As filed with the Securities and Exchange Commission on April 6, 2018

Registration No. 333-223033

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Alta Mesa Resources, Inc.

(Exact Name of Registrant as Specified in its Charter)

15021 Katy Freeway, Suite 400

Houston, Texas 77094

(281) 530-0991

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of registrant’s principal executive offices)

Harlan H. Chappelle

Chief Executive Officer

Alta Mesa Resources, Inc.

15021 Katy Freeway, Suite 400

Houston, Texas 77094

(281) 530-0991

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:

Bill Nelson

Haynes and Boone, LLP

1221 McKinney, Ste 2100

Houston, Texas 77010

(713) 547-2084

Approximate date of commencement of proposed sale to the public: From time to time after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ☒

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

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):

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 7(a)(2)(B of the Securities Act.  ☐

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act, or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission acting pursuant to said Section 8(a), may determine.

The information contained in this prospectus is not complete and may be changed. No securities may be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, dated April 6, 2018

Preliminary Prospectus

ALTA MESA RESOURCES, INC.

34,500,000 Shares of Class A Common Stock Issuable upon Exercise of

Outstanding Public Warrants

341,740,095 Shares of Class A Common Stock

This prospectus relates to the issuance by Alta Mesa Resources, Inc., a Delaware corporation (the “Company,” “we,” “our” or “us”) of 34,500,000 shares of our Class A Common Stock, par value $0.0001 per share (the “Class A Common Stock”), upon the exercise of warrants (the “Public Warrants”) originally sold as part of units, consisting of one share of Class A Common Stock and one-third of one Public Warrant, in our initial public offering (our “IPO”). Each Public Warrant entitles the holder to purchase one share of Class A Common Stock at an exercise price of $11.50 per share. We will receive the proceeds from the exercise of the Public Warrants, but not from the sale of the underlying shares of Class A Common Stock.

This prospectus also relates to the resale of 341,740,095 shares of Class A Common Stock by the selling stockholders named in this prospectus or their permitted transferees. The shares of Class A Common Stock being offered by the selling stockholders consist of (i) 213,402,398 shares of Class A Common Stock that have been or may be issued by us from time to time to certain members of SRII Opco, LP, a Delaware limited partnership (“SRII Opco”), who own common units representing limited partner interests (the “SRII Opco Common Units”) in SRII Opco, upon the redemption or exchange by such members of their SRII Opco Common Units for shares of Class A Common Stock pursuant to the limited partnership agreement of SRII Opco, (ii) up to 59,871,031 shares of Class A Common Stock that may be issued to the contributors pursuant to those certain Contribution Agreements, dated August 16, 2017, described herein (the “Contribution Agreements”) if the earn-out consideration described therein is issued to the contributors thereunder (the “Earn-Out Shares”), (iii) 40,000,000 shares of Class A Common Stock to Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”) pursuant to the terms of that certain Forward Purchase Agreement, dated as of March 17, 2017 (the “Forward Purchase Agreement”), (iv) 15,133,333 shares of Class A Common Stock underlying warrants (the “Private Placements Warrants”) originally sold pursuant to that certain Private Placement Warrant Purchase Agreement, dated as of March 23, 2017 (the “Warrant Purchase Agreement”), to Silver Run Sponsor II, LLC (the “Sponsor”), and (v) 13,333,333 shares of Class A Common Stock underlying warrants (the “Forward Purchase Warrants”) originally sold to Fund VI Holdings pursuant to the terms of the Forward Purchase Agreement.

The selling stockholders may offer, sell or distribute all or a portion of their shares of Class A Common Stock publicly or through private transactions at prevailing market prices or at negotiated prices. Although we will receive the exercise price of the Private Placement Warrants and the Forward Purchase Warrants if those warrants are not exercised on a cashless basis, we will not receive any of the proceeds from the sale of the shares of Class A Common Stock owned by the selling stockholders. We will bear all costs, expenses and fees in connection with the registration of these shares of Class A Common Stock, including with regard to compliance with state securities or “blue sky” laws. The selling stockholders will bear all commissions and discounts, if any, attributable to their sale of shares of Class  A Common Stock. See “Plan of Distribution” beginning on page 167 of this prospectus.

The Class A Common Stock and Public Warrants are quoted on The NASDAQ Capital Market (“NASDAQ”) under the symbols “AMR” and “AMRWW,” respectively. On April 5, 2018, the closing prices of our Class A Common Stock and Public Warrants were $7.30 and $1.50, respectively. On April 5, 2018, we had 169,371,730 shares of Class A Common Stock and 34,500,000 Public Warrants issued and outstanding.

We are an “emerging growth company” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and are subject to reduced public company reporting requirements. This prospectus complies with the requirements that apply to an issuer that is an emerging growth company.

INVESTING IN THESE SECURITIES INVOLVES CERTAIN RISKS. SEE “RISK FACTORS” ON PAGE 10.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is             , 2018

TABLE OF CONTENTS

You should rely only on the information contained in this prospectus, any prospectus supplement or in any free writing prospectus we may authorize to be delivered or made available to you. We have not, and the selling stockholders have not, authorized anyone to provide you with different information. We and the selling stockholders are not offering to sell, or seeking offers to buy, shares of our Class A Common Stock in jurisdictions where offers and sales are not permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of shares of our Class A Common Stock.

INDUSTRY AND MARKET DATA

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the selling stockholders have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

TRADEMARKS AND TRADE NAMES

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks,

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service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

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GLOSSARY

Unless the context otherwise requires, references in this prospectus to:

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For additional defined terms commonly used in the oil and natural gas industry and used in this prospectus, please see “Glossary of Oil and Natural Gas Terms” set forth in Exhibit A.

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RISK FACTORS

Investing in our securities involves a high degree of risk. You should consider carefully the risks and uncertainties described below, together with all of the other information in this prospectus, including our consolidated financial statements and related notes, before deciding whether to purchase any of our securities. Any of these risks may have a material adverse effect on our business, financial condition, results of operations and cash flows and our prospects could be harmed. In that event, the price of our securities could decline and you could lose part or all of your investment.

Risks Related to Our Securities and Capital Structure

Our only significant asset is the ownership of the general partner interest and a 44.2% limited partner interest in SRII Opco, and such ownership may not be sufficient to enable us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations, including under the Tax Receivable Agreement.

We have no direct operations and no significant assets other than the ownership of the general partner interest and a 44.2% limited partner interest in SRII Opco. We will depend on SRII Opco and its subsidiaries, including Alta Mesa and Kingfisher, for distributions, loans and other payments to generate the funds necessary to meet our financial obligations or to pay any dividends with respect to our Class A Common Stock. Subject to certain restrictions, SRII Opco generally is required to (i) make pro rata distributions to its partners, including us, in an amount at least sufficient to allow us to pay our taxes and (ii) reimburse us for certain corporate and other overhead expenses. However, legal and contractual restrictions in agreements governing future indebtedness of SRII Opco and its subsidiaries, including Alta Mesa and Kingfisher, as well as the financial condition and operating requirements of Alta Mesa and Kingfisher may limit our ability to obtain cash from SRII Opco. The earnings from, or other available assets of, SRII Opco and its subsidiaries, including Alta Mesa and Kingfisher, may not be sufficient to enable us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations. SRII Opco will be treated as a partnership for U.S. federal income tax purposes and, as such, will not be subject to any entity-level U.S. federal income tax. Instead, taxable income will be allocated to holders of its SRII Opco Common Units, including us. As a result, we generally will incur income taxes on our allocable share of any net taxable income of SRII Opco. Under the terms of the agreement of limited partnership of SRII Opco (the “SRII Opco LPA”), SRII Opco is obligated to make tax distributions to holders of its SRII Opco Common Units, including us, except to the extent such distributions would render SRII Opco insolvent or are otherwise prohibited by law or any of our current or future debt agreements. In addition to tax expenses, we will also incur expenses related to our operations, our interests in SRII Opco and related party agreements, including payment obligations under the Tax Receivable Agreement, and expenses and costs of being a public company, all of which could be significant. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.” To the extent that we need funds and SRII Opco or any of its subsidiaries is restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition, including our ability to pay our income taxes when due.

We may be required to take write-downs or write-offs, restructuring and impairment or other charges that could have a significant negative effect on our financial condition, results of operations and stock price, which could cause you to lose some or all of your investment.

Although we have conducted due diligence on Alta Mesa and Kingfisher, we cannot assure you that this diligence revealed all material issues that may be present in the businesses of Alta Mesa or Kingfisher, that it would be possible to uncover all material issues through a customary amount of due diligence, or that factors outside of our control will not later arise. As a result, we may be forced to later write-down or write-off assets, restructure our operations, or incur impairment or other charges that could result in losses. Even if our due diligence successfully identifies certain risks, unexpected risks may arise and previously known risks may materialize in a manner not consistent with our preliminary risk analysis. Even though these charges may be non-

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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 cause us to be unable to obtain future financing on favorable terms or at all.

