit the number of locations we can drill.

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

~~Federal,~~Our ~~state~~management is responsible for establishing and ~~local~~maintaining ~~regulations~~adequate ~~provide~~internal ~~detailed~~control ~~requirements~~over ~~for~~financial reporting (ICFR). Section 404 of SOX requires management to assess the ~~abandonment~~effectiveness of ~~wells,~~our ~~closure~~ICFR. Based oron ~~decommissioning~~our assessment as of ~~production~~December 31, ~~facilities~~2018, ~~and~~we ~~pipelines~~concluded ~~and~~that ~~for~~our ~~site~~ICFR ~~restoration~~was innot ~~areas~~effective ~~where~~as weof ~~operate.~~that ~~The~~date, Udue to identification of material weakness.S. A ~~Army~~material ~~Corps~~weakness is a deficiency or combination of ~~Engineers~~deficiencies ~~and~~in ~~many~~ICFR ~~other~~that ~~state~~causes ~~and~~a ~~local~~reasonable ~~authorities~~possibility ~~also~~that ~~have~~a ~~regulations~~material ~~for~~misstatement ~~plugging~~could occur and ~~abandonment,~~not ~~decommissioning~~be ~~and~~prevented ~~site~~or ~~restoration.~~detected ~~Although~~on ~~the~~a Utimely basis.S. ~~Army~~Our ~~Corps~~material weakness relates to both the design of ~~Engineers~~our ~~does~~controls ~~not~~and ~~require~~execution ~~bonds~~of orcontrol ~~other~~procedures. ~~financial~~Item ~~assurances,~~9A ~~some~~contains ~~state~~additional ~~agencies~~information ~~and~~regarding ~~municipalities~~our dodeficiencies ~~have~~and ~~such~~the ~~requirements~~proposed remediation plan.

~~Forced~~If ~~Pooling~~not remediated, the material weaknesses could result in ~~Oklahoma~~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.

~~The~~There ~~pooling~~are ~~process~~inherent ~~before~~limitations the OCC provides a mechanism to develop a unit when two or more of its owners cannot voluntarily agree to pool their interests for the purposes of drilling and development. This procedure, which is standard in anall ~~actively~~control ~~developed field in Oklahoma~~systems, isand ~~specific~~misstatements due to aerror ~~given~~or ~~reservoir.~~fraud ~~The parties~~ that ~~are~~could ~~the~~seriously ~~recipient~~harm ofour ~~pooling~~business ~~applications and orders under the OCC~~ may ~~elect~~occur ~~to: (i) lease their unleased minerals for stated terms; (ii) participate in the well~~ and ~~pay~~not ~~their proportionate share of costs; or (iii)~~ be ~~bought out for fair, just and reasonable compensation determined by the OCC~~detected.

~~Natural~~We ~~Gas~~do ~~Sales~~not expect that our internal controls and ~~Transportation~~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.

~~Historically,~~Cyber-attacks ~~federal~~targeting ~~legislation~~systems and ~~regulatory~~infrastructure ~~controls~~may ~~have~~adversely ~~affected~~impact ~~the price of the natural gas we produce and the manner in which we market~~ our ~~production~~operations. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.

~~Under~~Our ~~the~~industry ~~Energy~~has ~~Policy~~become ~~Act~~increasingly ofdependent ~~2005~~on ~~(“EPAct”),~~digital ~~Congress~~technologies ~~amended the Natural Gas Act (“NGA”)~~ to ~~give~~conduct ~~FERC) substantial enforcement authority~~ day-to-day ~~prohibit~~operations. ~~the~~For ~~manipulation of natural gas markets and enforce its rules and orders~~example, ~~including~~software ~~the~~programs ~~ability~~are toused ~~assess substantial civil penalties. EPAct also amended the NGA~~ to ~~authorize~~interpret ~~FERC~~seismic ~~to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce~~data,” ~~pursuant~~manage todrilling ~~which authorization FERC now requires natural gas wholesale market participants~~rigs, ~~including~~production aequipment ~~number~~and ofgathering ~~entities~~and ~~that~~transportation ~~may not otherwise be subject to FERC’s traditional NGA jurisdiction~~systems, toconduct ~~report~~reservoir ~~information~~modeling ~~annually to FERC concerning their natural gas sales~~ and ~~purchases.~~for ~~FERC~~compliance ~~requires any wholesale market participant that sells 2~~reporting.2 Industrial ~~million~~control ~~MMBtus~~systems orsuch ~~more annually in “reportable” natural gas sales to provide a report, known~~ as ~~FERC~~SCADA ~~Form~~(supervisory ~~552,~~control toand ~~FERC.~~data ~~Reportable~~acquisition) ~~natural~~now ~~gas~~control ~~sales~~large ~~include~~scale ~~sales~~processes ~~of natural gas~~ that ~~utilize~~can ainclude ~~daily~~multiple orsites ~~monthly~~and ~~gas~~long ~~price index~~distances, ~~contribute~~such toas ~~index~~power ~~price~~generation ~~formation,~~and ~~or could contribute to index price formation~~transmission, ~~such~~communications asand ~~fixed~~oil ~~price~~and ~~transactions~~gas ~~for next-day or next-month delivery~~pipelines.

~~FERC~~We ~~also~~depend ~~regulates~~on ~~interstate~~digital ~~natural gas transportation rates~~technology, ~~terms~~including ~~and~~information ~~conditions~~systems ~~of natural gas service,~~ and ~~the~~related ~~terms~~infrastructure ~~under~~as ~~which~~well we as acloud ~~shipper~~applications ~~may~~and ~~use interstate natural gas pipeline capacity~~services, ~~which~~to ~~affects~~process ~~the~~and ~~marketing~~record offinancial ~~natural~~and ~~gas~~operating ~~that we produce~~data, ascommunicate ~~well~~with ~~as the revenues we receive for sales of~~ our ~~natural~~employees ~~gas~~ and ~~for~~business ~~the release of our excess~~partners, ifanalyze ~~any,~~seismic ~~natural~~and ~~gas~~drilling ~~pipeline capacity. Commencing in 1985~~information, ~~FERC~~estimate ~~promulgated~~quantities ~~a series~~ of ~~orders,~~oil ~~regulations~~ and ~~rule-makings~~gas ~~that~~reserves ~~significantly~~as ~~fostered~~well ~~competition~~as inother ~~the~~activities ~~business~~related ofto ~~transporting~~our ~~and~~business. ~~marketing~~Our ~~gas.~~business ~~Today~~partners, ~~interstate~~including ~~pipeline~~vendors, ~~companies~~service ~~are~~providers, ~~required~~purchasers toof ~~provide~~our ~~nondiscriminatory transportation services to producers~~production, ~~marketers~~ and ~~other~~financial ~~shippers~~institutions, ~~regardless of whether such shippers~~ are ~~affiliated~~also ~~with~~dependent anon ~~interstate~~digital ~~pipeline company~~technology. ~~FERC’s~~The ~~initiatives~~technologies ~~have~~needed ~~led~~ to ~~the~~conduct ~~development~~oil ofand ~~a competitive, open access market for natural~~ gas ~~purchases~~exploration and ~~sales~~development ~~that~~activities ~~permits~~and ~~all~~global ~~purchasers~~competition offor ~~natural~~oil ~~gas~~and ~~to buy~~ gas ~~directly~~resources ~~from~~make ~~third-party~~certain ~~sellers~~information ~~other than pipelines. However,~~ the ~~natural~~target ~~gas~~of ~~industry~~theft ~~historically~~or has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activitiesmisappropriation.

Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.

Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transmission services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities, and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

~~Table~~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 ~~ContentsIndex~~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 ~~Financial~~targeted ~~Statements~~ cyber-attacks due to their critical role in operations.

~~1992,~~Our assystems ~~reauthorized~~ and ~~amended (“Pipeline Safety Act”)~~networks, and ~~the~~those ~~Pipeline~~of ~~Safety,~~our ~~Regulatory~~business ~~Certainty~~partners ~~and~~may ~~Job~~become ~~Creation~~the ~~Act~~target of ~~2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk~~cyber-~~based~~attacks ~~approach~~or toinformation ~~determine~~security ~~which~~breaches ~~gathering~~that ~~pipelines~~could ~~are~~result ~~subject~~in tothe ~~regulation~~unauthorized ~~and~~release, ~~what safety standards regulated~~ gathering, ~~pipelines~~monitoring, ~~must meet. In March 2016~~misuse, ~~the~~loss ~~PHMSA~~or ~~issued~~destruction aof ~~Notice~~information, ofor ~~Proposed~~cause ~~Rulemaking~~other ~~proposing~~disruptions to ~~revise~~our ~~the~~business ~~Pipeline~~operations. ~~Safety~~In ~~Regulations~~addition, ~~applicable~~certain tocyber ~~the~~incidents, ~~safety~~such ofas ~~onshore gas transmission and gathering pipelines~~surveillance, ~~including~~may ~~both~~remain ~~high~~undetected ~~consequence~~for ~~areas~~an ~~(“HCAs”)~~extended ~~and non-HCAs~~period.