The unaudited pro forma condensed consolidated combined financial information included in this prospectus may not be indicative of what our actual financial position or results of operations would have been.

The unaudited pro forma condensed consolidated combined financial information for the Company following the Business Combination in this prospectus is presented for illustrative purposes only and is not necessarily indicative of what our actual financial position or results of operations would have been had the Business Combination been completed on the dates indicated. See “Unaudited Pro Forma Condensed Consolidated Combined Financial Information of the Company” in the financial statements included elsewhere in this prospectus (see “Index to Financial Statements”).

If the Business Combination’s benefits do not meet the expectations of investors, stockholders or financial analysts, the market price of our securities may decline.

If the benefits of the Business Combination do not meet the expectations of investors or securities analysts, the market price of our securities may decline. The market values of our securities may vary significantly from their prices on the date the Contribution Agreements were executed or the date of this prospectus.

In addition, fluctuations in the price of our securities could contribute to the loss of all or part of your investment. Prior to the Business Combination, trading in the shares of our Class A Common Stock had not been active. Accordingly, the valuation ascribed to Alta Mesa, Kingfisher and our Class A Common Stock in the Business Combination may not be indicative of the price that will prevail in the trading market following the Business Combination. If an active market for our securities develops and continues, the trading price of our securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your investment in our securities and our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a further decline.

Factors affecting the trading price of our securities may include:

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Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general and NASDAQ have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of our securities, may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to us could depress our stock price regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.

If securities or industry analysts do not publish or cease publishing research or reports about us, our business, or our market, or if they change their recommendations regarding our securities adversely, the price and trading volume of our securities could decline.

The trading market for our securities will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market, or our competitors. Securities and industry analysts do not currently, and may never, publish research on us. If no securities or industry analysts commence coverage of us, our stock price and trading volume would likely be negatively impacted. If any of the analysts who may cover us change their recommendation regarding our securities adversely, or provide more favorable relative recommendations about our competitors, the price of our securities would likely decline. If any analyst who may cover us were to cease coverage of us or fail to regularly publish reports on us, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.

There is no guarantee that the Public Warrants will be in the money at a time when they are exercisable, and they may expire worthless; the terms of our Public Warrants may be amended without the consent of all holders.

The exercise price for our Public Warrants is $11.50 per share. There is no guarantee that the Public Warrants will be in the money at a time when they are exercisable, and as such, the Public Warrants may expire worthless.

In addition, the warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and us provides that the terms of the Public Warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least 50% of the then outstanding Public Warrants to make any change that adversely affects the interests of the registered holders. Accordingly, we may amend the terms of the Public Warrants in a manner adverse to a holder if holders of at least 50% of the then outstanding Public Warrants approve of such amendment. Although our ability to amend the terms of the Public Warrants with the consent of at least 50% of the then outstanding Public Warrants is unlimited, examples of such amendments could be amendments to, among other things, increase the exercise price of the Public Warrants, shorten the exercise period or decrease the number of shares of our Class A Common Stock purchasable upon exercise of a Public Warrant.

We may redeem the Public Warrants prior to their exercise at a time that is disadvantageous to holders, thereby making their Public Warrants worthless.

We have the ability to redeem the outstanding Public Warrants at any time after they become exercisable and prior to their expiration at a price of $0.01 per warrant, provided that (i) the last reported sale price of our

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Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within the 30 trading-day period ending on the third business day before we send the notice of such redemption and (ii) on the date we give notice of redemption and during the entire period thereafter until the time the Public Warrants are redeemed, there is an effective registration statement under the Securities Act covering the shares of our Class A Common Stock issuable upon exercise of the Public Warrants and a current prospectus relating to them is available or we have elected to require the exercise of the Public Warrants on a cashless basis. Redemption of the outstanding Public Warrants could force holders of Public Warrants:

Anti-takeover provisions contained in our Charter and bylaws (the “Bylaws”), as well as provisions of Delaware law, could impair a takeover attempt.

Our Charter and Bylaws contain provisions that could have the effect of delaying or preventing changes in control or changes in our management without the consent of our board of directors. These provisions include:

These provisions, alone or together, could delay hostile takeovers and changes in control of us or changes in our board of directors and management.

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As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law (the “DGCL”), which prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our outstanding voting common stock. Any provision of our Charter or Bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.

A significant portion of our total outstanding shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our Class A Common Stock to drop significantly, even if our business is doing well.

Sales of a substantial number of shares of Class A Common Stock in the public market could occur at any time. These sales, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of our Class A Common Stock. The holders of our founder shares, which include our Sponsor and independent directors, and Fund VI Holdings own approximately 39% of our Class A Common Stock. Pursuant to the terms of a letter agreement entered into at the time of the IPO, the founder shares (which were converted into shares of Class A Common Stock at the Closing) may not be transferred until the earlier to occur of (i) one year after the Closing or (ii) the date on which we complete a liquidation, merger, stock exchange or other similar transaction that results in all of our public stockholders having the right to exchange their shares of Class A Common Stock for cash, securities or other property. Notwithstanding the foregoing, if the last sale price of our Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions) for any 20 trading days within any 30-trading day period commencing at least 150 days after the Closing, the shares of Class A Common Stock into which the founder shares convert will be released from these transfer restrictions.

Additionally, 90 days after Closing, the Kingfisher Contributor will have the ability to redeem or exchange up to 39,000,000 SRII Opco Common Units for shares of Class A Common Stock on a one-to-one basis. The Alta Mesa Contributor and the Riverstone Contributor will also have this redemption or exchange right with respect to all of their respective SRII Opco Common Units 180 days after Closing. If the Contributors redeem or exchange all of their SRII Opco Common Units for shares of Class A Common Stock, they will collectively own 55.8% of our Class A Common Stock.

In connection with the closing of our IPO, we entered into a registration rights agreement with our Sponsor and certain of our directors providing for registration rights to such parties. In addition, in connection with the Closing, we entered into a registration rights agreement with Fund VI Holdings and the Contributors, pursuant to which we are required to file the registration statement of which this prospectus is a part registering the shares of Class A Common Stock held by them for resale within 30 days following the Closing.

We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may claim, and the amounts of such payments could be significant.

In connection with the completion of the Business Combination, we entered into the Tax Receivable Agreement with the Alta Mesa Contributor and the Riverstone Contributor (the “Initial Limited Partners”) and SRII Opco. Pursuant to the Tax Receivable Agreement, we will be required to make cash payments to the Initial Limited Partners and their permitted transferees (together, the “TRA Holders”) equal to 85% of the amount of tax benefits, if any, that we actually realize (or are deemed to realize in certain circumstances) in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for Class A Common Stock (or, under certain circumstances, cash) pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by Kingfisher or otherwise used in our Midstream Business, and

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(ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings. The amount of the cash payments that we may be required to make under the Tax Receivable Agreement could be significant and is dependent upon significant future events and assumptions, including the timing of the exchanges of SRII Opco Common Units, the price of our Class A Common Stock at the time of each exchange, the extent to which such exchanges are taxable transactions and the amount of the exchanging TRA Holder’s tax basis in its SRII Opco Common Units at the time of the relevant exchange. The amount of such cash payments is also based on assumptions as to the amount and timing of taxable income we generate in the future, the U.S. federal income tax rate then applicable and the portion of our payments under the Tax Receivable Agreement that constitute interest or give rise to depreciable or amortizable tax basis. Moreover, payments under the Tax Receivable Agreement will be based on the tax reporting positions that we determine, which tax reporting positions are subject to challenge by taxing authorities. We will be dependent on distributions from SRII Opco to make payments under the Tax Receivable Agreement, and we cannot guarantee that such distributions will be made in sufficient amounts or at the times needed to enable us to make our required payments under the Tax Receivable Agreement, or at all. Any payments made by us to the TRA Holders under the Tax Receivable Agreement will generally reduce the amount of overall cash flow that might have otherwise been available to us. To the extent that we are unable to make timely payments under the Tax Receivable Agreement for any reason, the unpaid amounts will be deferred and will accrue interest until paid by us. Nonpayment for a specified period may constitute a breach of a material obligation under the Tax Receivable Agreement, and therefore, may accelerate payments due under the Tax Receivable Agreement. The payments under the Tax Receivable Agreement are also not conditioned upon the TRA Holders maintaining a continued ownership interest in SRII Opco or us. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” for a discussion of the Tax Receivable Agreement and the related likely benefits to be realized by us and the TRA Holders.

We will not be reimbursed for any payments made to TRA Holders under the Tax Receivable Agreement in the event that any tax benefits are disallowed.