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

~~Sales~~• ofunauthorized ~~oil~~access to seismic data, ~~condensate~~reserves ~~and~~information, ~~natural~~royalty ~~gas~~owner ~~liquids~~data ~~are~~or ~~not~~other ~~currently~~sensitive ~~regulated~~or ~~and~~proprietary ~~are~~information ~~made~~could athave ~~negotiated~~a ~~prices.~~negative ~~Nevertheless,~~impact ~~Congress~~on ~~could~~our ~~reenact~~ability ~~price~~to ~~controls~~compete infor ~~the~~oil ~~future.~~and gas resources;

~~Our~~• ~~sales~~data ofcorruption, ~~oil~~communication ~~and natural gas liquids are also affected by the availability~~interruption, ~~terms~~or ~~and~~other ~~costs~~operational ofdisruption ~~transportation.~~during ~~The~~drilling ~~rates,~~activities ~~terms~~could ~~and~~result ~~conditions~~in ~~applicable~~failure to ~~the~~reach ~~interstate transportation of oil and natural gas liquids by pipelines are regulated by~~ the ~~FERC,~~intended astarget ~~common~~or ~~carriers, under the Interstate Commerce Act. The FERC has implemented~~ a ~~simplified~~drilling 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. incident;

~~Further,~~• ~~interstate~~data ~~and~~corruption ~~intrastate~~or ~~common~~operational ~~carrier~~disruption ~~oil~~of ~~pipelines~~production ~~must~~infrastructure ~~provide~~could ~~service~~result on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in ~~the~~loss ~~pipelines’~~of ~~published tariffs. Accordingly~~production, weor ~~believe~~accidental ~~that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.~~ discharge;

~~Any~~• ~~transportation~~a ~~of our crude oil, natural gas liquids and purity components (ethane, propane, butane, iso~~cyber-~~butane~~attack ~~and~~on ~~natural~~a ~~gasoline)~~vendor byor ~~rail~~service isprovider ~~also~~could ~~subject~~result toin ~~regulation~~supply bychain ~~the~~disruptions ~~DOT’s~~which ~~PHMSA~~could ~~and~~delay ~~the~~or ~~DOT’s~~halt ~~Federal~~a ~~Railroad~~development ~~Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180~~project, ~~including~~effectively ~~Emergency~~delaying ~~Orders by~~ the ~~FRA~~start ~~and new regulations being proposed by the PHMSA, arising due to the consequences~~ of ~~train~~cash ~~accidents~~flows ~~and~~from the ~~increase in the rail transportation of flammable liquids.~~ project;

In• ~~October~~a ~~2015,~~cyber-attack ~~the~~on ~~PHMSA~~a ~~issued~~third ~~proposed~~party ~~new~~gathering ~~safety~~or ~~regulations~~pipeline ~~for~~service ~~hazardous~~provider ~~liquid~~could ~~pipelines,~~prevent ~~including~~us afrom ~~requirement~~marketing ~~that~~our ~~all~~production, ~~hazardous~~resulting ~~liquid~~in ~~pipelines have~~ a ~~system~~loss ~~for detecting leaks and establish a timeline for inspections~~ of ~~affected pipelines following extreme weather events or natural disasters.~~ revenue;

~~State~~• ~~Regulation~~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;

~~Texas~~• ~~regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes~~ a ~~4.6%~~cyber-attack ~~severance tax~~ on ~~oil production and~~ a ~~7.5%~~communications ~~severance~~network tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or ~~resource~~power ~~conservation,~~grid orcould ~~both.~~cause ~~States~~operational dodisruption ~~not~~resulting ~~regulate wellhead prices or engage~~ in ~~other~~loss ~~similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect~~ of ~~these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.~~ revenue;

~~Oklahoma~~• ~~currently imposes on all new wells, both horizontal and vertical, drilled on or after July 1, 2015,~~ a ~~tax~~deliberate 2%corruption of ~~gross~~our ~~production~~financial for the first 36 months of production and then at 7% thereafter. There will still be different treatment for a limited number of wells defined as enhanced recovery projects, production enhancement projects, inactive wells and economically at-risk oil or ~~gas~~operational ~~leases.~~data ~~Horizontal~~could ~~wells~~result ~~drilled~~in ~~prior~~events to July 1, 2015, will continue to be taxed at 1% for 48 months after production commences. Deep wells drilled prior to July 1, 2015, will continue to be taxed at 4% for 48 months, while most other wells drilled prior to July 1, 2015, will be taxed at 7% throughout their productive life. In response to a recent significant earthquake, federal and Oklahoma state regulators imposed limitations on disposal of ~~produced water in two counties. On September 12, 2016, federal and state regulators expanded and modified those emergency orders limiting disposal activity in the two~~non-~~county~~compliance ~~area.~~which ~~Multiple~~could ~~wells~~lead ~~shut down immediately after the earthquake are being allowed~~ to ~~resume~~regulatory ~~operations~~fines ~~with~~or ~~volume~~penalties; ~~limits.~~ and

~~Louisiana~~• ~~severance~~expensive ~~tax~~remediation laws are more complex than those of other states. Different schedules of taxes are imposed based on the different hydrocarbons produced. The basic (and highest) rate for natural gas is $0.164 per Mcf for full rate wells. The basis (and highest) rate for oil is 12.5% of value for full rate oil and condensate. There is a severance tax exemption for oil and gas produced from horizontal wells. Last yearefforts, ~~Louisiana~~distraction ~~imposed on operators~~ of ~~wells~~management aor ~~security~~damage ~~deposit~~to ~~requirement~~our ~~for plugging and~~ 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

~~Table~~• ofchanges ~~ContentsIndex~~ to ~~Financial~~items ~~Statements~~ excluded from the $1.0 million executive compensation deduction limitation.

~~abandonment~~The ~~obligations.~~further ~~Those~~passage ~~who own between 11 and 99 wells pay a deposit~~ of ~~$250,000. The~~any ~~fee is $500~~legislation,~~000~~ ~~for~~including ~~every~~the ~~100~~proposals ~~wells.~~above, ~~Owners~~or ofchanges ~~single~~in ~~wells pay by the depth~~U.S. ~~The~~federal ~~deposit~~income istax $7laws ~~per~~could ~~foot~~negatively ~~for~~affect ~~the~~our ~~first~~financial ~~3,000~~condition ~~feet~~and ~~with~~results ~~lower~~of ~~rates the deeper the well is drilled~~operations.

~~The~~Risks ~~petroleum~~Related ~~industry is also subject~~ to ~~compliance~~Our with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. Indebtedness

~~Other~~We ~~Regulation~~ 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.

InOur ~~addition~~present level of indebtedness requires us to ~~the~~use ~~regulation~~a ofsubstantial ~~oil~~portion ~~and~~of ~~natural~~our ~~gas~~cash ~~pipeline~~flow ~~transportation~~to ~~rates~~pay interest, ~~the~~which ~~oil~~reduces funds available to finance our capital and ~~natural~~acquisition ~~gas~~activities ~~industry~~and ~~generally~~could islimit ~~subject~~our flexibility in reacting to ~~compliance~~changes ~~with~~in ~~various~~our ~~other~~business. ~~federal,~~The ~~state~~outstanding ~~and~~debt ~~local~~under ~~regulations~~the Alta Mesa RBL bears interest at a variable rate, and ~~laws~~so a rise in interest rates will generate greater interest expense (provided we have not hedged against interest rate increases). ~~Some~~The amount of ~~those~~our ~~laws~~debt ~~relate~~may also cause us to ~~occupational~~be ~~safety,~~more ~~resource~~vulnerable ~~conservation~~to economic downturns and ~~equal~~adverse ~~employment~~developments ~~opportunity~~in our business.

~~General~~We ~~Corporate~~may ~~Information~~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.

~~Alta~~Our ~~Mesa~~ability ~~Holdings,~~to LPmeet isour adebt ~~Texas~~obligations ~~limited~~and ~~partnership~~other ~~founded~~expenses inwill ~~1987~~depend ~~with~~on ~~principal~~our ~~offices~~future atperformance, ~~15021~~which ~~Katy~~will ~~Freeway~~be affected by financial, ~~Suite~~business, ~~400~~economic, ~~Houston~~regulatory and other factors, ~~Texas~~many ~~77094~~of which we are unable to control. WeIf ~~can~~cash flow is not sufficient to service debt, we may be ~~reached~~required atto ~~(281) 530-0991~~refinance ~~and~~debt, ~~our~~sell ~~website~~assets ~~address~~or issell ~~www.altamesa.net.~~additional ~~Information~~securities on ~~the~~terms ~~website~~that iswe may not ~~part~~find ofattractive ~~this~~if ~~report~~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.

~~Item 1A.~~Our ~~Risk~~significant ~~Factors~~indebtedness could give rise to other material adverse consequences, including the following:

~~Each~~• of the ~~following~~Alta ~~risk~~Mesa ~~factors~~RBL ~~could adversely affect our business, operating results~~ and ~~financial~~the ~~condition.~~indenture Itgoverning isthe ~~not~~2024 ~~possible~~notes tohave ~~foresee~~cross ordefault ~~identify~~provisions, ~~all~~which ~~such~~could ~~factors.~~result ~~Investors~~in ~~should~~the ~~not~~acceleration ~~consider this list an exhaustive statement~~ of ~~all~~indebtedness ~~risks~~under ~~and~~both ~~uncertainties.~~agreements ~~This~~if ~~report~~we ~~also~~fail ~~contains~~to ~~forward-looking~~comply ~~statements~~with ~~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~~covenants ~~described below~~ and ~~factors~~other ~~described~~provisions ~~elsewhere~~ in ~~this~~either ~~report. Please read the section above entitled “Cautionary Statement Regarding Forward-Looking Statements” for further discussion of these matters.~~ agreement;

~~Oil~~• ~~and~~it ~~natural~~may ~~gas~~be ~~prices~~difficult ~~are~~to ~~highly~~satisfy ~~volatile~~our ~~and~~obligations, ~~depressed~~including ~~prices~~debt ~~can~~service ~~significantly~~requirements ~~and~~under ~~adversely~~debt ~~affect~~agreements, ~~our~~or ~~financial~~maintain ~~condition~~compliance ~~and~~with ~~results~~financial ofand ~~operations.~~other debt covenants;

~~Our~~• ~~revenue, profitability and cash flows depend upon~~ the prices for oil, natural gas and natural gas liquids. The prices we receive for oil and natural gas production are volatile and a decrease in prices can significantly and adversely affect our financial results and impede our growth, including our ability to ~~maintain~~obtain oradditional ~~increase~~financing ~~our~~for ~~borrowing~~working ~~capacity~~capital, ~~to repay current or future indebtedness and to obtain additional~~ capital onexpenditures, ~~attractive~~debt ~~terms.~~service ~~Changes~~requirements ~~in oil~~ and ~~natural~~other ~~gas~~general ~~prices~~corporate ~~have~~purposes amay ~~significant~~be ~~impact on the value of our reserves and on our cash flows.~~ impaired;