We will not be reimbursed for any cash payments previously made to the TRA Holders pursuant to the Tax Receivable Agreement if any tax benefits initially claimed by us are subsequently challenged by a taxing authority and are ultimately disallowed. Instead, any excess cash payments made by us to a TRA Holder will be netted against any future cash payments that we might otherwise be required to make under the terms of the Tax Receivable Agreement. However, a challenge to any tax benefits initially claimed by us may not arise for a number of years following the initial time of such payment or, even if challenged early, such excess cash payment may be greater than the amount of future cash payments that we might otherwise be required to make under the terms of the Tax Receivable Agreement and, as a result, there might not be future cash payments from which to net against. The applicable U.S. federal income tax rules are complex and factual in nature, and there can be no assurance that the Internal Revenue Service (the “IRS”) or a court will not disagree with our tax reporting positions. As a result, it is possible that we could make cash payments under the Tax Receivable Agreement that are substantially greater than our actual cash tax savings. See “Certain Relationships and Related Party Transactions — Tax Receivable Agreement” for a discussion of the Tax Receivable Agreement and the related likely benefits to be realized by us and the TRA Holders.

Certain of the TRA Holders have substantial control over us, and their interests, along with the interests of other TRA Holders, in our business may conflict with yours.

The TRA Holders may receive payments from us under the Tax Receivable Agreement upon any redemption or exchange of their SRII Opco Common Units, including the issuance of shares of our Class A Common Stock upon any such redemption or exchange. As a result, the interests of the TRA Holders may conflict with the interests of holders of our Class A Common Stock. For example, the TRA Holders may have different tax positions from us which could influence their decisions regarding whether and when to dispose of assets, whether and when to incur new or refinance existing indebtedness, especially in light of the existence of

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the Tax Receivable Agreement, and whether and when we should terminate the Tax Receivable Agreement and accelerate our obligations thereunder. In addition, the structuring of future transactions may take into consideration tax or other considerations of TRA Holders even in situations where no similar considerations are relevant to us. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” for a discussion of the Tax Receivable Agreement and the related likely benefits to be realized by us and the TRA Holders.

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

The Tax Receivable Agreement provides that if we breach any of our material obligations under the Tax Receivable Agreement or if, at any time, we elect an early termination of the Tax Receivable Agreement, then the Tax Receivable Agreement will terminate and our obligations, or our successor’s obligations, to make payments under the Tax Receivable Agreement would accelerate and become immediately due and payable. The amount due and payable in those circumstances is determined based on certain assumptions, including an assumption that we would have sufficient taxable income to fully utilize all potential future tax benefits that are subject to the Tax Receivable Agreement. We may need to incur debt to finance payments under the Tax Receivable Agreement to the extent our cash resources are insufficient to meet our obligations under the Tax Receivable Agreement as a result of timing discrepancies or otherwise.

As a result of the foregoing, (i) we could be required to make cash payments to the TRA Holders that are greater than the specified percentage of the actual benefits we ultimately realize in respect of the tax benefits that are subject to the Tax Receivable Agreement, and (ii) we would be required to make a cash payment equal to the present value of the anticipated future tax benefits that are the subject of the Tax Receivable Agreement, which payment may be made significantly in advance of the actual realization, if any, of such future tax benefits. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combination, or other changes of control due to the additional transaction costs a potential acquirer may attribute to satisfying such obligations. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

The recently passed comprehensive tax reform bill could adversely affect our business and financial condition.

On December 22, 2017, President Trump signed into law the final version of the tax reform bill that significantly reforms the Internal Revenue Code of 1986, as amended (the “Code”). The tax reform bill, among other things, contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate, a partial limitation on the deductibility of business interest expense, a limitation of the deduction for net operating loss carryforwards to 80% of current year taxable income, an indefinite net operating loss carryforward, immediate deductions for certain new investments instead of deductions for depreciation expense over time, and the modification or repeal of many business deductions and credits. We continue to examine the impact this tax reform legislation may have on our business. Notwithstanding the reduction in the corporate income tax rate, the overall impact of the tax reform bill is uncertain and our business and financial condition could be adversely affected. The impact of this tax reform on holders of our Class A Common Stock is also uncertain and could be adverse.

The JOBS Act permits “emerging growth companies” like us to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.

We qualify as an “emerging growth company” as defined in the JOBS Act. As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies for as long as we continue to be an emerging growth company, including (i) the

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exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. As a result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year (a) following March 29, 2022, the fifth anniversary of our IPO, (b) in which we have total annual gross revenue of at least $1.07 billion or (c) in which we are deemed to be a large accelerated filer, which means the market value of our Class A Common Stock that is held by non-affiliates exceeds $700 million as of the last business day of our prior second fiscal quarter, and (ii) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards provided in Section 7(a)(2)(B) of the Securities Act. An emerging growth company can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies, but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.

We cannot predict if investors will find our Class A Common Stock less attractive because we will rely on these exemptions. If some investors find our Class A Common Stock less attractive as a result, there may be a less active trading market for our Class A Common Stock and our stock price may be more volatile.

Non-U.S. holders may be subject to U.S. income tax with respect to gain on disposition of their Class A Common Stock and Public Warrants.

We believe that we are a United States real property holding corporation (a “USRPHC”). As a result, Non-U.S. holders (defined below in the section entitled “Material U.S. Federal Income Tax Consequences to Non-U.S. Holders”) that own (or are treated as owning under constructive ownership rules) more than a specified amount of our Class A Common Stock or Public Warrants during a specified time period may be subject to U.S. federal income tax on a sale, exchange, or other disposition of such Class A Common Stock or Public Warrants and may be required to file a U.S. federal income tax return. If you are a Non-U.S. holder, we urge you to consult your tax advisors regarding the tax consequences of such treatment.

Risks Related to our E&P Business

Oil and natural gas prices are highly volatile and depressed prices can significantly and adversely affect our financial condition and results of operations.

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 materially and adversely affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flows.

Historically, world-wide oil and natural gas prices and markets have been subject to significant change and may continue to change in the future. In particular, the prices of oil and natural gas declined dramatically after

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the second half of 2014. Based on daily settlements of monthly contracts traded on the NYMEX, the average price for the twelve months ended December 31, 2016 for a barrel of oil ranged from a high of $52.17 in December 2016 to a low of $30.62 in February 2016, and the price for an 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 NYMEX, the average price for the twelve months ended December 31, 2017 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 price 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.

Continued fluctuations in oil and natural gas prices, price declines 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 per barrel in 2016 and $46.22 per barrel in 2015. Because the oil price we are required to use to estimate our future net cash flows is the average first day of the month price over the twelve months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash 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 reversible at a later date, even if prices increase.

Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

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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. 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 Alta Mesa’s Eighth A&R credit facility (as defined below) 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:

If our revenues or the borrowing base under Alta Mesa’s Eighth A&R 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. Alta Mesa’s Eighth A&R 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 Alta Mesa’s Eighth A&R credit facility is not sufficient to meet its capital requirements, the failure to obtain additional financing could result in a curtailment of its operations relating to development of its prospects, which in turn could lead to a decline in our reserves and production and could adversely affect Alta Mesa’s business, results of operations, financial conditions and ability to make payments on its outstanding indebtedness.

External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under Alta Mesa’s Eighth A&R 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 may be forced to limit or defer 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.

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

Our operations 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

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of these new technologies may not prove successful and could result in significant cost overruns or delays or reduction in production, and in extreme cases, the abandonment of a well. The difficulties we face drilling horizontal wells include:

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

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 Alta Mesa’s Eighth A&R credit facility, which is revised periodically, may be reduced, which would negatively impact its borrowing ability.

Lower oil and natural gas 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

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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 Alta Mesa’s Eighth A&R 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.

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. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

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. 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 natural gas liquids 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. 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.”

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.

Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing acreage.

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

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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.

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

Accounting rules require 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 write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We recognized impairment expense during 2017 and 2016 of $30.3 million and $16.3 million, respectively, as a result of lower forecasted commodity prices. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

In the future, we may recognize significant impairments of proved oil and gas properties and impairments of unproved oil and gas properties as a result of lower forecasted commodity prices and changes to our drilling plans. At December 31, 2017, our estimate of undiscounted future cash flows attributable to our proved oil and natural gas properties with a net book value of approximately $762.2 million indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if oil and natural gas prices decline by 10%. We estimate that, if the oil and natural gas prices decline by 10%, this depletion group becomes impaired in a future period and we could recognize non-cash impairments in that period of approximately $2.7 million. It is also reasonably foreseeable that prolonged low or further declines in commodity prices, further changes to our drilling plans in response to lower prices or increases in drilling or operating costs could result in other additional impairments.

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.

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates 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 reserves is complex, requiring significant decisions and assumptions in

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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 12 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.

The present value of future net revenues from our proved reserves or “PV-10” will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves.

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 12-month unweighted arithmetic average of the closing prices on the first day of each month for the preceding 12 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:

The timing of both our production and our incurrence of expenses in connection with the development 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. 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.

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

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.

Approximately 68% of Alta Mesa’s total estimated SEC net proved reserves at December 31, 2017 were PUDs requiring substantial capital expenditures and may ultimately prove to be less than estimated.