~~Historically,~~• ~~world-wide~~a ~~oil and natural gas prices and markets have been subject to~~ significant ~~change~~portion ~~and may continue to change in the future. In particular, the prices~~ of ~~oil~~our ~~and~~cash ~~natural~~flow ~~gas~~is ~~declined~~committed ~~dramatically~~to ~~after~~payments ~~the second half of 2014. Based~~ on ~~daily~~our ~~settlements of monthly contracts traded on the NYMEX~~debt, ~~the~~which ~~average~~will ~~price~~reduce ~~for~~ the ~~twelve~~funds ~~months~~available ~~ended December 31, 2016 for a barrel of oil ranged from a high of $52.17 in December 2016~~ to aus ~~low of $30.62 in February 2016, and the price~~ for another MMBtu of natural gas ranged from a high of $3.23 in December 2016 to a low of $1.71 in March 2016. Oil prices continued to fluctuate during 2017. Based on daily settlements of monthly contracts traded on the NYMEXpurposes, ~~the~~such ~~average~~as ~~price~~future ~~for~~capital ~~the twelve months ended December 31~~expenditures, ~~2017~~acquisitions ~~for a barrel of oil ranged from a high of $57.95 in December 2017 to a low of $45.20 in June 2017,~~ and ~~the~~general ~~price~~working ~~for an MMBtu of natural gas ranged from a high of $3.93 in January 2017 to a low of $2.63 in March 2017.~~ capital;

~~Continued~~• ~~fluctuations~~we inare ~~oil~~more ~~and~~vulnerable ~~natural~~to ~~gas prices,~~ price ~~declines~~fluctuations ~~or any other unfavorable market conditions could have a material adverse effect on our financial condition~~ and ~~on the carrying value of our proved reserves. The average realized price, excluding hedge settlements, at which we sold oil in 2017 was $49.44 per barrel compared~~ to ~~$40.54~~economic ~~per~~downturns ~~barrel in 2016~~ and ~~$46.22~~adverse ~~per~~industry ~~barrel~~conditions inand ~~2015. Because the oil price we are required to use to estimate~~ our ~~future~~flexibility ~~net cash flows is the average first day of the month price over the twelve months prior~~ to ~~the~~plan ~~date~~for, ofor ~~determination~~react ~~of future net cash flows~~to, ~~the~~changes ~~full effect of falling prices may not be reflected~~ in our ~~estimated~~business ~~net~~or ~~cash~~industry ~~flows for several quarters. We review the carrying value of our properties on a quarterly basis and once incurred, a write-down in the carrying value of our properties~~ is ~~not~~more ~~reversible~~limited; ~~at a later date, even if prices increase.~~ and

~~Prices~~• ~~for~~our ~~oil~~ability ~~and natural gas may fluctuate widely in response~~ to ~~relatively~~capitalize ~~minor~~on ~~changes~~business inopportunities ~~supply~~ and ~~demand,~~to ~~market~~react ~~uncertainty~~to ~~and~~competitive apressures ~~variety~~may ofbe ~~additional factors that are beyond our control, such as:~~ limited.

·The ~~the~~Alta ~~domestic~~Mesa RBL and ~~foreign~~the ~~supply~~indenture ofgoverning ~~and~~our ~~demand~~2024 ~~for~~Notes ~~oil~~have restrictive covenants that could limit our growth, financial flexibility and ~~natural~~our ~~gas;~~ability to engage in certain activities.

·The ~~the~~Alta ~~price~~Mesa RBL and ~~quantity~~the ofindenture ~~foreign~~governing ~~imports~~our of2024 ~~oil~~Notes have restrictive covenants that could limit our growth, financial flexibility and ~~natural~~our ~~gas;~~ability to engage in activities that may be in our long-term best interests. These covenants, among other things, limit our ability to:

·• ~~changes~~incur inadditional ~~federal regulations removing decades-old prohibition of the export of crude oil production in the U.S.~~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;

~~Table~~• ofincur ~~ContentsIndex~~liens; ~~to Financial Statements~~ and

·• ~~federal~~engage ~~regulations~~in ~~applicable~~certain toother ~~exports~~transactions ofwithout ~~liquefied natural gas (“LNG”), including~~ the ~~recently~~prior ~~initiated~~consent ~~exports~~ of ~~LNG~~our ~~liquefied from natural gas produced in the lower 48 states of the U~~lenders.~~S.;~~

·In ~~actions~~addition, ~~taken~~the byAlta ~~members~~Mesa ofRBL ~~the~~requires ~~Organization~~us ofto ~~Petroleum~~maintain ~~Exporting~~financial ~~Countries~~ratios ~~and~~or ~~other~~to ~~oil~~reduce ~~producing~~our ~~nations~~indebtedness inif ~~connection~~we are unable to comply with ~~their~~such ~~arrangements~~ratios, which may limit our ability to ~~maintain~~obtain ~~oil~~future ~~price~~financings ~~and~~to ~~production~~withstand ~~controls;~~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 ~~level~~Alta Mesa RBL borrowing base as a result of ~~consumer~~the ~~product~~periodic ~~demand;~~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 ~~weather~~under ~~conditions;~~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 ~~domestic~~we are unable to comply with the restrictions and ~~foreign~~covenants ~~governmental~~in ~~regulations~~our debt agreements, ~~including~~we ~~environmental~~could ~~initiatives~~default ~~and~~under ~~taxation;~~the terms of such agreements, which could ultimately result in an acceleration of repayment.

·If ~~overall~~we ~~domestic~~cannot comply with the restrictions and ~~global~~covenants ~~economic~~in ~~conditions;~~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 ~~the~~we ~~value~~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 ~~dollar~~various ~~relative~~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 ~~currencies~~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 ~~countries;~~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 ~~stockholder~~service ~~activism~~our ~~or activities by non-governmental organizations to restrict the exploration~~indebtedness, ~~development~~we ~~and~~require ~~production~~significant ofliquidity ~~oil~~ and ~~natural~~our ~~gas~~ability ~~in order~~ to ~~minimize~~generate ~~emissions~~cash ofdepends ~~carbon~~on ~~dioxide,~~many afactors ~~greenhouse~~beyond ~~gas~~our ~~(“GHG”);~~control.

·Our ~~political~~ability to service and ~~economic~~refinance ~~conditions~~our debt and ~~events~~to infund ~~foreign~~planned ~~oil~~capital ~~and~~expenditures ~~natural~~depends ~~gas~~on ~~producing~~our ~~countries,~~generating ~~including~~cash. This ~~embargoes,~~ability ~~continued~~hinges ~~hostilities~~on ingeneral ~~the~~economic, ~~Middle~~financial, ~~East~~competitive, legislative, regulatory and other ~~sustained~~factors ~~military~~beyond ~~campaigns,~~our ~~conditions~~control. inWe ~~South~~can ~~America,~~provide ~~Central~~no ~~America~~assurance that we will generate sufficient operating cash flow, ~~China~~that ~~and~~we ~~Russia~~will ~~and~~realize ~~acts~~the ofplanned ~~terrorism~~operating cost improvements or ~~sabotage;~~that future borrowings will be available to us in an amount sufficient to service and repay our debt, while still

· the proximity and capacity of natural gas pipelines and other transportation facilities to our production;

· technological advances affecting energy consumption;

· the price and availability of alternative fuels; and

· the impact of energy conservation efforts.

Substantially all of our production is sold to purchasers under contracts with market-based prices. Lower oil and natural gas prices will reduce our cash flows and may reduce the present value of our reserves.

Our exploration, exploitation, development and acquisition operations 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.

The oil and natural gas industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our business for the exploration, exploitation, development and acquisition of oil and natural gas reserves. As a result of the current price environment and in connection with the business combination, we have increased our budgeted capital expenditures for 2018. Our estimated STACK capital expenditures for 2018 are $568 million for the drilling and completion of wells, as well as other expenditures for facilities and acquisition of leaseholds. Our STACK capital expenditures for 2017 and 2016 totaled $356 million and $209 million, respectively, for the drilling and completion of wells, as well as other expenditures for facilities and acquisition of leaseholds. For the twelve months ended December 31, 2017, we have received approximately $92.7 million from BCE under our joint development agreement. We have funded development and operating activities primarily through equity capital raised from our affiliates, through borrowings, through the issuance of debt, and through internal operating cash flows. We intend to finance our future capital expenditures predominantly with cash flows from operations and with proceeds we received in the business combination. If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under our senior secured revolving credit facility and the future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

· the estimated quantities of our proved oil and natural gas reserves;

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

· the prices at which we sell our production; and

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

If our revenues or the borrowing base under our senior secured revolving credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. Our senior secured revolving credit facility 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 available under our senior secured revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our reserves and production and could adversely affect our business, results of operations, financial conditions and ability to make payments on our outstanding indebtedness.

~~Table~~funding ofour ~~ContentsIndex~~other liquidity needs. If we are unable to ~~Financial~~satisfy ~~Statements~~ our debt obligations, we may have to undertake alternative plans such as:

~~External~~• ~~financing~~refinancing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our senior secured revolving credit facility may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and we may be forced to limit or ~~defer~~restructuring our planned oil and natural gas development program, which will adversely affect the recoverability and ultimate value of our oil and natural gas properties, in turn negatively affecting our business, financial condition and results of operations. debt;

~~Our~~• ~~business~~selling ~~strategy involves the use of the latest available horizontal drilling, completion and production technology, which involve risks and uncertainties in their application.~~ assets;

~~Our~~• ~~operations~~reducing involve the use of the latest horizontal drilling, completion and production technologies, as developed by us and our service providers, in an effort to improve efficiencies in recovery of hydrocarbons. Use of these new technologies may not prove successful and could result in significant cost overruns or ~~delays~~delaying orcapital ~~reduction~~investments; ~~in production, and in extreme cases, the abandonment of a well. The difficulties we face drilling horizontal wells include:~~ or

·• ~~landing~~seeking ~~our~~to ~~wellbore~~raise inadditional ~~the desired drilling zone;~~capital.

·Any ~~staying~~alternative inplans ~~the~~that ~~desired~~we ~~drilling~~undertake ~~zone~~may ~~while~~still ~~drilling~~not ~~horizontally~~enable ~~through~~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 ~~formation;~~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 ~~running~~High ~~our~~Mesa ~~production~~Inc. ~~casing~~and ~~the~~its ~~entire~~subsidiaries ~~length~~(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 ~~wellbore;~~Alta Mesa RBL and could adversely impact the trading price for our securities.