Recovery of PUDs requires significant capital expenditures and successful drilling operations. At December 31, 2017, approximately 125.1 MMBOE of Alta Mesa’s total estimated SEC net proved reserves were

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undeveloped. The reserve data included in the 2017 Reserve Report assumes that substantial capital expenditures will be made to develop non-producing reserves. The calculation of Alta Mesa’s estimated net proved reserves as of December 31, 2017 assumed that it would spend a total of $978.4 million over a five-year period, including plugging and abandonment costs, to develop its estimated PUDs, including an estimated $382.7 million during 2018. Although cost and reserve estimates attributable to Alta Mesa’s oil and natural gas reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate. We may need to raise additional capital in order to develop Alta Mesa’s estimated PUDs over the next five years and we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Additionally, declines in commodity prices will reduce the future net revenues of Alta Mesa’s estimated PUDs and may result in some projects becoming uneconomical. As a result of lower oil and natural gas prices, Alta Mesa may reduce the budgeted capital expenditures for the development of undeveloped reserves. These delays in the development of reserves could force Alta Mesa to reclassify certain of our proved reserves as unproved reserves. Further, Alta Mesa’s drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, results of operations and future cash flows.

As part of Alta Mesa’s exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.

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:

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:

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We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and natural gas liquids we produce.

The availability of a ready market for any oil, natural gas and natural gas liquids 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.

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

The primary focus of our business strategy is to increase production levels by drilling wells. Although we were successful in drilling in the past, we cannot provide assurance that we will continue to maintain production levels 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 uncertain, and it is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.

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.

We have made and may in the future make 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 purchase of the business or property. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. In the course of our due diligence, we may not inspect every aspect of a business we acquire and we cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when an inspection is made.

The success of any completed 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 require a disproportionate amount of our 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.

In addition, Alta Mesa’s Eighth A&R credit facility and the indenture governing its 7.875% senior unsecured notes due December 15, 2024 (the “2024 Notes”) impose certain limitations on its ability to enter into mergers or combination transactions. Alta Mesa’s Eighth A&R credit facility and the indenture governing its 2024 Notes also limit Alta Mesa’s ability to incur certain indebtedness, which could indirectly limit its ability to engage in acquisitions of businesses.

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Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations.

Our business activities are subject to operational risks, including:

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 processing facilities. These alternative facilities may not be available, which could cause us to shut in our natural gas production. Further, such alternative facilities could be more expensive than the facilities we currently use.

Any of these 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 the 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 available insurance is excessive relative to the perceived risks presented. Losses could therefore 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 our business activities, financial condition and results of operations.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

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 natural gas production.

Our decisions to develop or purchase prospects or properties will depend in part 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. 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.”

Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. In addition, our cost of drilling, completing and operating wells is often uncertain.

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Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

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 have hedged approximately 35% of our total forecasted PDP production through 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. Alta Mesa’s Eighth A&R credit facility limits the amount of hedges that Alta Mesa can place on our PDP production. If we experience a sustained material interruption in our production, we 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 liquidity. 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 ability to 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 future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity price changes.

Our policy has been to hedge a significant portion of our near-term estimated production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our 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, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price fluctuations.

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Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if 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 periods of falling commodity prices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of hydrocarbons, which could adversely affect the results of our drilling operations.

Even 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.

We often gather 2-D and 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 2-D and 3-D seismic data without having an opportunity to attempt to benefit from those expenditures.

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.

Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Our competitors may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, the oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. Our inability to compete effectively with our competitors could have a material adverse impact on our business activities, financial condition and results of operations.

We may not be able to keep pace with technological developments in the oil and natural gas industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies,

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we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Deficiencies of title to our leased interests could significantly affect our financial condition.

If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is the practice of our management, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.

Prior 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.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water 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.

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

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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:

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.

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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.

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

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the 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 to price volatility through the OTC market. 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

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certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives transactions. The “Volcker Rule” provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

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

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

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

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and natural gas. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our financial condition could be adversely affected.

Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. Various proposals and proceedings that might affect the petroleum industry are pending before the U.S. Congress (“Congress”), the Federal Energy Regulatory Commission, (“FERC”), various state legislatures and the courts. The industry historically has been heavily regulated and we cannot provide assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.

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

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

Under the Energy Policy Act of 2005 (“EPAct”), FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the ability to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC under the NGA. Under the Commodity Exchange Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, FERC, or the CFTC from time to time. Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability.

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

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and may continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the CAA that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential sources of significant, 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, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce

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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 nationally 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 into force in November 2016. The United States is one of more than 120 nations having ratified or otherwise consented to the agreement; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions. With the change in presidential administration, the ongoing commitment of the United States to the Paris Agreement is unclear. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement, if it chooses to do so, are unclear at this time.

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

Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities, our costs of operations potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by such climate effects, or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.

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

Hydraulic fracturing is an essential and common practice used to stimulate production of oil and natural gas from dense subsurface rock formations, such as shales. We routinely apply hydraulic fracturing techniques in many of our operations to stimulate production of hydrocarbons, particularly natural gas. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation to fracture the surrounding rock and stimulate production.

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Hydraulic fracturing (other than that using diesel) is currently generally exempt from regulation under the SDWA’s Underground Injection Control (“UIC”) program and is typically regulated by state oil and natural gas commissions or similar agencies. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In 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, which has been challenged in court. However, the BLM is in the process of rescinding the 2015 rule.

Additionally, in 2014, the EPA published an advanced notice of public rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixture used in hydraulic fracturing. From time to time, Congress has introduced, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of chemicals used in the fracturing process.

In addition, some states, including Oklahoma where we operate, have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in 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 hydraulic fracturing activities and thereby affect our production and increase our cost of doing 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.

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

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

One such concern relates to recent seismic events near underground injection wells used for the disposal of produced water resulting from oil and natural gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including

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Oklahoma, where we operate. In response to these concerns regarding induced seismicity, regulators in some states, including Oklahoma, have imposed, and other states are considering imposing, additional requirements in the permitting of produced water injection wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on injection wells in proximity to faults and also, from time to time, developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend injection well operations. The Oklahoma Corporation Commission (“OCC”) has implemented the National Academy of Science’s “traffic light system,” in determining whether new injection wells should be permitted, permitted only with special restrictions, or not permitted at all. In addition, the OCC has established rules requiring operators of certain produced water injection wells in seismically-active areas, or Areas of Interest, within the Arbuckle formation of the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for injection wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal operations in an attempt to mitigate the occurrence of such incidents. More recently, in December 2016, the OCC Oil and Gas Conservation Division and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In addition, in February 2017, the OCC’s Oil and Gas Conservation District issued an order limiting future increases in the volume of oil and natural gas wastewater injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state.

Also, ongoing lawsuits allege that injection well disposal operations have caused damage to neighboring properties or otherwise violated state and federal rules governing waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and natural 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 well locations or otherwise or by requiring us to shut down injection wells, could significantly increase our costs to manage and dispose of this produced water, which could have a material adverse effect on our financial condition and results of operations.

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

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

Additionally, the U.S. Fish and Wildlife Service (“FWS”) may designate new or increased critical habitat areas that it believes are necessary for survival of threatened or endangered species, which designation could

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

We could experience periods of higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in our area of operations. Higher costs could reduce our profitability, cash flow and ability to pursue our drilling program as planned.

Historically, our capital and operating costs typically rise during periods of sustained increasing oil, natural gas and natural gas liquid prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor, especially those required in horizontal drilling and completion. Since late 2014, oil and natural gas prices declined substantially resulting in decreased levels of drilling activity in the U.S. oil and natural gas industry, including in our area of operations. This led to significantly lower costs of some drilling and completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases in our area of operations, these lower cost levels may not be sustainable over long periods. Recently, there has been increased drilling activity in the STACK. As a result, such costs may rise thereby negatively impacting our profitability, cash flow and causing us to possibly reconfigure or reduce our drilling program.

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

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations. See “Our E&P Business — Environmental and Occupational Safety and Health Matters” and “Our E&P Business — Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.

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

We have limited control over properties which we do not operate or do not otherwise control operations. If we do not operate or otherwise control the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations, an operator’s financial difficulties, including as a result of price volatility or an operator’s breach of the applicable agreements could reduce our production and revenues. The

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success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.

Oil and gas exploration and production activities are complex and involve risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course of our business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

We depend on key personnel, the loss of any of whom could materially adversely affect future operations.

Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintain key-man life insurance with respect to any of our employees. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.

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

Our operations and drilling activity are concentrated in the STACK, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially 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 continue or complete our current and planned development activities could result in oil and gas production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our results of operations, liquidity and financial condition.

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

The marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling.

The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.

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Alta Mesa’s Eighth A&R credit facility and the indenture governing its 2024 Notes have restrictive covenants that could limit its growth, financial flexibility and its ability to engage in certain activities. Since Alta Mesa is our subsidiary, most of the effects of these debt facilities on Alta Mesa apply equally to us.