·High ~~running~~Mesa ~~tools~~Services LLC (“HMS”), a subsidiary of HMI, is the promissor under two promissory notes in the principal amount of $1.5 million and ~~other~~$8.5 ~~equipment~~million. ~~consistently~~As ~~through~~of December 31, 2018, approximately $1.7 million and $11.7 million, respectively, were outstanding under the ~~horizontal~~promissory ~~wellbore~~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.

~~The~~Pursuant ~~difficulties~~to ~~that~~the Business Combination, we ~~face~~distributed ~~while~~our ~~completing~~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 ~~wells~~ability ~~include~~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 ~~following:~~ 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 ~~designing~~the ~~and~~Alta ~~executing~~Mesa RBL, Investments (as defined) are limited to $10.0 million. If the ~~optimum~~amounts ~~fracture~~due ~~stimulation~~from ~~program~~HMI ~~for~~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 ~~specific~~waiver ~~target~~or ~~zone;~~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, ~~running~~we ~~tools~~are co-guarantors under certain surety bonds with HMI, including bonds that cover the ~~entire~~non-STACK ~~length~~oil and gas assets owned by them. The surety has requested posting of ~~the~~collateral. ~~wellbore~~If ~~during~~HMI ~~completion~~cannot ~~operations;~~post ~~and~~collateral or satisfy its indemnity

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

In addition, certain of the new techniques we are adopting 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. Furthermore, the application of technology developed in drilling, completing and producing in one productive formation may not be successful in other prospective formations with little or no horizontal drilling history. If our use of the latest technologies does not prove successful, our drilling and production results may be less than anticipated or we may experience cost overruns, delays in obtaining production or abandonment of a well. As a result, the return on our investment will be adversely affected, we could incur material write-downs of unevaluated properties or undeveloped reserves and the value of our undeveloped acreage and reserves could decline in the future.

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

Our producing properties are geographically concentrated in the STACK. Because of this concentration, the success and profitability of our operations may 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 gathering, pipeline and rail transportation capacity constraints; (ii) the availability of rigs, equipment, oil field services, supplies and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operations in the STACK may be adversely affected by severe weather events such as floods, ice storms and tornadoes, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, results of operations and cash flows.

If oil and natural gas prices decrease, we anticipate that the borrowing base under our senior secured revolving credit facility, which is revised periodically, may be reduced, which would negatively impact our borrowing ability.

Lower prices could reduce our cash flows to a level that would require us to borrow to fund our 2018 capital budget. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas prices could render uneconomic a significant portion of our identified drilling locations. This may result in significant downward adjustments to our estimated proved reserves and, as a result, a decline in the borrowing base under our senior secured revolving credit facility. As a result, a substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

~~Table~~obligations, ofAlta ~~ContentsIndex~~Mesa tomay ~~Financial~~be ~~Statements~~ required post collateral or otherwise satisfy HMI’s obligations associated with HMI surety bonds.

~~Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling~~Item 1B. InUnresolved ~~addition,~~Staff ~~we may not be able to raise the substantial amount of capital that would be necessary to drill such locations~~Comments.

~~Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage~~None. These locations represent a significant part of our growth strategy. Our ability to drill and develop identified locations depends on a number of uncertainties, including oil, natural gas and NGLs prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are located, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

~~Furthermore, our estimate of the number of our net drilling locations is based on a number of assumptions, which may prove to be incorrect~~Item 2. For example, we have estimated the number of net drilling locations based on our expected working interests in each gross drilling location based on our existing working interest associated with our acreage applicable to such drilling location and any assumed dilution of such working interest based on any expected unitization (or imposed forced pooling) of such acreage with adjacent properties controlled by third parties. Our assumptions regarding the impact on any such unitization or forced pooling on our working interest in our gross drilling locations may be incorrect and may result in more dilution of our working interest than anticipated, which would result in a reduction of our net drilling locations. See “Risk Factors—We may have difficulty maintaining our historic levels of success in using the current Oklahoma forced pooling process to increase our interest in wells we propose to drill on our STACK acreage due to changes in third-party interest owners’ ability or desire to participate in our wells or possible future regulatory changes.” Properties

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 raise the capital required. Any drilling activities we are able to conduct on these potential locations may not be successful or allow us to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. Overview

~~Certain~~As of ~~our~~December ~~undeveloped~~31, ~~leasehold~~2018, ~~assets~~we ~~are~~have ~~subject~~assembled toa ~~leases~~highly ~~that~~contiguous ~~will~~position ~~expire~~of ~~over~~approximately 140,000 net acres in the ~~next~~up-dip, ~~several~~naturally-fractured ~~years~~oil ~~unless~~portion ~~production~~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 ~~established~~characterized onby ~~units~~multiple ~~containing~~productive ~~acreage~~zones located at total vertical depths between 4,000 feet and 8,000 feet.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, 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, we do have provisions in some of our leases that provide for the lease to expire unless certain conditions are met, such as drilling having commenced on the lease or production in paying quantities having been obtained within a defined time period. If commodity prices decline or we are unable to fund our anticipated capital program, there is a risk that some of our existing proved reserves and some of our unproved inventory could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. 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 reserves and our growth opportunities (or the incurrence of significant costs). Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas 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 successful exploration, exploitation, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we may be adversely affected.

~~Table~~At ofDecember ~~ContentsIndex~~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 ~~Financial~~use ~~Statements~~ 2-3 rigs for the remainder of 2019 as we focus on the optimal completion design, well pattern and lowering well costs.

~~Lower~~Bayou ~~oil,~~City ~~natural~~Joint ~~gas~~Development ~~and natural gas liquids prices may cause us to record non-cash write-downs, which could negatively impact our results of operations.~~ Agreement

~~Accounting~~In ~~rules~~January ~~require~~2016, ~~that~~ we ~~periodically~~entered ~~review~~into ~~the~~a ~~carrying~~joint ~~value~~development ofagreement ~~our~~(as ~~properties~~subsequently ~~for~~amended, ~~possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at~~ the ~~time~~“JDA”) ofwith ~~prospective~~BCE-STACK ~~impairment~~Development ~~reviews~~LLC (“BCE”), ~~and~~a ~~the~~fund ~~continuing~~advised ~~evaluation~~by ofBayou ~~development~~City ~~plans~~Management, ~~production data~~LLC, ~~economics,~~to ~~and~~fund ~~other~~a ~~factors,~~portion weof ~~may~~our bedrilling ~~required~~operations towith ~~write down~~ the ~~carrying~~intent ~~value~~to ofaccelerate our ~~properties~~development. The AJDA ~~write-down~~establishes ~~constitutes~~ a ~~non-cash~~development ~~charge~~plan ~~to earnings. We recognized impairment expense during 2017 and 2016~~ of ~~$30.3~~60 ~~million~~wells ~~and~~in ~~$16.3~~three ~~million~~tranches, ~~respectively,~~and asprovides aopportunities ~~result~~for ~~of lower forecasted commodity prices. We may incur impairment charges in~~ the ~~future,~~parties ~~which~~to ~~could~~potentially ~~have~~agree ato ~~material~~an ~~adverse~~additional ~~effect~~20 onwells. As ~~our results~~ of ~~operations~~December 31, ~~for~~2018, ~~the~~61 ~~periods~~joint inwells ~~which~~had ~~such~~been ~~charges~~drilled ~~are~~or ~~taken~~spudded.

InUnder the ~~future~~JDA, weup ~~may~~to ~~recognize~~100% ~~significant impairments~~ of ~~proved oil and natural gas properties and impairments of unproved oil and natural gas properties as a result of lower forecasted commodity prices and changes to~~ our ~~drilling~~well ~~plans.~~costs Atcould ~~December 31,~~be ~~2017,~~funded ~~our~~up ~~estimate of undiscounted future cash flows attributable~~ to ~~our proved oil and natural gas properties with~~ a ~~net~~specified ~~book~~total ~~value~~well ~~of approximately $762~~cost.~~2 million~~ We ~~indicated~~are ~~that~~responsible ~~the carrying amount was expected to be recovered; however, this depletion group may be at risk~~ for ~~impairment~~any ifdrilling ~~oil~~ and ~~natural~~completion ~~gas~~costs ~~prices~~exceeding ~~decline~~approved ~~by 10%~~amounts. WeIn ~~estimate~~exchange ~~that,~~for ifBCE carrying the ~~oil~~drilling and ~~natural~~completion ~~gas~~costs, ~~prices~~they ~~decline~~receive ~~by 10~~80%, ~~this~~of ~~depletion~~our ~~group~~working ~~becomes~~interest ~~impaired~~ in aeach ~~future~~funded ~~period~~well ~~and~~until weattaining ~~could~~a ~~recognize~~15% ~~non-cash~~internal ~~impairments~~rate ~~in that period in excess~~ of ~~$2.7 million.~~return Itfor isthe ~~also~~entire ~~reasonably foreseeable that prolonged low or further declines in commodity prices~~tranche, ~~further~~at ~~changes~~which totime ~~our~~their ~~drilling~~interest ~~plans~~reduces ~~in response~~ to ~~lower~~20%. If ~~prices~~a ortranche ~~increases~~attains ina ~~drilling~~25% orinternal ~~operating~~rate ~~costs~~of ~~could~~return, ~~result~~their ininterest ~~other~~reduces ~~additional~~to ~~impairments~~12. 5%.

~~Our~~During ~~estimated~~the ~~proved~~Successor ~~oil~~Period, ~~and~~we ~~natural~~brought ~~gas~~25 ~~reserve~~horizontal ~~quantities~~wells ~~and~~on ~~future~~ production ~~rates~~that ~~are~~were ~~based~~funded onthrough ~~many~~the ~~assumptions~~JDA. ~~that~~At ~~may~~December 31, ~~prove~~2018, tothere bewere ~~inaccurate.~~no ~~Any~~funded ~~material~~horizontal ~~inaccuracies~~wells in ~~these~~progress, ~~reserve~~and ~~estimates~~we ordo ~~the~~not ~~underlying~~expect ~~assumptions~~any ~~will~~wells ~~materially~~to ~~affect~~be ~~the~~developed ~~quantities~~in ~~and~~2019 ~~present~~pursuant ~~value~~to ofthe ~~our reserves~~JDA.