Alta Mesa’s Eighth A&R credit facility and the indenture governing its 2024 Notes have restrictive covenants that could limit its growth, financial flexibility and its ability to engage in activities that may be in Alta Mesa’s long-term best interests. Alta Mesa’s Eighth A&R credit facility and the indenture governing its 2024 Notes also contain covenants that, among other things, limit Alta Mesa’s ability to:

In addition, Alta Mesa’s Eighth A&R credit facility requires Alta Mesa to maintain certain financial ratios or to reduce Alta Mesa’s indebtedness if it is unable to comply with such ratios, which may limit Alta Mesa’s ability to obtain future financings to withstand a future downturn in its business or the economy in general or to otherwise conduct necessary corporate activities. Alta Mesa may also be prevented from taking advantage of business opportunities that arise because of these limitations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Alta Mesa — Senior Notes” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Alta Mesa — Eighth A&R credit facility.”

Alta Mesa’s failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of its indebtedness. If that occurs, Alta Mesa may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to Alta Mesa.

Any significant reduction in Alta Mesa’s borrowing base under its Eighth A&R credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact Alta Mesa’s ability to fund its operations, and Alta Mesa may not have sufficient funds to repay borrowings under its Eighth A&R credit facility if required as a result of a borrowing base redetermination.

Availability under Alta Mesa’s Eighth A&R credit facility is currently subject to a borrowing base of $350.0 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Alta Mesa — Eighth A&R credit facility.” The borrowing base is subject to scheduled semiannual and other elective unscheduled borrowing base redeterminations and is based on the value of Alta Mesa’s oil and natural gas reserves as determined by the lenders under its Eighth A&R credit facility and other factors deemed relevant by its lenders. Declines in prices for oil and natural gas may cause Alta Mesa’s banks to reduce the borrowing base under its Eighth A&R credit facility. Any significant reduction in Alta Mesa’s borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact its liquidity and its ability to fund its operations and, as a result, may have a material adverse effect on Alta Mesa’s financial condition, results of operations and cash flows. Further, if the outstanding borrowings under Alta Mesa’s Eighth A&R credit facility were to exceed the borrowing base as a result of any such redetermination, Alta Mesa would be required to repay

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the excess. Alta Mesa may not have sufficient funds to make such repayments. If Alta Mesa does not have sufficient funds and it is otherwise unable to negotiate renewals of its borrowings or arrange new financing, it may have to sell significant assets. Any such sale could have a material adverse effect on the business and financial results of Alta Mesa and us.

If Alta Mesa is unable to comply with the restrictions and covenants in its debt agreements, there could be a default under the terms of such agreements, which could result in an acceleration of repayment.

If Alta Mesa is unable to comply with the restrictions and covenants in its debt agreements, there could be a default under the terms of these agreements. Alta Mesa’s ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond its control. As a result, Alta Mesa cannot assure that it will be able to comply with these restrictions and covenants or meet such financial ratios and tests.

If Alta Mesa is unable to generate sufficient cash flow and is otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on its indebtedness, or if Alta Mesa otherwise fails to comply with the various covenants, including financial and operating covenants in the instruments governing its indebtedness (including covenants in its Eighth A&R credit facility or the indenture governing the 2024 Notes), Alta Mesa could be in default under the terms of the agreements governing such indebtedness. 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, together with accrued and unpaid interest, the lenders under its Eighth A&R credit facility could terminate their commitments to lend, cease making further loans and institute foreclosure proceedings against its assets, and it could be forced into bankruptcy or liquidation. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, Alta Mesa’s assets might not be sufficient to repay in full all of its outstanding indebtedness and it may be unable to find alternative financing. Even if Alta Mesa could obtain alternative financing, it might not be on terms that are favorable or acceptable to it. Additionally, Alta Mesa may not be able to amend its debt agreements or obtain needed waivers on satisfactory terms.

Alta Mesa’s borrowings under its Eighth A&R credit facility expose us to interest rate risk.

Alta Mesa’s earnings are exposed to interest rate risk associated with borrowings under its Eighth A&R credit facility. Alta Mesa’s Eighth A&R credit facility carries a floating interest rate based upon short-term interest rate indices. If interest rates increase, so will Alta Mesa’s interest costs, which may have a material adverse effect on its financial condition and results of operations. Alta Mesa may use interest rate hedges in an effort to mitigate this risk, but those efforts may not prove successful.

To service its indebtedness, Alta Mesa requires a significant amount of cash, and its ability to generate cash will depend on many factors beyond its control.

Alta Mesa’s ability to make payments on and to refinance its indebtedness and to fund planned capital expenditures depends in part on its ability to generate cash in the future. This ability is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond Alta Mesa’s control. Alta Mesa cannot provide assurance that it will generate sufficient cash flow from operations, that it will realize operating improvements on schedule or that future borrowings will be available to it in an amount sufficient to enable it to service and repay its indebtedness or to fund its other liquidity needs. If Alta Mesa is unable to satisfy its debt obligations, it may have to undertake alternative financing plans, such as:

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However, any alternative financing plans that it undertakes, if necessary, may not allow Alta Mesa to meet its debt obligations.

Alta Mesa cannot provide assurance that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to it or that additional financing could be obtained on acceptable terms. Alta Mesa’s inability to generate sufficient cash flows to satisfy its debt obligations, or to obtain alternative financing, could materially and adversely affect its and our business, financial condition, results of operations and prospects.

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have precipitated an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

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

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

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and communicate with our employees and third-party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to

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market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks 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 vulnerability to cyber-attacks.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data systems. If any such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax 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 exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, and (3) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and natural gas within the United States. 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 (1) the elimination of the deduction for U.S. production activities, (2) the provision for individual taxpayers to deduct 20% of their domestic qualified business income (which may provide some relief from the aforementioned item), (3) more stringent limitation on business interest deduction, (4) modification of net operating loss carryforward rules, and (5) changes to items excluded from the $1.0 million executive compensation deduction limitation. These changes are mostly effective beginning in the tax year 2018, and we have not yet calculated their effect on our forward-looking financials. The further passage of any legislation as a result of the above mentioned proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

Risks Related to our Midstream Business

We must continually compete for crude oil, natural gas and NGL supplies, and any decrease in supplies of such commodities could adversely affect our financial condition, results of operations or cash flows.

In order to maintain or increase throughput levels in our gathering system and asset utilization rates at our processing plant, we must continually contract for new product supplies. We may not be able to obtain additional contracts for crude oil, natural gas and NGL supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing supplies that are not committed to other systems and the level of drilling activity near our gathering system. If we are unable to maintain or increase the volumes on our system by accessing new supplies to offset the natural decline in reserves, our business and financial results could be adversely affected. In addition, our future growth will depend in part upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our current supplies.

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Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new crude oil and natural gas reserves. During 2016, we saw lower drilling activity due to low commodity prices. Although drilling activity improved during 2016 and 2017, we could see downward pressure on future drilling activity in the STACK play if commodity prices decline, which may result in lower volumes. Tax policy changes or additional regulatory restrictions on development could also have a negative impact on drilling activity, reducing supplies of product available to our system and assets. We have no control over producers and depend on them to maintain sufficient levels of drilling activity. A continued decrease in the level of drilling activity or a material decrease in production in our area of operation for a prolonged period, as a result of continued depressed commodity prices or otherwise, likely would adversely affect our financial condition, results of operations and cash flow.

Any decrease in the volumes that we gather, process, store or transport would adversely affect our financial condition, results of operations or cash flows.

Our financial performance depends to a large extent on the volumes of crude oil, natural gas and NGLs gathered, processed, stored and transported on our assets. Decreases in the volumes of crude oil, natural gas and NGLs we gather, process, store or transport would directly and adversely affect our financial condition, results of operations or cash flows. These volumes can be influenced by factors beyond our control, including:

The volumes of crude oil, natural gas and NGLs gathered, processed and transported on our assets also depend on the production from the region that supplies our systems. Supply of crude oil, natural gas and NGLs can be affected by many of the factors listed above, including commodity prices and weather. In order to maintain or increase throughput levels on our system, we must obtain new sources of crude oil, natural gas and NGLs. The primary factors affecting our ability to obtain non-dedicated sources of crude oil, natural gas, and NGLs include (i) the level of successful leasing, permitting and drilling activity in our areas of operation, (ii) our ability to compete for volumes from new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines. We have no control over the level of drilling activity in our area of operation, the amount of reserves associated with wells connected to our system or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, levels of reserves, availability of drilling rigs and other costs of production and equipment.

Construction of our Phase II assets subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations or cash flows.

We are engaged in the construction of our Phase II assets, including an expansion of our cryogenic processing plant, some of which will take a number of months before commercial operation. The construction of

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these Phase II assets is complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, complying with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of the Phase II assets could adversely affect our financial condition, results of operations or cash flows. The construction of pipelines and gathering and processing and storage facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and capital position could be adversely affected. This level of development activity requires significant effort from our management and technical personnel. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.

Our construction of new assets may be more expensive than anticipated and may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks that could adversely affect our financial condition, results of operations or cash flows.