~~Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves.~~ Our ~~estimates~~Oil ~~of our proved reserve quantities are based upon our estimated net proved reserves as of December 31, 2017. The process of estimating oil~~ and ~~natural~~Gas gas reserves is complex, requiring 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 future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling 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 natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the 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 twelve month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced. Reserves

~~The~~Our ~~present value of future net revenues from our~~ proved reserves orand ~~“PV-10”~~production ~~will~~profile ~~not necessarily be the same~~ as ~~the current market value~~ of ~~our~~December ~~estimated~~31, ~~proved~~2018 ~~oil~~was ~~and~~as ~~natural gas reserves.~~ follows:

It should not be assumed that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the closing prices on the first day of each month for the preceding twelve months from the date of the report without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:



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

~~· actual prices we receive for crude oil and natural gas;~~_________________

·(1) ~~actual~~Computed ~~cost~~as a percentage of ~~development~~total proved reserves. Based on our April 2019 assessment of our ability to continue as a going concern and ~~production~~our ~~expenditures;~~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 ~~amount~~first day of each of the twelve months ended December 31, 2018, as established by the SEC. Because Alta Mesa is a partnership and, ~~timing~~as such, is not subject to income taxes, our PV-10 is the same as our standardized measure of ~~actual~~future ~~production;~~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) ~~transportation~~Includes developed and ~~processing;~~undeveloped ~~and~~acreage.

·(4) ~~changes~~Calculated inas ~~governmental~~gross ~~regulations~~wells ormultiplied ~~taxation~~by our working interest percentage for each well.

~~The~~(5) ~~timing~~Average ofdaily ~~both~~net ~~our~~ production ~~and~~for ~~our incurrence of expenses in connection with~~ the ~~development~~Successor ~~and production of our oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves and thus their actual present value~~Period. In addition, the 10% discount factor we use when calculating the PV-10 value may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimate. If oil and natural gas prices decline by 10%, then our PV-10 value as of December 31, 2017 would decrease by approximately $358.3 million to $747.7 million.

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.

Table of ContentsIndex to Financial Statements



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

SEC rules could limit our ability to book additional PUDs in the future.



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

The SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill, or change our development plans to delay the drilling of those wells within the required five-year timeframe.



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

~~Approximately 68% of our total estimated proved reserves at December 31, 2017 were PUDs requiring substantial capital expenditures and may ultimately prove to be less than estimated.~~ _________________

~~Recovery~~(1) ofProved ~~PUDs~~reserves ~~requires~~were ~~significant~~calculated ~~capital~~using ~~expenditures~~oil and ~~successful~~gas ~~drilling~~parameters ~~operations.~~established Atby ~~December~~current ~~31,~~SEC ~~2017,~~guidelines ~~approximately~~and ~~125.1~~accounting ~~MMBOE of our total estimated proved reserves were undeveloped~~rules. ~~The~~Reserve ~~reserve~~estimates ~~data~~are ~~included~~based inon ~~our~~various ~~reserve~~assumptions, ~~reports~~including ~~assumes~~assumptions ~~that~~required ~~substantial~~by ~~capital~~the ~~expenditures~~SEC ~~will~~relating ~~be made~~ to ~~develop~~oil ~~non-producing~~and ~~reserves.~~gas ~~The~~prices, ~~calculation~~drilling ofand ~~our~~operating ~~estimated~~expenses, ~~net~~capital ~~proved reserves as of December 31~~expenditures, ~~2017~~taxes ~~assumed~~and ~~that~~availability weof ~~would~~funds. ~~spend~~Actual ~~$978.4~~future ~~million~~production, ~~including~~oil ~~plugging~~ and ~~abandonment~~gas ~~costs~~prices, torevenue, ~~develop~~taxes, ~~our~~development ~~estimated PUDs~~expenditures, ~~including~~operating anexpenses ~~estimated $382.7 million during 2018. Although cost~~ and ~~reserve~~quantities ~~estimates~~of ~~attributable~~recoverable ~~to our~~ oil and ~~natural~~ gas reserves ~~have~~may ~~been~~vary ~~prepared~~from inthese ~~accordance~~estimates. ~~with~~In ~~industry standards~~addition, we ~~cannot be sure that the estimated costs are accurate. We~~ may ~~need~~adjust toour ~~raise~~estimates ~~additional~~of ~~capital~~proved inreserves ~~order~~ to ~~develop~~reflect ~~our~~production ~~estimated~~history, ~~PUDs~~results ~~over~~of ~~the~~exploration ~~next five years~~ and ~~we cannot be certain that additional financing will be available to us on acceptable terms~~development, ifprevailing atoil ~~all.~~and ~~Additionally,~~gas ~~continued declines in commodity~~ prices ~~will~~and ~~reduce~~other ~~the~~factors, ~~future~~many ~~net revenues~~ of ~~our~~which ~~estimated~~are ~~PUDs~~beyond ~~and~~our ~~may result in some projects becoming uneconomical~~control. As aSustained ~~result of~~ lower ~~oil and natural gas~~ prices, we may ~~reduce~~result ~~the budgeted capital expenditures for the development of undeveloped reserves. These delays~~ in the ~~development~~estimated ofquantities ~~reserves~~and ~~could~~present ~~force~~values ~~us to reclassify certain~~ of our ~~proved~~ reserves asbeing ~~unproved~~reduced ~~reserves. Further, our drilling efforts may be delayed or unsuccessful~~ and ~~actual reserves~~ may ~~prove~~necessitate tofuture beimpairments ~~less~~of ~~than current reserve estimates, which, could have a material adverse effect on~~ our ~~financial~~capitalized ~~condition, results of operations and future cash flows~~costs.

As(2) ~~part~~Average ofmarket ~~our~~prices ~~exploration~~represent ~~and~~an ~~development~~unweighted ~~operations,~~arithmetic weaverage ~~have~~of ~~expanded, and expect to further expand,~~ the ~~application~~market ofprice ~~horizontal~~on ~~drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to~~ the ~~completion~~first ~~cost~~day of aeach ~~vertical~~month ~~well.~~during ~~The incremental capital expenditures are~~ the ~~result~~last of12 ~~greater measured depths and additional hydraulic fracture stages in horizontal wellbores~~months.

We may experience difficulty in achieving and managing future growth.

We believe that our future success depends on our ability to manage the growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

· increased responsibilities for our executive level personnel;

· increased administrative burden;

· increased capital requirements; and

· increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties.

Additionally, future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

· the results of our drilling program;

· hydrocarbon prices;

· our ability to develop existing prospects;

· our ability to obtain leases or options on properties for which we have 3-D seismic data;

· our ability to acquire additional 3-D seismic data;

· our ability to identify and acquire new exploratory prospects;

· our ability to continue to retain and attract skilled personnel;

· our ability to maintain or enter into new relationships with project partners and independent contractors; and

· our access to capital.

~~Table~~Proved ofUndeveloped ~~ContentsIndex to Financial Statements~~ Reserves

WeThe ~~depend~~information ~~upon~~presented ~~several~~during ~~significant purchasers for~~ the ~~sale~~Predecessor ofPeriods ~~most~~includes ofamounts ~~our~~related ~~oil~~to ~~and~~discontinued ~~natural gas production~~operations. Changes ~~The~~in ~~loss of one or more of these purchasers could, among other factors, limit~~ our ~~access~~proved toundeveloped ~~suitable~~reserves ~~markets~~were ~~for~~(in ~~the oil, natural gas and NGLs we produce.~~ MBoe):

The availability of a ready market for any oil, natural gas and NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. While we believe that we would be able to locate alternative purchasers, we cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.



	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	%

~~We will rely on drilling to increase our levels of production. If our drilling is unsuccessful, our financial condition will be adversely affected.~~ _________________

~~The~~(1) Reserves ~~primary~~sold/distributed ~~focus~~during ofthe ~~our~~period ~~business~~January ~~strategy~~1, is2018 to ~~increase~~February ~~production~~8, ~~levels by drilling wells. Although we were successful in drilling in the past~~2018, werepresent ~~cannot~~amounts ~~provide~~related ~~assurance that we will continue~~ to ~~maintain~~our ~~production~~non-STACK ~~levels~~properties ~~through drilling. Our drilling involves numerous risks, including the risk~~ that ~~we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. The costs of drilling and completing wells~~ are ~~often~~classified ~~uncertain,~~as ~~and~~discontinued itoperations ~~is possible that we will make substantial expenditures on drilling and not discover reserves~~ in ~~commercially~~our ~~viable~~consolidated ~~quantities.~~financial statements.

We(2) ~~may~~Effective beas ~~unable~~of December 31, 2018, due to ~~make~~uncertainty ~~attractive~~regarding ~~acquisitions~~our orability ~~successfully~~to ~~integrate~~continue ~~acquired~~as ~~businesses,~~a going concern and ~~any~~the ~~inability~~availability of capital that would be required to dodevelop sothe ~~may~~proved ~~disrupt~~undeveloped ~~our~~reserves, ~~business~~we ~~and~~have ~~hinder~~removed all of our ~~ability~~PUDs tofrom ~~grow.~~our total estimated proved reserves.

WeDuring ~~have~~the ~~made~~Successor ~~and~~Period, ~~may~~we inincurred ~~the~~approximately ~~future~~$160.6 ~~make~~million ~~acquisitions~~in ofexpenditures ~~businesses~~to ordevelop ~~properties~~PUD ~~that~~reserves. ~~complement~~PUD orreserves ~~expand~~may ~~our~~only ~~current~~be ~~business.~~booked Weif ~~may~~they ~~not~~relate beto ~~able~~wells scheduled to ~~identify~~be ~~attractive~~drilled ~~acquisition~~within ~~opportunities.~~five ~~Even~~years ifof wethe dooriginal ~~identify~~date ~~attractive~~of ~~acquisition~~their ~~opportunities,~~recognition. weThe ~~may~~identification ~~not~~and bedevelopment ~~able~~of toPUDs ~~complete~~in the ~~acquisition~~future oris dodependent so on ~~commercially~~future ~~acceptable~~commodity ~~terms~~prices, costs, capital availability and other economic assumptions. During WeJanuary ~~may~~2019, ~~not~~we befinalized ~~able~~our todevelopment ~~obtain~~plan ~~contractual~~for ~~indemnities~~the next five years and received an audit report from ~~sellers~~our ~~for~~outside ~~liabilities~~engineers ~~incurred~~that ~~prior~~agreed towith our ~~purchase~~recognition of PUDs for the ~~business~~majority orof ~~property~~that future development. During NoApril ~~assurance~~2019, ~~can~~in befinalizing ~~given~~our ~~that~~financial reporting for 2018, we ~~will~~determined bethat ~~able~~we may fail to ~~identify~~satisfy ~~additional~~the ~~suitable~~leverage ~~acquisition~~covenant ~~opportunities,~~under ~~negotiate~~the ~~acceptable~~Alta ~~terms~~Mesa RBL during 2019. Accordingly, ~~obtain~~we ~~financing~~were ~~for~~unable ~~acquisitions~~to onconclude ~~acceptable~~that ~~terms~~we orwould ~~successfully~~have ~~acquire~~continuing ~~identified~~access ~~targets.~~to Inthat capital source in the ~~course~~event of ~~our~~a ~~due~~failure ~~diligence~~of the leverage covenant. Thus, we ~~may~~concluded that we did not ~~inspect~~satisfy ~~every~~the ~~aspect~~ability-to-drill ofthreshold aunder ~~business~~the weSEC’s ~~acquire~~reserve recognition rule with respect to our future drilling locations and did not recognize any proved undeveloped locations in our final December 31, we2018 ~~cannot~~reserve ~~necessarily~~report. Should ~~observe~~our ~~structural~~ability ~~and~~to ~~environmental~~fund ~~problems~~the required development costs improve in the future, ~~such~~we asexpect ~~pipe~~to ~~corrosion~~recognize all or ~~groundwater~~a ~~contamination,~~portion ~~when~~of anthose ~~inspection~~resources isas ~~made~~proved.

~~The~~Internal ~~success~~Controls ofOver ~~any~~Reserve ~~completed~~Estimates ~~acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties~~ and ~~may~~Qualifications ~~require a disproportionate amount~~ of ~~our~~Technical managerial and financial resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Persons

InOur ~~addition,~~policies and practices regarding internal controls over reserve recognition are structured to objectively and accurately estimate our ~~senior~~oil ~~secured~~and ~~revolving~~gas ~~credit~~reserves ~~facility~~quantities and ~~the~~their ~~indenture~~present ~~governing~~value ~~the~~in ~~2024~~compliance ~~Notes~~with ~~impose~~SEC ~~certain~~standards. The ~~limitations~~reserve onestimation process begins with our ~~ability~~Corporate toDevelopment ~~enter~~department, ~~into~~which ~~mergers~~gathers orand ~~combination~~analyzes ~~transactions.~~much ~~Our~~of ~~senior~~the ~~secured~~data ~~revolving~~used ~~credit~~as ~~facility~~inputs to estimating reserves. Working and ~~the~~net ~~indenture~~revenue ~~governing~~interests ~~the~~are ~~2024~~sourced ~~Notes~~from ~~also~~our ~~limit~~division order system in our ~~ability~~land todepartment. Lease ~~incur~~operating ~~certain~~expenses ~~indebtedness,~~are ~~which~~provided ~~could~~by ~~indirectly~~our ~~limit~~accounting department and our ~~ability~~operations toteam ~~engage~~provides incapital ~~acquisitions~~expenses. Our Vice President of ~~businesses~~Corporate Planning and Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:

~~Our~~• ~~business~~Over is30 ~~subject~~years toof ~~operational~~practical ~~risks~~experience ~~that~~in ~~will~~petroleum ~~not~~engineering beand ~~fully~~in ~~insured,~~the ~~which,~~estimation ifand ~~they~~evaluation ~~were to occur, could adversely affect our financial condition or results~~ of ~~operations.~~reserves; and

~~Our~~• ~~business~~Bachelor ~~activities~~of ~~are~~Science ~~subject~~Degree toin ~~operational~~Petroleum ~~risks~~Engineering from the University of Texas in 1980, ~~including:~~Master of Business Administration from Oklahoma City University in 1988.

·Our ~~damages~~methodologies toinclude ~~equipment~~reviews ~~caused~~of byproduction ~~natural~~trends, ~~disasters~~material ~~such~~balance ascalculations, ~~earthquakes~~analogy ~~and~~to ~~adverse~~comparable ~~weather~~properties, ~~conditions~~and volumetric analysis, ~~including~~with ~~tornadoes~~performance methods preferred. Reserve estimates for developed non-producing properties and ~~flooding;~~for undeveloped properties are based primarily on analogy to offset production in the same area.

·We ~~facility~~maintain orinternal ~~equipment~~controls ~~malfunctions;~~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:

· pipeline or tank ruptures or spills;

· surface fluid spills, produced water contamination and surface or groundwater contamination resulting from petroleum constituents or hydraulic fracturing chemical additions;

· fires, blowouts, craterings and explosions; and

· uncontrollable flows of oil or natural gas or well fluids.

In addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and

~~Table~~• ofwe ~~ContentsIndex~~follow comprehensive SEC-compliant internal policies to ~~Financial~~determine ~~Statements~~ and report proved reserves;

~~processing~~• ~~facilities.~~reserve ~~These~~estimates ~~alternative~~are ~~facilities~~made ~~may~~by ~~not~~experienced bereservoir ~~available,~~engineers ~~which~~or ~~could~~under ~~cause~~their usdirect tosupervision; ~~shut in our natural gas production. Further, such alternative facilities could be more expensive than the facilities we currently use.~~ and

~~Any~~• ofannually, ~~these events could adversely affect~~ our ~~ability~~Chief toOperating ~~conduct~~Officer ~~operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources~~ and ~~equipment,~~Chief ~~pollution~~Executive orOfficer ~~other~~review ~~environmental~~all ~~contamination,~~significant ~~loss~~reserves ofchanges ~~wells, regulatory penalties, suspension or termination of operations~~ and ~~attorney’s~~all ~~fees~~new ~~and~~proved ~~other~~undeveloped ~~expenses~~reserves ~~incurred in the prosecution or defense of litigation~~additions.

AsRyder isScott ~~customary~~Company, inLP ~~the~~(“Ryder ~~industry~~Scott”), wea ~~maintain~~third-party ~~insurance~~petroleum ~~against~~engineering ~~some~~consulting ~~but~~firm, ~~not~~audited ~~all~~approximately 96% of ~~these~~our ~~risks.~~2018 ~~Additionally,~~proved wereserves ~~may~~on ~~elect~~a ~~not~~6:1 toMcf ~~obtain~~per ~~insurance~~Bbl ifconversion webasis. ~~believe~~Their ~~that~~report ~~the~~is ~~cost~~filed ofwith ~~available~~this ~~insurance~~Annual isReport ~~excessive~~as ~~relative~~Exhibit to99.1. ~~the~~The ~~perceived~~reserve ~~risks~~audit ~~presented.~~by ~~Losses~~Ryder ~~could~~Scott ~~therefore~~conformed ~~occur~~to ~~for~~the ~~uninsurable~~meaning orof ~~uninsured~~“reserves ~~risks~~audit” oras inpresented ~~amounts~~ in ~~excess~~the ofSEC’s ~~existing~~Regulation ~~insurance~~S-K, ~~coverage~~Item 1202. The ~~occurrence~~qualifications of anthe ~~event~~technical ~~that~~person isat ~~not~~Ryder ~~fully~~Scott ~~covered~~primarily byresponsible ~~insurance~~for ~~could~~overseeing ~~have~~the aaudit ~~material~~of ~~adverse impact on~~ our ~~business~~reserve ~~activities,~~estimates ~~financial~~are ~~condition~~set ~~and~~forth ~~results of operations~~below.

~~Drilling~~Miles ~~for~~R. ~~and~~Palke ~~producing~~earned ~~oil~~a B.S. in Petroleum Engineering from Texas A&M University in College Station, Texas and ~~natural~~a ~~gas~~Master ~~are~~of ~~high~~Science ~~risk~~in ~~activities~~Petroleum Engineering from Stanford University in Palo Alto California. Mr. Palke graduated Magna Cum Laude and with ~~many~~University ~~uncertainties~~Honors ~~that~~from ~~could~~Texas ~~adversely~~A&M ~~affect~~University ~~our~~and ~~business~~is a registered Professional Engineer in the State of Texas. Based on his educational background, ~~financial~~professional ~~condition~~training orand ~~results~~more than 22 years of ~~operations~~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.

~~Our~~A ~~future~~reserves audit and a financial ~~condition~~audit are separate activities with unique and different processes and results. ofA ~~operations~~reserves ~~will~~audit ~~depend~~under onSEC standards is the ~~success~~process of ~~our~~reviewing ~~development,~~certain ~~acquisition~~of the pertinent facts interpreted and ~~production~~assumptions ~~activities~~underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, ~~which~~the ~~are~~adequacy ~~subject~~and toquality ~~numerous~~of ~~risks~~the ~~beyond~~data ~~our~~relied ~~control~~upon, ~~including~~the depth and thoroughness of the ~~risk~~reserves ~~that~~estimation ~~drilling~~process, ~~will~~the ~~not~~classification ~~result~~of inreserves ~~commercially~~appropriate ~~viable~~to ~~oil~~the relevant definitions used, and ~~natural~~the ~~gas~~reasonableness ~~production.~~of the estimated reserves quantities.

~~Our~~Oil ~~decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through geophysical~~ and ~~geological~~Gas ~~analyses~~Production, ~~production~~Production ~~data~~Prices and ~~engineering~~Production studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “— Our estimated proved oil and natural gas reserve quantities 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.” Costs

~~Any~~Information ~~material~~relating ~~inaccuracies~~to inour ~~reserve~~oil ~~estimates or underlying assumptions will materially affect the quantities~~ and ~~present~~gas ~~value~~production, ofsales ~~our~~prices ~~reserves. In~~for ~~addition,~~ our ~~cost~~products ofproduced ~~drilling, completing~~ and ~~operating~~production ~~wells~~costs is ~~often~~included ~~uncertain.~~in Item 1.