The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control including potential protests or legal actions by interested third parties, and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase due to the successful construction of a particular project. For instance, if we expand a pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues promptly following completion of a project or at all. Moreover, we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our financial condition, results of operations or cash flows. In addition, the construction of additions to our existing gathering and processing assets will generally require us to obtain new rights-of-way and permits prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way or permits to connect new product supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.

Performance of our operations requires that we obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect our ability to initiate or continue operations at the affected location or facility and on our financial condition, results of operations and cash flows.

Additionally, in order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate. Certain approval procedures may require preparation of archaeological surveys, endangered species

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studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time required to prepare applications and to receive authorizations.

We typically do not obtain independent evaluations of hydrocarbon reserves; therefore, volumes we service in the future could be less than anticipated.

We typically do not obtain, on a regular basis, independent evaluations of hydrocarbon reserves connected to our gathering systems or that we otherwise service due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, other than reserve estimates with respect to our E&P Business, we do not have independent estimates of total reserves serviced by our assets or the anticipated life of such reserves. If the total reserves or estimated life of the reserves is less than we anticipate and we are unable to secure additional sources, then the volumes transported on our gathering systems or that we otherwise service in the future could be less than anticipated. A decline in the volumes could adversely affect our financial condition, results of operations or cash flows.

Restrictions in Kingfisher’s credit facility could adversely affect its financial condition, results of operations or cash flows. Since Kingfisher is our subsidiary, most of the effects of these debt facilities on Kingfisher apply equally to us.

Kingfisher is a party to a $200 million credit agreement that matures on August 8, 2021, with quarterly interest payments due on Base Rate loans. Kingfisher’s interest rates depend upon its consolidated leverage ratio and Kingfisher can elect to borrow on a Eurodollar Loan or Base Rate Loan basis. Both the Eurodollar Loan and Base Rate Loan margins are subject to minimum rates established by third-party institutions, such as, but not limited to the Federal Reserve. For example, if Kingfisher elects to borrow a Base Rate Loan, the interest rate would be 4.25%, plus the applicable margin pricing level. Currently, Kingfisher is at tier 2 of the pricing level resulting in an applicable margin of 2.0% for an effective annual interest rate of 6.25%. The terms of this credit agreement limit Kingfisher’s ability to, among other things:

The Kingfisher credit facility also contains covenants requiring it to maintain certain financial ratios. Kingfisher’s ability to meet those financial ratios and tests can be affected by events beyond its control, and Kingfisher cannot assure you that it will meet any such ratios and tests.

The provisions of the Kingfisher credit facility may affect its ability to obtain future financing and pursue attractive business opportunities and its flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the credit facility could result in a default or an event of default that could enable Kingfisher’s lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of Kingfisher’s debt is accelerated, its assets may be insufficient to repay such debt in full.

Our exposure to commodity price risk may change over time.

We generate substantially all of our revenues from our Midstream Business pursuant to fee-based contracts under which we are paid based on the volumes that we gather, process and transport, rather than the underlying

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value of the commodity, in order to minimize our exposure to commodity price risk. However, we are a party to fee-based contracts that have a small portion of percent-of-proceeds contractual mix, but the portion of percent-of-proceeds does not exceed 6.0% for any one contract. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of crude oil, natural gas and NGL prices could adversely affect our financial condition, results of operations or cash flows.

If third-party pipelines or other midstream facilities interconnected to our gathering, processing, storage or transportation systems become partially or fully unavailable, or if the volumes we gather, process, store or transport do not meet the quality requirements of the pipelines or facilities to which we connect, our gross profit and cash flow could be adversely affected.

Our gathering, processing, storage and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if our costs to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport or process product, or if the volumes we gather or transport do not meet the product quality requirements of such pipelines or facilities, our gross profit and cash flows could be adversely affected.

The midstream industry is highly competitive, and increased competitive pressure could adversely affect our financial condition, results of operations or cash flows.

We compete with similar midstream enterprises in our area of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Our competitors include large crude oil and natural gas companies that have greater financial resources and access to supplies of crude oil, natural gas and NGLs than us. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services we provide to our customers. Excess pipeline capacity in the region served by our intrastate pipelines could also increase competition and adversely impact our ability to renew or enter into new contracts with respect to our available capacity when existing contracts expire. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain or increase current revenues and cash flows could be adversely affected by the activities of our competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, storage and transportation services. All of these competitive pressures could adversely affect our financial condition, results of operations or cash flows.

If we do not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired midstream assets with our existing asset base, our future growth will be limited.

Our ability to grow depends, in part, on our ability to make midstream acquisitions that result in an increase in cash generated from operations. If we are unable to make accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or at all or (3) outbid by competitors, then our future growth will be limited.

From time to time, we may evaluate and seek to acquire midstream assets or businesses that we believe complement our existing business and related assets. We may acquire midstream assets or businesses that we

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plan to use in a manner materially different from its prior owner’s use. Any acquisition involves potential risks, including:

The assessment by our management of these risks is inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect our financial condition, results of operations and cash flows. If we consummate any future acquisition, our capitalization and results of operations may change significantly.

We may not be able to retain existing midstream customers or acquire new customers, which would reduce our revenues and limit our future profitability.

The renewal or replacement of our existing contracts with our midstream customers at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including competition from other midstream service providers and the price of, and demand for, crude oil, natural gas and NGLs in the markets we serve. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

If our midstream assets become subject to FERC regulation or federal, state or local regulations or policies change, our financial condition, results of operations and cash flows could be materially and adversely affected.

We believe that our gathering and transportation operations are exempt from regulation by FERC under the NGA. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts, or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by us are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGPA and the rules and regulations promulgated under those statutes. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows.

Unlike natural gas gathering under the NGA, there is no exemption for the gathering of crude oil or NGLs under the ICA. Whether a crude oil or NGL shipment is in interstate commerce under the ICA depends on the

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fixed and persistent intent of the shipper as to the crude oil’s or NGL’s final destination, absent a break in the interstate movement. We believe that the crude oil and NGL pipelines in our gathering system meet the traditional tests FERC has used to determine that a pipeline is not providing transportation service in interstate commerce subject to FERC ICA jurisdiction. However, the determination of the interstate or intrastate character of shipments on our crude oil and NGL pipelines depends on the shipper’s intentions and the transportation of the crude oil or NGLs outside of our system, and may change over time. If FERC were to consider the status of an individual facility and the character of a crude oil or NGL shipment, and determine that the shipment is in interstate commerce, the rates for, and terms and conditions of, transportation services provided by such facility would be subject to regulation by FERC under the ICA. Such FERC regulation could decrease revenue, increase operating costs, and, depending on the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.

If we fail to comply with all the applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, for instance, FERC has civil penalty authority to impose penalties for current violations of the NGA or NGPA of up to $1,213,503 per day for each violation. The maximum penalty authority established by statute has been and will continue to be adjusted periodically for inflation. FERC also has the power to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct.

Other state and local regulations also affect our business. We are subject to some ratable take and common purchaser statutes in the states where we operate. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and Oklahoma has adopted complaint-based or other limited economic regulation of natural gas gathering activities.

We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.

The pipelines we own and operate are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. PHMSA also recently proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.

Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the OCC could result in substantial expenditures for testing, repairs and replacement. If our pipelines fail to meet the safety standards mandated by the OCC or the DOT regulations, then we may be required to repair or replace sections of such pipelines or operate the pipelines at a reduced maximum allowable operating pressure, the cost of which cannot be estimated at this time.

Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a

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material adverse effect on our results of operations or financial position. Because certain of our operations are located around areas that may become more populated areas, such as the STACK play, we may incur expenses to mitigate noise, odor and light that may be emitted in our operations and expenses related to the appearance of our facilities. Municipal and other local or state regulations are imposing various obligations including, among other things, regulating the location of our facilities, imposing limitations on the noise levels of our facilities and requiring certain other improvements that increase the cost of our facilities. We are also subject to claims by neighboring landowners for nuisance related to the construction and operation of our facilities, which could subject us to damages for declines in neighboring property values due to our construction and operation of facilities.

In addition to the foregoing risks affecting our Midstream Business, many of the risks that apply to our E&P Business also apply to our Midstream Business.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, 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 prospectus, the words “could”, “should”, “will”, “play”, “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 this prospectus. 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:

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We caution you 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, 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, costs related to the Business Combination, 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 “Risk Factors” in this prospectus.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. Specifically, 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 prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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 prospectus.

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USE OF PROCEEDS

Issuance of Class A Common Stock Underlying Public Warrants

We will receive the proceeds from the exercise of Public Warrants, but not from the sale of the underlying shares of Class A Common Stock. Assuming the exercise of all of the Public Warrants at an exercise price of $11.50 per share, we expect to receive $396,750,000. We intend to use any proceeds for general corporate purposes.

Resale of Class A Common Stock by Selling Stockholders

We will not receive any of the proceeds from the sale of Class A Common Stock by the selling stockholders named herein. We will receive the proceeds from the exercise of Private Placement Warrants and the Forward Purchase Warrants, but not from the sale of the underlying shares of Class A Common Stock. Assuming the exercise of all of the Private Placement Warrants and the Forward Purchase Warrants at an exercise price of $11.50 per share (assuming no cashless exercise), we expect to receive $327,366,659. We intend to use any proceeds for general corporate purposes.