~~Further,~~Drilling ~~many~~and ~~factors~~Other ~~may~~Exploratory ~~curtail,~~and ~~delay~~Development ~~or cancel our scheduled drilling projects, including the following:~~ Activities

· delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal;



	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 ~~regulation~~at ~~limiting~~Year ~~emission of GHGs and limitations on hydraulic fracturing;~~End

·At ~~pressure~~December or31, ~~irregularities~~2018, we were in ~~geological~~process ~~formations;~~of drilling 32 gross (26 net) wells.

· shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

· 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 oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

· declines in oil and natural gas prices;

· limited availability of financing at acceptable terms;

· title problems; and

· limitations in the market for oil and natural gas.

Our hedging activities 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 natural gas, we have entered and may continue to enter into hedging arrangements for a significant portion of our production. As of December 31, 2017, we

~~Table~~Delivery ~~of ContentsIndex to Financial Statements~~ Commitments

~~have~~Information ~~hedged~~about ~~approximately 35% of~~ our ~~total~~firm ~~forecasted~~transportation ~~PDP~~commitments ~~production~~is ~~through~~included ~~2020 at weighted average annual floor prices ranging from $50.00 per Bbl to $51.59 per Bbl for oil and $3.60 per MMBtu for natural gas, with the majority of the hedged volumes~~ in ~~2018. Our~~Part ~~senior secured revolving credit facility limits the amount of hedges that we can place on our PDP production. If we experience a sustained material interruption in our production~~II, weItem might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity7. Lastly, an attendant risk exists in hedging activities 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.

~~Our~~Productive ~~ability~~Wells, toDeveloped ~~use hedging transactions to protect us from future price declines will be dependent upon prices at the time we enter into future hedging transactions~~ and ~~our~~Undeveloped ~~future levels of hedging and, as a result our future net cash flows, may be more sensitive to commodity price changes.~~ Acreage

~~Our~~The ~~policy~~following ~~has~~sets ~~been~~forth toinformation ~~hedge~~with arespect ~~significant~~to ~~portion of~~ our ~~near-term~~wells ~~estimated production. However, our price hedging strategy~~ and ~~future~~acreage ~~hedging transactions will be determined at our discretion. We are not~~ under anlease ~~obligation~~as ~~to hedge a specific portion~~ of ~~our~~December ~~production. 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~~31, ~~which may be substantially higher or lower than current prices. Accordingly~~2018, ~~our~~all 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 with the next few years,~~ which ~~would~~is ~~result~~located in ~~our~~the ~~oil~~United ~~and natural gas revenues becoming more sensitive to commodity price fluctuations.~~ States:

Our hedging transactions expose us to counterparty credit risk.



	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

~~Our~~ hedging transactions expose us to risk of financial loss if our counterparty fails to perform under a derivative contract. This risk of counterparty non-performance is of particular concern given the disruptions that have occurred in the financial markets and the significant declines in oil and natural gas prices which could lead to sudden changes in a counterparty’s liquidity, and impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. _________________

~~During~~(1) ~~periods~~Productive wells are producing wells and those wells we deem capable of ~~falling~~production. ~~commodity~~A ~~prices~~gross ~~our~~well ~~hedge~~is ~~receivable~~a ~~positions~~well ~~increase,~~in which ~~increases~~a ~~our~~working ~~exposure~~interest is owned. IfThe number of net wells represents the ~~creditworthiness~~sum of ~~our~~fractional ~~counterparties~~working ~~deteriorates~~interests ~~and~~we ~~results~~own in ~~their~~gross ~~nonperformance~~wells, weincluding ~~could~~joint ~~incur~~development ~~a significant loss~~wells.

(2) Our ~~use~~lease ofacreage ~~2-D~~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-D ~~seismic~~to ~~data~~5 years. As is ~~subject~~customary toin ~~interpretation~~our ~~and~~industry, our undeveloped leasehold may ~~not~~be ~~accurately~~maintained ~~identify~~through: ~~the~~(i) ~~presence~~commencing ofoperations ~~hydrocarbons~~for drilling, ~~which~~completion ~~could~~and ~~adversely~~production, ~~affect~~(ii) pooling, (iii) extensions or renewals and (iv) other operational extensions, including shut-in payments and continuous operations. As of December 31, 2018, the ~~results~~majority of our ~~drilling~~undeveloped ~~operations~~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.

~~Even~~Title ~~when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used~~ to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons. We are employing 3-D seismic data technology with respect to certain of our projects. The use of 2-D and 3-D seismic data and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. Properties

We ~~often~~typically ~~gather~~conduct ~~2-D~~a ~~and~~preliminary ~~3-D~~review ~~seismic~~of ~~data~~title ~~over~~records, ~~large~~which ~~areas.~~may ~~Our~~include ~~interpretation~~opinions ofor ~~seismic~~reports ~~data delineates those portions~~ of anappropriate ~~area~~professionals ~~that~~or wecounsel, ~~believe~~at ~~are~~the ~~desirable~~time ~~for drilling. Therefore,~~ we ~~may choose not to~~ acquire ~~option~~properties. orWe ~~lease~~believe ~~rights~~that ~~prior~~title to ~~acquiring~~our ~~seismic~~interests ~~data,~~is satisfactory and, inconsistent ~~many~~with ~~cases,~~the westandards ~~may identify hydrocarbon indicators before seeking option or lease rights~~ in ~~the~~our ~~location~~industry. IfThe weinterests ~~are~~owned ~~not~~by ~~able~~us tomay ~~lease~~be ~~those~~subject ~~locations~~to onone ~~acceptable~~or ~~terms~~more royalty, weoverriding ~~will~~royalty ~~have~~net ~~made~~profits ~~substantial~~interests, ~~expenditures~~liens ~~to acquire~~ and ~~analyze~~taxes ~~2-D~~or ~~and~~other ~~3-D~~outstanding ~~seismic~~interests ~~data~~(including ~~without~~disputes ~~having~~related ~~an opportunity~~ to ~~attempt~~such tointerests) ~~benefit~~customary ~~from~~in ~~those~~the ~~expenditures~~industry.

~~Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel~~Item 3. Legal Proceedings

~~Our~~We ~~ability~~are subject to ~~acquire~~legal ~~additional~~proceedings, ~~properties~~claims and toliabilities ~~discover~~arising ~~reserves~~ in the ~~future~~ordinary ~~will~~course of business. The outcomes cannot be ~~dependent~~reasonably ~~upon~~estimated; ~~our~~however, ~~ability~~in tothe ~~evaluate~~opinion of management, such litigation and ~~select~~claims ~~suitable~~will ~~properties~~be toresolved ~~consummate~~without ~~transactions~~material inadverse aeffect ~~highly~~on ~~competitive~~our ~~market.~~financial ~~Our~~position, ~~competitors~~results ~~may~~of beoperations ~~able~~or tocash ~~pay~~flows. ~~more~~Accruals for ~~oil~~losses ~~and~~associated ~~natural~~with ~~gas~~litigation ~~properties~~are ~~and~~made ~~evaluate,~~when ~~bid~~losses ~~for~~are ~~and~~deemed ~~purchase~~probable aand ~~greater~~can ~~number~~be ofreasonably ~~properties~~estimated. Because ~~than~~legal ~~our~~proceedings ~~financial~~are orinherently ~~human~~unpredictable ~~resources~~and ~~permit.~~unfavorable Inresolutions ~~addition~~could occur, ~~the~~assessing ~~oil~~contingencies ~~and~~is ~~natural~~highly ~~gas~~subjective ~~industry~~and ~~has~~requires ~~periodically~~judgments ~~experienced~~about ~~shortages~~uncertain offuture ~~drilling~~events. ~~rigs,~~When ~~equipment~~evaluating contingencies, ~~pipe~~we ~~and~~may ~~personnel,~~be ~~which~~unable ~~has~~to ~~delayed~~provide ~~development~~a ~~drilling~~meaningful ~~and~~estimate ~~other~~due ~~exploitation~~to ~~activities~~a ~~and~~number ~~has~~of ~~caused~~factors, ~~significant~~including ~~price~~the ~~increases.~~procedural ~~Competition~~status ~~has~~of ~~been~~the ~~strong~~matter in ~~hiring~~question, ~~experienced~~the ~~personnel,~~presence ~~particularly~~of incomplex ~~the~~or ~~engineering~~novel ~~and~~legal ~~technical~~theories, ~~accounting~~and/or the ongoing discovery and ~~financial~~development of information important to the matters.

~~Table of ContentsIndex to Financial Statements~~ Litigation

~~reporting~~On January 30, ~~tax~~2019, AMR, James T. Hackett, AMR’s interim Chief Executive Officer and ~~land~~Chairman ~~departments~~of the Board, certain of AMR’s former and current directors, Thomas J. ~~Our~~Walker, ~~inability~~AMR’s toformer ~~compete~~Chief ~~effectively~~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 ~~our~~the ~~competitors~~Business ~~could~~Combination ~~have~~and, therefore, violated Section 14(a) ~~material~~of ~~adverse~~the ~~impact~~Securities onExchange ~~our~~Act ~~business~~of ~~activities~~1934, ~~financial~~as ~~condition~~amended (the “Exchange Act”), and ~~results~~Rule 14-9 promulgated thereunder. In addition, the plaintiff alleges that Riverstone and the individual defendants violated Section 20(a) of ~~operations~~the Exchange Act. The plaintiff is seeking compensatory and/or rescissory damages against the defendants.