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DETERMINATION OF OFFERING PRICE

Issuance of Class A Common Stock Underlying Public Warrants

The offering price of the shares of Class A Common Stock underlying the Public Warrants offered hereby is determined by reference to the exercise price of the Public Warrants of $11.50 per share. The Public Warrants are listed on NASDAQ under the symbol “AMRWW.”

Resale of Class A Common Stock by Selling Stockholders

Our Class A Common Stock is listed on NASDAQ under the symbol “AMR.” The actual offering price by the selling stockholders of the shares of Class A Common Stock covered by this prospectus will be determined by prevailing market prices at the time of sale, by private transactions negotiated by the selling stockholders or as otherwise described in the section entitled “Plan of Distribution.”

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PRICE RANGE OF SECURITIES AND DIVIDENDS

Our Class A Common Stock and Public Warrants are currently listed on NASDAQ under the symbols “AMR” and “AMRWW,” respectively. Through February 9, 2018, our Class A Common Stock and Public Warrants were listed under the symbols “SRUN” and “SRUNW,” respectively.

The following table sets forth, for the calendar quarter indicated, the high and low sales prices per unit and share of Class A Common Stock as reported on NASDAQ, respectively, for the periods presented. Since warrants are not currently eligible to be exercised, there is no information presented for the warrants in the table below.

On April 5, 2018, the closing price of our Class A Common Stock and Public Warrants was $7.30 and $1.50, respectively. As of April 5, 2018, there were 169,371,730 shares of Class A Common Stock outstanding, held of record by 12 holders. In addition, 34,500,000 shares of Class A Common Stock are issuable upon exercise of the 34,500,000 Public Warrants, held of record by six holders. The number of record holders of our Class A Common Stock and Public Warrants does not include DTC participants or beneficial owners holding shares or Public Warrants through nominee names.

Dividend Policy

We have not paid any cash dividends on our Class A Common Stock to date. Our board of directors may from time to time consider whether or not to institute a dividend policy. It is our present intention to retain any earnings for use in our business operations and, accordingly, we do not anticipate the board of directors declaring any dividends in the foreseeable future.

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SELECTED HISTORICAL FINANCIAL INFORMATION

The following table shows Alta Mesa’s selected historical financial information for the periods and as of the dates indicated. The selected historical consolidated financial information as of December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016, and 2015 was derived from the audited historical consolidated financial statements of Alta Mesa included elsewhere in this prospectus. The selected historical consolidated financial information as of December 31, 2014 and 2013 and for the years ended December 31, 2014, and 2013 was derived from the audited historical consolidated financial statements of Alta Mesa. Historical financial information for Kingfisher is not included below and can be found in the financial statements attached to this prospectus.

Our historical results are not necessarily indicative of future operating results. In addition, the selected historical financial information below includes the results of operations from Alta Mesa’s non-STACK assets, which we did not acquire in the Business Combination. The selected consolidated and combined financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” as well as the historical consolidated and combined financial statements and accompanying notes and the unaudited pro forma condensed consolidated combined financial statements and accompanying notes included elsewhere in this prospectus.

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DESCRIPTION OF BUSINESS

The following discussion of our business should be read in conjunction with the “Selected Historical Financial Information” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion includes information regarding Alta Mesa’s non-STACK assets, which were not acquired by us in the Business Combination.

The estimated proved reserve information for our properties as of December 31, 2017 contained in this prospectus is based on the reserve report prepared by our internal engineers and audited by Ryder Scott Company, L.P., our independent petroleum engineer (such report being referred to as the “2017 Reserve Report”). A copy of the 2017 Reserve Report is attached to this prospectus as Exhibit B.

Corporate History

We were originally incorporated in Delaware on November 16, 2016 as a blank check company under the name Silver Run Acquisition Corporation II for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving us and one or more businesses (an “initial business combination”). On November 21, 2016, our Sponsor purchased 11,500,000 shares of Class B Common Stock, the founder shares, from us, for an aggregate purchase price of $25,000. On March 2017, we effected a stock dividend of 14,375,000 shares of Class B Common Stock, resulting in our Sponsor holding an aggregate of 25,875,000 founder shares. In March 2017, our Sponsor transferred 33,000 founder shares to each of our then independent directors (together with our Sponsor, the “initial stockholders”) at their original purchase price.

On March 29, 2017, we consummated our IPO of 103,500,000 Units (including 13,500,000 Units sold pursuant to the underwriters’ exercise of their over-allotment option) at $10.00 per Unit, with each Unit consisting of one share of Class A Common Stock and one-third of one Public Warrant. Simultaneously with the closing of our IPO on March 29, 2017, we completed the private sale of 15,133,333 warrants (the “Private Placement Warrants”) to our Sponsor at a purchase price of $1.50 per Private Placement Warrant, generating gross proceeds to us of $22,700,000. The Private Placement Warrants are identical to the Public Warrants, except that our Sponsor agreed not to transfer, assign or sell any of the Private Placement Warrants (except to certain permitted transferees) until 30 days after the completion of the Business Combination. The Private Placement Warrants are also not redeemable by us so long as they are held by our Sponsor or its permitted transferees.

A total of $1.035 billion (including approximately $36.2 million in deferred underwriting commissions to the underwriters of the IPO), which represents $1.0143 billion of the proceeds from the IPO after deducting upfront underwriting commissions of $20.7 million, and the proceeds of the sale of the private placement warrants were placed in the Trust Account (the “Trust Account”) to be used to fund an initial business combination. On April 26, 2017, we announced that the holders of our Units could elect to separately trade the Class A Common Stock and Public Warrants included in the Units.

From the consummation of our IPO through the end of July, 2017, we were searching for a suitable target business to effect an initial business combination. On August 16, 2017, we entered into the following agreements:

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On February 9, 2018 (the “Closing Date”), we consummated the acquisition of (i) all of the limited partnership interests in Alta Mesa, (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa GP and (iii) all of the membership interests in Kingfisher (such acquisition, the “Business Combination”).

At the closing of the Business Combination (the “Closing”),

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

In connection with the Closing, we also issued (i) one share of Series A Preferred Stock, par value $0.0001 per share (“Series A Preferred Stock”), to each of Bayou City Energy Management, LLC (“Bayou City”), HPS

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Investment Partners, LLC (“HPS”), and AM Equity Holdings, LP (“AM Management”), and (ii) one share of Series B Preferred Stock, par value $0.0001 per share (“Series B Preferred Stock”), to the Riverstone Contributor. None of the holders of the Series A Preferred Stock or Series B Preferred Stock is entitled to any dividends from us related to such Preferred Stock, but such holders are entitled to preferred distributions in liquidation in the amount of $0.0001 per share of Preferred Stock, and will have limited voting rights as described below. Shares of the Preferred Stock are redeemable for the par value thereof by us upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Preferred Stock at the election of the holder thereof or (3) upon a breach by the holder of the transfer restrictions applicable to such Preferred Stock. For so long as the Series A Preferred Stock or Series B Preferred Stock remains outstanding, as applicable, the holders thereof are entitled to nominate and elect directors to our board of directors for a period of up to five years following the Closing based on their and their affiliates’ beneficial ownership of Class A Common Stock.

Pursuant to the Alta Mesa Contribution Agreement and the Kingfisher Contribution Agreement, for a period of seven years following the Closing, the Alta Mesa Contributor and the Kingfisher Contributor may be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of Class C Common Stock) as earn-out consideration if the 20-Day VWAP of the Class A Common Stock equals or exceeds specified prices as follows (each such payment, an “Earn-Out Payment”):

Neither the Alta Mesa Contributor nor the Kingfisher Contributor will 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 Alta Mesa Contributor or the Kingfisher Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the Alta Mesa Contributor and/or the Kingfisher Contributor will be entitled to receive each such Earn-Out Payment. The Alta Mesa Contributor and the Kingfisher Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of our assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.

On February 6, 2018, our stockholders voted to approve the Business Combination. In connection with that vote, the holders of shares of Class A Common Stock originally sold as part of the units issued in our IPO (such holders, the “public stockholders”), were provided with the opportunity to redeem shares of Class A Common Stock then held by them for cash equal to approximately $10.00 per share. Public holders of 3,270 shares of Class A Common Stock elected to redeem those shares and, at the Closing, $32,944 held in the Trust Account was paid to such redeeming shareholders and the remaining $1,042.7 million held in the Trust Account was disbursed to us. We used these funds, along with the proceeds of the Forward Purchase Agreement, to fund our obligations under the Contribution Agreements and to pay the underwriters’ deferred discount.

On February 9, 2018, all of the outstanding founder shares were automatically converted into shares of Class A Common Stock on a one-for-one basis in connection with the Closing.