WeOn ~~may~~March ~~not~~14 beand ~~able~~19, to2019, ~~keep~~two ~~pace~~additional ~~with~~putative ~~technological~~securities ~~developments~~class action complaints were filed in the ~~oil~~U.S. District Court for the Southern District of Texas (“SDTX Complaints”) against the same defendants named in the SDNY Complaint, and ~~natural~~Harlan ~~gas~~H. ~~industry~~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 ~~oil~~outcome ~~and~~of ~~natural~~the ~~gas~~above ~~industry~~securities isclass ~~characterized~~action bycomplaints ~~rapid~~is ~~and~~uncertain, ~~significant technological advancements~~ and ~~introductions~~while ~~of new products and services using new technologies. As others use or develop new technologies,~~ we ~~may~~believe bethat ~~placed~~AMR athas avalid ~~competitive~~defenses ~~disadvantage or competitive pressures may force us~~ to ~~implement~~the ~~those~~plaintiff’s ~~new~~claims ~~technologies at substantial costs. In addition, other oil~~ and ~~natural~~intend ~~gas~~to ~~companies~~defend ~~may~~the ~~have~~lawsuits ~~greater financial~~vigorously, ~~technical~~no ~~and~~assurance ~~personnel~~can ~~resources~~be ~~that~~given ~~allow~~as ~~them~~ to ~~enjoy~~the ~~technological~~outcome ~~advantages~~of ~~and may in~~ the ~~future allow them to implement new technologies before we can~~lawsuits. We ~~may~~are not bea ~~able~~party to ~~respond to~~ these ~~competitive~~suits ~~pressures~~but ~~and implement new technologies on a timely basis or at~~ an ~~acceptable~~adverse ~~cost.~~outcome Ifcould ~~one~~potentially orimpact ~~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,~~ our business~~, financial condition and results of operations could be materially adversely affected~~.

~~Deficiencies~~On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of ~~title~~Kingfisher toCounty, ~~our~~Oklahoma, ~~leased~~against ~~interests~~Oklahoma ~~could~~Energy ~~significantly~~Acquisitions, ~~affect~~LP, and eight other entities, including certain of our ~~financial~~affiliates ~~condition~~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.

IfIn anAugust ~~examination~~2017, ofBiloxi Marsh Lands (“Biloxi”) filed suit in the ~~title~~34th ~~history~~District Court for the Parish of aSt. ~~property~~Bernard, ~~reveals~~Louisiana, ~~that~~against anMeridian ~~oil~~Resource or& ~~natural~~Exploration ~~gas~~LLC ~~lease~~(a orsubsidiary of HMI), us, and other ~~developed~~defendants. Biloxi ~~rights~~alleges ~~has~~negligent ~~been~~construction, ~~purchased~~installation, inmaintenance, ~~error~~use ~~from~~and operation of a ~~person~~pipeline. In ~~who~~lieu isof ~~not~~litigating ~~the~~corporate ~~owner~~structure ofallegations ~~the~~and ~~mineral~~to ~~interest~~reduce ~~desired~~potential litigation expenses, ~~our~~we ~~interest~~stipulated ~~would~~with ~~substantially~~respect ~~decline~~to inBiloxi ~~value.~~that Inwe ~~such~~would ~~cases,~~be ~~the~~bound ~~amount~~by ~~paid~~and ~~for~~assume ~~such~~liability ~~oil~~and orresponsibility ~~natural~~for ~~gas~~any ~~lease~~unpaid ordebts, ~~leases~~obligations or ~~other~~final ~~developed~~judgments ~~rights~~that ~~would~~may be ~~lost.~~entered Itagainst isMeridian ~~the~~in ~~practice~~favor of ~~our~~Biloxi ~~management~~in this matter. However, inthese ~~acquiring~~allegations relate to non-STACK oil and ~~natural~~ gas ~~leases~~assets orthat ~~undivided~~we ~~interests~~distributed into ~~oil~~a ~~and~~subsidiary ~~natural~~of ~~gas~~HMI ~~leases~~prior orto ~~other~~the ~~developed~~Business ~~rights~~Combination. In connection with that distribution, ~~not~~certain HMI subsidiaries agreed to ~~incur~~indemnify ~~the~~and ~~expense~~hold ofus ~~retaining~~harmless ~~lawyers~~from toany ~~examine~~liabilities ~~the~~associated ~~title~~with tothose ~~the~~non-STACK ~~mineral~~oil ~~interest~~and togas beassets, ~~acquired.~~regardless ~~Rather~~of when those liabilities arose. Consequently, we ~~rely~~believe ~~upon~~that ~~the~~any ~~judgment~~potential ofdamages ~~oil~~incurred ~~and~~by ~~natural~~us ~~gas~~or ~~lease~~Meridian ~~brokers~~as ora ~~landmen~~result ~~who~~of ~~perform~~these allegations are the ~~fieldwork~~responsibility inof ~~examining~~HMI. There ~~records~~is inno ~~the~~guarantee ~~appropriate~~that ~~governmental~~HMI will pay any settlement amounts or ~~county~~judgments ~~clerk’s~~rendered ~~office~~against ~~before~~us ~~attempting~~or Meridian. In addition, our ability to ~~acquire~~collect aany ~~lease~~amounts ordue ~~other~~pursuant ~~developed~~to ~~rights~~these inindemnification aobligations ~~specific~~will ~~mineral~~depend ~~interest.~~upon the liquidity and solvency of HMI.

~~Prior~~SEC to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and it may happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Our failure to obtain perfect title to our leasehold may adversely impact our ability in the future to increase production and reserves. Investigation

~~Our~~The ~~operations~~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 ~~substantially~~cooperating ~~dependent~~with onthis investigation. At this point we are unable to predict the ~~availability~~timing or outcome of ~~water~~this investigation. If ~~Restrictions~~the onSEC ~~our~~determines ~~ability~~that toviolations ~~obtain~~of ~~water~~the ~~may~~federal securities laws have anoccurred, ~~adverse~~the ~~effect~~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 ~~and cash flows~~.

~~Water~~Environmental is an essential component of shale oil and natural gas exploration and production 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 be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. If we are unable to obtain sufficient amounts of water to use in our operations from local sources, our ability to perform hydraulic fracturing operations could be restricted or made more costly, or we otherwise may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. Claims

Our operations may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental laws or regulations or a release of hazardous substances or other wastes into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example, the following federal laws and their state counterparts, as amended from time to time:

· 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 EPA as authority for adopting climate change regulatory initiatives relating to GHG emissions;

· the Federal Water Pollution Control Act, also known as the 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;

· OPA, which imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States;

~~Table~~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 ~~ContentsIndex~~mineral leases and alleged failure to ~~Financial~~restore ~~Statements~~ 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. ~~SDWA,~~Mine ~~which~~Safety ~~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;~~Disclosures

·Not ~~RCRA, which imposes requirements for the generation, treatment, storage, transport disposal and cleanup of non-hazardous and hazardous wastes;~~applicable.

·PART CERCLA, which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur as well as imposes liability on present and certain past owners and operations of sites were hazardous substance releases have occurred or are threatening to occur;II

·Item 5. ~~the~~Market ~~Emergency~~for ~~Planning~~Registrant’s ~~and~~Common ~~Community Right to Know Act~~Equity, ~~which~~Related ~~requires~~Stockholder ~~facilities~~Matters ~~to implement a safety hazard communication program~~ and ~~disseminate~~Issuer ~~information~~Purchases toof ~~employees,~~Equity ~~local emergency planning committees and response departments about toxic chemical uses and inventories;~~Securities

·No ~~the~~class ~~Endangered~~of ~~Species~~our ~~Act~~limited ~~(“ESA”),~~partnership ~~which~~interests ~~restricts~~has ~~activities~~been ~~that~~registered ~~may~~under ~~affect~~the ~~federally~~Exchange ~~identified~~Act ~~endangered~~of ~~and~~1934, ~~threatened~~as ~~species~~amended ~~or their habitats through~~ (the ~~implementation~~“Exchange ~~of operating limitations or restrictions or a temporary~~Act”), ~~seasonal~~and orthere ~~permanent~~is ~~ban~~no onestablished ~~operations~~public intrading ~~affected~~market ~~areas;~~for ~~and~~our equity.

·As ~~NEPA,~~of ~~which~~May ~~requires~~17, ~~federal~~2019, ~~agencies~~SRII toOpco ~~evaluate~~LP ~~major agency actions having the potential to impact the environment~~ and ~~that~~AMH ~~may~~GP ~~require~~held ~~the~~100% ~~preparation~~ of ~~environmental~~such ~~assessments or environmental impact statements~~interests.

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, the occurrence of 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 analogous state 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 the oil and natural gas industry, particularly changes in the current Oklahoma forced pooling system, could have a material adverse effect on our business.

Our business is subject to various forms of extensive government regulation, including laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells we drill and the disposal of saltwater produced from such wells, among other matters. Changes in the legal and regulatory environment governing our industry, particularly any changes to Oklahoma statutory forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business and operating results.

We may have difficulty maintaining our historic levels of success in using the current Oklahoma forced pooling process to increase our interest in wells we propose to drill on our STACK acreage due to changes in third-party interest owners’ ability or desire to participate in our wells or possible future regulatory changes.

In the past we have used, and we expect to continue to use, the Oklahoma “forced pooling” process to increase our working interest in drilling units for wells we propose to drill as operator on our STACK acreage, which could lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well. In recent years, the collective working interest of third party owners of mineral rights in our drilling units who have elected to participate in our wells has been relatively low, which we believe could largely be attributed to the absence of available capital following the substantial oil and gas price downturns that commenced in late 2014. Due to the increased interest in the STACK as an economic oil and gas play in the current price and cost environment and the resultant consolidation of acreage in producers with greater access to capital, we believe that third party interest holders may be more likely to bear their share of the costs of the proposed future wells we propose to drill on our acreage. Thus, our ability to use Oklahoma forced pooling procedures to increase our working interest in proposed wells may be more difficult to accomplish. In addition, future changes in laws and regulations in Oklahoma affecting the forced pooling process could result in changes in economics and the level of participation in drilling by third party interest owners and adversely affect our ability to increase our interest in wells that we propose.

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

~~The adoption of derivatives legislation and regulations by the U~~Item 6.S. ~~Congress~~Selected ~~related~~Financial ~~to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.~~ Data

~~Title~~The ~~VII~~following ofinformation ~~the~~has ~~Dodd-Frank~~been ~~Act~~derived ~~establishes~~from federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our ~~exposure~~audited toconsolidated ~~price~~financial ~~volatility through the OTC market~~statements. ~~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 natural 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 has 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.



	Successor			Predecessor
	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31,
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			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

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