Following the Business Combination, we changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.” and continued the listing of our Class A Common Stock and Public Warrants on NASDAQ under the symbols “AMR” and “AMRWW,” respectively. Following the completion of the Business Combination, the size of our board of directors was expanded from four directors to 11, including one director appointed by Bayou City and its affiliates, one director appointed by HPS and its affiliates and two directors

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appointed by AM Management and its affiliates, as the holders of our Series A Preferred Stock, and three directors appointed by the Riverstone Contributor and its affiliates, as the holder of our Series B Preferred Stock. In addition, in connection with the Business Combination, we appointed the management team of Alta Mesa to hold most of our executive officer positions.

Alta Mesa is considered our accounting predecessor and hence the historical financial statements of Alta Mesa as of December 31, 2017 and 2016 and for each of the three years ended December 31, 2017 are included elsewhere in this prospectus. The (a) historical financial statements of AMR as of December 31, 2017 and 2016 and for the year ended December 31, 2017, and period from November 16, 2016 (date of inception) to December 31, 2016, (b) historical financial statements of Kingfisher as of December 31, 2017 and 2016, and for the two years ended December 31, 2017 and 2016, and (c) the unaudited pro forma balance sheet of AMR as of December 31, 2017, and income statement for the year ended December 31, 2017 are included only as Exhibits to this prospectus. Alta Mesa and Kingfisher continue to exist as separate subsidiaries of SRII Opco and those entities are separately financed, with each having debt obligations that are not obligations of the other. Consequently, references herein to Alta Mesa and to Kingfisher are to those entities and not to the Company as a whole.

Business Overview

Following the Business Combination, our only significant asset is our ownership of an approximate 44.2% partnership interest in SRII Opco. SRII Opco owns all of the economic interests in each of Alta Mesa (which owns our E&P Business) and Kingfisher (which owns our Midstream Business). Founded in 1987, Alta Mesa is an exploration and production company focused on the development and acquisition of unconventional oil and natural gas reserves in the eastern portion of the Anadarko Basin referred to as the STACK. The 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. The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates. As 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. Our drilling locations primarily target formations comprised of the Osage, Meramec and Oswego. We continue to acquire acreage within and adjacent to our acreage footprint with the goal of operating the drilling, completion and production operations in such locations. At present, we are operating seven horizontal drilling rigs in the STACK with plans to increase the number of rigs by the end of 2018. Following our Business Combination, our anticipated capital expenditures for 2018 of $568 million are all allocated to the STACK.

Our Midstream Business primarily focuses on providing crude oil gathering, gas gathering and processing and marketing to producers of natural gas, NGLs, crude oil and condensate in the STACK play. Our midstream energy asset network includes approximately 308 miles of existing low and high pressure pipelines, a 60 MMcf/d cryogenic natural gas processing plant, 10 MMcf/d in offtake processing, compression facilities, crude storage, NGL storage and purchasing and marketing capabilities.

Our goal is to build a premier development and acquisition company focused on horizontal drilling and gas gathering in the STACK.

OUR E&P BUSINESS

We intend to grow our reserves and production through the development of our multi-year inventory of identified drilling locations within the STACK. From 2012 to December 31, 2017, we increased our STACK production at a compound annual growth rate (CAGR) of approximately 80%. We increased our leasehold interests 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 largely undeveloped leasehold.

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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.

We 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, given that we expect full development of our leasehold to require multiple wells per drilling unit to maximize economic recovery of oil and natural gas from each formation.

As of 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.

2017 Highlights

During 2017, we concentrated our efforts on developing our assets in the STACK play. Highlights from 2017 include:

Industry Operating Environment and Outlook

The success of our business is highly dependent on the prices we receive for our oil, natural gas and natural gas liquids. Our industry has been significantly impacted by lower commodity prices in recent years. Commodity prices remained volatile, but generally increased on average in 2017 relative to 2016 in response to improving supply and demand fundamentals and other factors. Oil prices in particular showed significant signs of

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improvement in early 2018, with NYMEX West Texas Intermediate (“NYMEX WTI”) reaching $66.14 per barrel on January 26, 2018. As of April 4, 2018, NYMEX WTI was $63.64 per barrel and NYMEX Henry Hub was $2.71 per MMBtu. Commodity prices remain unpredictable, and it is uncertain whether the increase in market prices experienced in recent months will be sustained. Therefore, we cannot predict with certainty the future prices for the commodities we produce and sell. Forecasts can be impacted by many factors, including but not limited to changes in worldwide economic conditions, including the European credit markets; geopolitical activities, including developments in the Middle East, South America and elsewhere; worldwide supply conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets.

Our anticipated 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 activity in the STACK by BCE pursuant to our joint development agreement (described below). Following the Business Combination, 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.

Our Strategy

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

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Our Strengths

We believe that the following strengths provide us with significant competitive advantages and position us to continue to successfully execute our strategies:

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Reserve and Production Overview

The following table describes our proved reserves and production profile as of December 31, 2017:

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Our Properties

STACK, Oklahoma

As 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.

As of December 31, 2017, we had a 68% average working interest in 608 gross producing wells. We produced 7,513 MBOE net to us from our STACK properties in 2017, an increase of 58% as compared to 4,768 MBOE in 2016. During 2017, we spent approximately $356 million in the STACK 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 currently operate seven drilling rigs in the STACK for horizontal development. We plan to increase to eight drilling rigs by the end of 2018, targeting the Mississippian-age Osage, Meramec, and Manning formations and the Pennsylvanian-age Oswego formation with horizontal drilling. We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Osage.

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 City Joint Development Agreement

In January 2016, we entered into a joint development agreement with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. On

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December 31, 2016, High Mesa purchased from BCE and contributed interests in the Contributed Wells drilled under the joint development agreement to us with an effective date of October 1, 2016. The drilling program will fund the development of 80 additional wells, in four tranches of 20 wells each. As of December 31, 2017, 54 joint wells have been drilled or spudded leaving 26 joint wells to be drilled under the joint development agreement.

Under the joint development agreement, BCE has committed to fund 100% of our working interest share up to a maximum average of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding this limit. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest (the “BCE Interest”) in each wellbore, which the BCE Interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. 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 Access

We have favorable access to physical markets for our crude oil, natural gas and NGLs 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.

In the second quarter of 2016, Kingfisher commissioned 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 assurance 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 the end of April 2018.

We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to Kingfisher. As part of the 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 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.”

Other Assets

Through February 8, 2018, we conducted operations in other areas. On February 8, 2018, we distributed the remainder of our non-STACK assets to Alta Mesa 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 205-20, “Discontinued Operations”.

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Our Oil and Natural Gas Reserves

The table below summarizes our estimated net proved reserves as of December 31, 2017:

The table above 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. The process of estimating reserves is complex. This process requires significant decisions and assumptions in 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 factors, many of which are beyond our control. Sustained lower prices will cause the unweighted arithmetic average 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 and may necessitate future write-downs.

Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively 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 as established industry practices used by independent engineering firms and our peers, and in accordance the 2007 Petroleum Resources Management System sponsored and approved by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists and the Society of Petroleum Evaluation Engineers. The reserve estimation process begins with our Corporate Planning and Reserves 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 department. Lease operating and capital expenses are provided by our accounting department and reviewed by the Corporate Planning and Reserves department. Our Vice President of Corporate Planning and

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Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:

Our methodologies include reviews 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 same or similar fields.

We maintain internal controls including the following to ensure the reliability of reserves estimations:

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.

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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:

PUDs converted to proved developed reserves were primarily in the STACK, our most active development area. During 2017, we incurred approximately $26.3 million in expenditures to convert the December 31, 2016 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 SEC 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 assumptions in 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, which may cause us to decrease the amount of our PUDs we expect to develop within the five-year time frame. 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.

We reevaluate our five year PUD schedule quarterly. However, the relative proportion of total PUD reserves that we develop over the next 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 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.

During 2016 and 2017, we focused on drilling wells to hold our acreage and expand our proved reserves, as opposed to drilling PUD locations for development purposes as 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.

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Production, Prices and Production Cost History

The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sale of oil, natural gas, and natural gas liquids for the periods indicated below. For additional information on price calculations, please see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations”:

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The following table provides a summary of our production, average sales prices and average production costs for the STACK area, which contributes approximately 96% of our total proved reserves as of December 31, 2017;

Delivery Commitments

As of December 31, 2017, we had no commitments to provide a fixed quantity of oil, natural gas or natural gas liquids.

Drilling Activity

The following table sets forth, for each of the three years ended December 31, 2017, 2016 and 2015, the number of net productive and dry 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.

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We had one net well that is a developmental dry hole. The well was a recompletion related to our non-STACK asset.

Present Activities

As of December 31, 2017, we were drilling 43 gross (18.0 net) wells.

Productive Wells

The following table sets forth information with respect to our ownership interest in productive wells as of December 31, 2017:

Of the total well count as of December 31, 2017, 1 gross wells (0.6 net) are multiple completions.

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 gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractional working interests we own in gross wells.

Developed and Undeveloped Acreage Position

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, 2017, all of which is located in the United States: