Aransas Resources 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)
Registration No. 333-220789

PROSPECTUS

ALTA MESA HOLDINGS, LP

ALTA MESA FINANCE SERVICES CORP.

Offer to Exchange

Up To $500,000,000 of

7.875% Senior Notes due 2024

That Have Not Been Registered Under

The Securities Act of 1933

For

Up To $500,000,000 of

7.875% Senior Notes due 2024

That Have Been Registered Under

The Securities Act of 1933

The exchange offer and withdrawal rights will expire at 5:00 p.m.,

New York City time, on November 27, 2017, unless extended.

Terms of the New 7.875% Senior Notes due 2024 Offered in the Exchange Offer:

• The terms of the new notes (CUSIP No. 021332AF8) (the “new notes”) are identical to the terms of the old notes (CUSIP Nos. 021332AE1 and U02051AC1) (the “old notes”) that were issued on December 8, 2016, except that the new notes will be registered under the Securities Act of 1933 and will not contain restrictions on transfer, registration rights or provisions for additional interest.

Terms of the Exchange Offer:

• We are offering to exchange up to $500,000,000 of our old notes for new notes with materially identical terms that have been registered under the Securities Act of 1933 and are freely tradable.

• We will exchange all old notes that you validly tender and do not validly withdraw before the exchange offer expires for an equal principal amount of new notes.

• The exchange offer expires at 5:00 p.m., New York City time, on November 27, 2017, unless extended.

• Tenders of old notes may be withdrawn at any time prior to the expiration of the exchange offer.

• The exchange of new notes for old notes should not be a taxable event for U.S. federal income tax purposes.

• Broker-dealers who receive new notes pursuant to the exchange offer acknowledge that they will deliver a prospectus in connection with any resale of such new notes.

• Broker-dealers who acquired the old notes as a result of market-making or other trading activities may use the prospectus for the exchange offer, as supplemented or amended, in connection with resales of the new notes.

See “Risk Factors” beginning on page 14 for a discussion of certain risks that you should consider before participating in the exchange offer.

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 October 26, 2017

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume that the information contained in this prospectus is accurate as of any date other than its date.

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	ii
PROSPECTUS SUMMARY	1
RISK FACTORS	14
EXCHANGE OFFER	45
USE OF PROCEEDS	51
SELECTED HISTORICAL FINANCIAL AND OTHER DATA	52
RATIO OF EARNINGS TO FIXED CHARGES	53
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	54
BUSINESS	80
MANAGEMENT	111
THE PARTNERSHIP AGREEMENT	124
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	130
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	131
DESCRIPTION OF CERTAIN INDEBTEDNESS	134
DESCRIPTION OF NEW NOTES	137
PLAN OF DISTRIBUTION	190
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS	191
LEGAL MATTERS	192
EXPERTS	192
GLOSSARY OF OIL AND NATURAL GAS TERMS	192
INDEX TO FINANCIAL STATEMENTS	F-1
ANNEX A LETTER OF TRANSMITTAL	A-1

CAUTIONARY STATEMENT 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 our:

• ability to effect the AM Contribution Agreement (as defined below) and the acquisitions and other transactions contemplated thereby (the “business combination”);

• the benefits of the business combination;

• the future financial performance of the combined company following the business combination;

• business strategy;

• reserve quantities and the present value of our reserves;

• exploration and drilling prospects, inventories, projects and programs;

• our horizontal drilling, completion and production technology;

• ability to replace the reserves we produce through drilling and property acquisitions;

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

• future oil and natural gas prices;

• timing and amount of future production of oil and natural gas;

• hedging strategy and results;

• drilling and completion of wells, including statements about future horizontal drilling plans;

• competition and government regulation;

• ability to obtain permits and governmental approvals;

• changes in the Oklahoma forced pooling system;

• pending legal and environmental matters;

• future drilling plans

• marketing of oil, natural gas and natural gas liquids;

• leasehold or business acquisitions;

• costs of developing our properties;

• liquidity and access to capital;

• ability to hire, train or retain qualified personnel;

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• general economic conditions;

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

• the costs, terms and availability of gathering, processing, fractionation and other midstream services; and

• plans, objectives, expectations and intentions contained in this prospectus that are not historical.

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 occurrence of any event, change or other circumstances that could delay the business combination or give rise to the termination of the AM Contribution Agreement, the outcome of any legal proceedings that may be instituted against Silver Run Acquisition Corporation II (“SRII”) or us following announcement of the transactions, the inability to complete the business combination due to the failure to obtain approval of the stockholders of SRII or other conditions to closing in the AM Contribution Agreement, the risk that the proposed business combination disrupts our current plans and operations as a result of the announcement and consummation of the transactions, 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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PROSPECTUS SUMMARY

This summary highlights certain information concerning our business and this prospectus. Because this is a summary, it may not contain all of the information that may be important to you and to your investment decision. The following summary is qualified in its entirety by the more detailed information and financial statements and notes thereto included elsewhere in this prospectus. You should read this prospectus carefully and should consider, among other things, the matters set forth in “Risk Factors” and the other cautionary statements described in this prospectus.

In this prospectus, unless indicated otherwise, references to “Alta Mesa” refer to Alta Mesa Holdings, LP. References to the “Company”, “our company”, “we”, “our” and “us” refer to Alta Mesa and its subsidiaries. References to “Alta Mesa GP” or the “General Partner” are references to Alta Mesa Holdings GP, LLC, our general partner. References to “Co-issuer” are references to Alta Mesa Finance Services Corp., our wholly-owned subsidiary and co-issuer of the notes.

The estimates of our proved reserves as of December 31, 2016 included in this prospectus are based on reserve reports prepared for our internal engineers and audited by Ryder Scott in a reserves audit.

For the definitions of certain terms and abbreviations used in the oil and natural gas industry, see “Glossary of Oil and Natural Gas Terms”.

In this prospectus we refer to the notes to be issued in the exchange offer as the “new notes” and the notes issued on December 8, 2016 as the “old notes.” We refer to the new notes and the old notes together as the “notes.”

Our Company

We are a privately held, independent exploration and production company primarily engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids within the United States. We have transitioned our focus from our diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the eastern portion of the Anadarko Basin in Oklahoma (the “STACK”) with an extensive inventory of drilling opportunities.

At present, we are operating five horizontal drilling rigs in the STACK with plans to increase to seven rigs by the end of 2017. Our current anticipated capital expenditures for 2017 are $363 million, of which we have allocated over 95% to the STACK.

Beginning in the early 1990s, our operations in 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

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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. In addition to our existing horizontal development of the Osage, Meramec and Oswego formations, we also plan to commence the drilling of horizontal wells in the Manning formation in 2017.

As of December 31, 2016, our estimated total proved reserves were approximately 138.8 MMBOE, of which 93% were in the STACK. The estimated total proved reserves in the STACK were approximately 129.6 MMBOE, representing a 93% increase over 2015 year-end estimated proved reserves of 67.0 MMBOE in the STACK. Our total proved reserve mix is approximately 42% oil, 38% natural gas, and 20% natural gas liquids.

Recent Developments

Silver Run Contribution Agreement

On August 16, 2017, we entered into a Contribution Agreement (the “AM Contribution Agreement”) with Silver Run Acquisition Corporation II, a Delaware corporation (“SRII”), High Mesa Holdings, LP, a Delaware limited partnership (the “AM Contributor” or “HMH”), High Mesa Holdings GP, LLC, a Texas limited liability company, our General Partner and solely for certain provisions therein, the equity owners of AM Contributor. Pursuant to the AM Contribution Agreement, SRII will acquire from the AM Contributor (i) all of its limited partner interest in Alta Mesa; and (ii) 100% of the economic interests and 90% of the voting interests in our General Partner. In return, the AM Contributor will receive: (i) 220,000,000 common units (the “Common Units”) as adjusted of SRII Opco, LP, a Delaware limited partnership (“SRII Opco”) and wholly owned subsidiary of SRII; (ii) $400 million in cash, which shall be contributed to us; and (iii) up to $800 million in earn-out consideration in the form of common units of SRII Opco, LP (the “Earn-out Consideration”). At closing, the Common Units will be adjusted (i) upward for any inorganic acquisition capital expenditures invested by us during the interim period (based on a value of $10.00 per Common Unit), (ii) downward for the $200 million contribution to Alta Mesa by Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “RS Contributor” or “Riverstone”), which was made in connection with the parties entering into the Contribution Agreements (based on a value of $10.00 per SRII Opco Common Unit), and (iii) downward for debt and transaction expenses (based on a value of $10.00 per SRII Opco Common Unit). The Earn-out Consideration will be paid as set forth below if the 20-day volume-weighted average price (“VWAP”) of the Class A Common Stock of SRII (the “Class A Common Stock”) equals or exceeds the following prices:

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

Additionally, the AM Contributor will purchase non-economic capital stock of SRII, dedicated as Class C Common Stock (“Class C Common Stock”). The common units of SRII Opco, LP and corresponding Class C Common Stock are redeemable for Class A Common Stock beginning 180 days after the closing.

Simultaneous with the execution of the AM Contribution Agreement, SRII entered into (i) a Contribution Agreement (the “KFM Contribution Agreement”) with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“KFM” or “Kingfisher”), and, solely for certain provisions therein, the equity owners of the KFM Contributor, pursuant to which SRII will acquire 100% of the outstanding membership interests in Kingfisher (the “KFM Contribution”); and a contribution agreement (the “RS Contribution Agreement” and, together with the AM Contribution

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Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with the RS Contributor pursuant to which SRII will acquire from the RS Contributor all of its limited partner interests in Alta Mesa.

The acquisition of Alta Mesa and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “business combination.”

In connection with the execution of the RS Contribution Agreement, the RS Contributor made a $200 million capital contribution to us, in exchange for limited partner interests. Additionally, pursuant to that certain forward purchase agreement between SRII and Riverstone VI SR II Holdings, L.P. (“Riverstone SR”), dated as of August 16, 2017, Riverstone SR has agreed to purchase up to $200 million shares of SRII Class A Common Stock in order to consummate the business combination.

The Contribution Agreement contains customary representations and warranties and pre-closing covenants, with the representations and warranties not survive the closing. Additionally, we have agreed to transfer to the AM Contributor prior to closing all assets and liabilities related to our non-STACK assets. The closing of the Contribution Agreement is subject to (i) the approval of the SRII stockholders; (ii) the simultaneous closing of the KFM Contribution Agreement and the RS Contribution Agreement; (iii) a SRII Opco leverage ratio of less than 1.5x; (iv) certain regulatory approvals; and (v) the satisfaction or waiver of other customary closing conditions. The Contribution Agreement also contains certain customary termination rights, including if the transaction is not consummated by February 28, 2018.

The notes will continue to be obligations of the Issuers (as defined below) pursuant to the terms of the indenture dated December 8, 2016 after completion of the business combination.

Sixth Amended and Restated Agreement of Limited Partnership

On August 16, 2017, our General Partner, the AM Contributor and the RS Contributor entered into a Sixth Amended and Restated Agreement of Limited Partnership of Alta Mesa (the “Amended Partnership Agreement”). The Amended Partnership Agreement reflects, among other things, certain changes in the ownership of Alta Mesa, and provides for certain preemptive rights, tag-along rights, and drag-along rights for the limited partners. In connection with Amended Partnership Agreement, the existing limited partners of Alta Mesa transferred their interests in Alta Mesa to the AM Contributor. The Amended Partnership Agreement also reflects the admission of the RS Contributor and the AM Contributor to Alta Mesa as limited partners, and provides for certain distribution rights for the Class A and Class B limited partners with respect to the STACK and non-STACK assets.

The RS Contributor was admitted as a limited partner in connection with its $200 million capital contribution to us on August 17, 2017, in exchange for limited partner interests in Alta Mesa. We used all of the capital contribution to pay down our senior secured revolving credit facility.

Fifth Amended and Restated Limited Liability Company Agreement

On August 16, 2017, the owners of our General Partner entered into a Fifth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, show certain changes in the ownership of our General Partner and reflect that the holders of Class A units are entitled to 100% of the economic rights with respect to our General Partner and the holders of Class B units are entitled to 100% of the voting rights with respect to our General Partner.

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General Corporate Information

Alta Mesa Holdings, LP is a Texas limited partnership founded in 1987 with principal offices at 15021 Katy Freeway, Suite 400, Houston, Texas 77094. We can be reached at (281) 530-0991 and our website address is www.altamesa.net. Information on the website is not part of this prospectus. Co-issuer is a Delaware corporation and a wholly owned subsidiary of Alta Mesa that has no material assets.

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EXCHANGE OFFER

On December 8, 2016, we completed a private offering of the old notes. We entered into a registration rights agreement with the initial purchasers in the private offering in which we agreed to deliver to you this prospectus and to use commercially reasonable efforts to complete an exchange offer within 360 days after the date we issued the old notes.

Exchange Offer We are offering to exchange new notes for old notes. The old notes were issued under the indenture dated December 8, 2016.

Expiration Date The exchange offer will expire at 5:00 p.m., New York City time, on November 27, 2017, unless we decide to extend it.

Condition to the Exchange Offer The registration rights agreement does not require us to accept old notes for exchange if the exchange offer, or the making of any exchange by a holder of the old notes, would violate any applicable law or interpretation of the staff of the Securities and Exchange Commission. The exchange offer is not conditioned on a minimum aggregate principal amount of old notes being tendered.

Procedures for Tendering Old Notes To participate in the exchange offer, you must follow the procedures established by The Depository Trust Company, which we call “DTC,” for tendering notes held in book-entry form. These procedures, which we call “ATOP,” require that (i) the exchange agent receive, prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer, a computer generated message known as an “agent’s message” that is transmitted through DTC’s automated tender offer program, and (ii) DTC has received:

• your instructions to exchange your old notes, and

• your agreement to be bound by the terms of the letter of transmittal.

For more information on tendering your old notes, please refer to the section in this prospectus entitled “Exchange Offer — Terms of the Exchange Offer,” “Exchange Offer— Procedures for Tendering,” and “Description of New Notes — Book-Entry; Delivery and Form.”

Guaranteed Delivery Procedures None.

Withdrawal of Tenders You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer — Withdrawal of Tenders.”

Acceptance of Old Notes and Delivery of New Notes If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in

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the exchange offer before 5:00 p.m., New York City time on the expiration date. We will return any old notes that are late or not properly tendered and, therefore, that we do not accept for exchange, to you without expense promptly after the expiration date and acceptance of the old notes for exchange. Please refer to the section in this prospectus entitled “Exchange Offer — Terms of the Exchange Offer.”

Fees and Expenses We will bear expenses related to the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer — Fees and Expenses.”

Use of Proceeds The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement.

Consequences of Failure to Exchange Old Notes If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register the old notes under the Securities Act except in limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

U.S. Federal Income Tax Consequences The exchange of new notes for old notes in the exchange offer should not be a taxable event for U.S. federal income tax purposes. Please read “Certain United States Federal Income Tax Consequences.”

Exchange Agent We have appointed U.S. Bank National Association as exchange agent for the exchange offer. You should direct questions and requests for assistance, requests for additional copies of this prospectus or the letter of transmittal to the exchange agent as follows:

By mail, overnight courier or in person:

U.S. Bank National Association

Attn: Specialized Finance

111 Fillmore Avenue

St. Paul, MN 55107-1402

Eligible institutions may make requests by facsimile at(651) 466-7367.

See “Exchange Offer” for more detailed information concerning the terms of the exchange offer.

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TERMS OF THE NEW NOTES

The new notes will be identical to the old notes except that the new notes will be registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest. The new notes will evidence the same debt as the old notes, and the same indenture will govern the new notes and the old notes. The old notes do, and the new notes will, constitute the same series of securities for purposes of the indenture.

The following summary contains basic information about the new notes and is not intended to be complete. It does not contain all information that may be important to you. For a more complete understanding of the new notes, please refer to the section entitled “Description of New Notes” in this prospectus.

Issuers Alta Mesa Holdings, LP and Alta Mesa Finance Services Corp. The Co-issuer is our wholly owned direct subsidiary and exists solely to co-issuer our notes and other debt. The Co-issuer has no material assets and does not conduct any operations.

Securities Offered $500,000,000 aggregate principal amount of 7.875% senior notes due 2024.

Maturity Date December 15, 2024.

Interest Interest on the notes will accrue at the rate of 7.875% per annum.

Interest Payment Dates June 15 and December 15 of each year. Interest on each new note will accrue from the last interest payment date on which interest was paid on the old note tendered in exchange thereof, or, if no interest has been paid on the old note, from the date of the original issue of the old note.

Guarantees The notes will be guaranteed initially by all of our subsidiaries, other than certain immaterial subsidiaries, and will be guaranteed by our future domestic restricted subsidiaries, other than certain immaterial subsidiaries.

Ranking The new notes and the related guarantees will be the unsecured senior obligations of us, the Co-issuer and the guarantors. Accordingly, they will rank:

• equal in right of payment with our existing and future senior indebtedness, including our senior secured revolving credit facility and any old notes that are not exchanged;

• senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the notes or the respective guarantees;

• effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our senior secured revolving credit facility; and

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• structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the notes.

As of September 25, 2017, we had $639 million of debt outstanding, $111 million of which was secured indebtedness and our non-guarantor subsidiaries had no indebtedness outstanding except that certain non-guarantor subsidiaries have guaranteed obligations under our senior secured revolving credit facility.

Optional Redemption Beginning on December 15, 2019, we may redeem some or all of the notes at the redemption prices listed under “Description of New Notes — Optional Redemption” plus accrued and unpaid interest on the notes to the date of redemption. At any time prior to December 15, 2019, we may redeem up to 35% of the aggregate principal amount of the notes from the proceeds of certain sales of our equity securities at 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption. We may make that redemption only if, after the redemption, at least 65% of the aggregate principal amount of the notes remains outstanding and the redemption occurs within 120 days of the closing of the equity offering.

Before December 15, 2019, we may redeem some or all of the notes at the “make-whole” redemption price set forth under “Description of New Notes — Optional Redemption” plus accrued and unpaid interest on the notes to the date of redemption.

Change of Control Upon the occurrence of a change of control (as described under “Description of New Notes — Change of Control”), we must offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase.

Covenants The indenture governing the notes contains certain covenants limiting our ability and the ability of our restricted subsidiaries to, under certain circumstances:

• prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments;

• incur indebtedness;

• create liens on our assets to secure debt;

• restrict dividends, distributions or other payments from subsidiaries to us;

• enter into transactions with affiliates;

• designate subsidiaries as unrestricted subsidiaries;

• sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries;

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• effect a consolidation or merger; and

• change our line of business.

These covenants are subject to important exceptions and qualifications as described in this prospectus under the caption “Description of New Notes — Certain Covenants”.

Limited Public Market for the New Notes The new notes generally will be freely transferable, but will also be new securities for which the public market may be limited. There can be no assurance as to the development, persistence or liquidity of any market for the new notes. We do not intend to apply for a listing of the new notes on any securities exchange or any automated dealer quotation system.

Risk Factors Investing in the new notes involves risks. See “Risk Factors” beginning on page 14 for a discussion of certain factors you should consider in evaluating whether or not to tender your old notes.

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Summary Historical Financial Data

The following table sets forth our summary historical financial data as of and for each of the periods indicated. The summary historical financial data as of and for the years ended December 31, 2016, 2015 and 2014 are derived from our historical audited consolidated financial statements and are included elsewhere in this prospectus. The condensed consolidated financial data as of and for the six months ended June 30, 2017 and 2016 have been derived from our unaudited consolidated financial statements and are included elsewhere in this prospectus. Our audited and unaudited consolidated financial statements have been prepared in accordance with GAAP.

For further information that will help you better understand the summary financial data, you should read this financial data in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section included elsewhere in this prospectus and the financial statements and related notes and other financial information included elsewhere in this prospectus.

	Six Months Ended June 30,						Year Ended December 31,
	2017			2016			2016			2015			2014
	(unaudited)
	(in thousands)
Statement of Operations Data:
Operating revenues and other:
Oil, natural gas, and natural gas liquids	$	154,932		$	91,689		$	210,293		$	241,284		$	431,125
Other revenues		202			301			415			682			1,003
Total operating revenues		155,134			91,990			210,708			241,966			432,128
Gain on sale of assets		—			3,731			3,542			67,781			87,520
Gain on acquisition of oil and natural gas properties		1,626			—			—			—			—
Gain (loss) on derivative contracts		48,492			(27,478	)		(40,460	)		124,141			96,559
Total operating revenues and other		205,252			68,243			173,790			433,888			616,207
Operating Expenses:
Lease and plant operating expense		34,333			30,577			56,893			67,706			64,686
Marketing and transportation expense		12,900			2,887			13,326			4,030			9,134
Production and ad valorem taxes		6,107			5,126			10,750			15,131			28,214
Workover expense		3,398			2,515			4,714			6,511			8,961
Exploration expense		14,407			6,714			24,777			42,718			61,912
Depreciation, depletion, and amortization		51,298			44,424			92,901			143,969			141,804
Impairment expense		29,124			13,319			16,306			176,774			74,927
Accretion expense		1,052			1,075			2,174			2,076			2,198
General and administrative expense		18,076			22,259			41,758			44,454			69,198
Total operating expenses		170,695			128,896			263,599			503,369			461,034
Income (loss) from operations		34,557			(60,653	)		(89,809	)		(69,481	)		155,173
Other expense:
Interest expense, net		(24,671	)		(33,634	)		(59,990	)		(61,750	)		(55,797	)
Loss on extinguishment of debt		—			—			(18,151	)		—			—
Total other expense		(24,671	)		(33,634	)		(78,141	)		(61,750	)		(55,797	)
Income (loss) before income taxes		9,886			(94,287	)		(167,950	)		(131,231	)		99,376
Income taxes:
Provision (benefit) for state income taxes		285			107			(29	)		562			176
Income (loss) from continuing operations	$	9,601		$	(94,394	)	$	(167,921	)	$	(131,793	)	$	99,200
Other supplementary data:
Adjusted EBITDAX(1)		81,122			95,050			172,850			211,806			261,443

(1) Adjusted EBITDAX is a non-GAAP financial measure. See “Reconciliation of Non-GAAP Financial Measure” below.

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	Six Months Ended June 30,						Year Ended December 31,
	2017			2016			2016			2015			2014
	(unaudited)
	(in thousands)
Statement of Cash Flow Data:
Capital expenditures	$	151,832		$	94,997		$	214,061		$	223,604		$	366,090
Net cash flow provided by (used in) operating activities		(6,593	)		(46,919	)		131,376			143,978			184,884
Net cash used in investing activities		(158,083	)		(93,639	)		(224,298	)		(105,815	)		(189,721	)
Net cash provided by (used in) financing activities		162,770			141,136			91,238			(30,643	)		(351	)
Balance Sheet Data (at period end):
Cash and cash equivalents	$	5,279		$	9,447		$	7,185		$	8,869		$	1,349
Property and equipment, net		832,188			566,702			721,893			537,039			697,681
Total assets		957,002			790,210			813,851			722,525			911,125
Total debt, including Founder Notes(1)		713,082			887,846			556,862			743,523			785,682
Total equity holders’ capital (deficit)		41,707			(271,443	)		32,106			(177,049	)		(61,446	)

(1) Our notes payable to our founder had a balance of (i) $27.6 million and $26.3 million at June 30, 2017 and 2016, respectively and (ii) $27.0 million, $25.7 million and $24.5 million at December 31, 2016, 2015 and 2014, respectively.

Reconciliation of Non-GAAP Financial Measure

Adjusted EBITDAX is a non-GAAP financial measure and as used herein represents net income before interest expense, exploration expense, depletion, depreciation and amortization, impairment of oil and natural gas properties, accretion of asset retirement obligations, tax expense, (gain)/loss on sale of assets and unrealized settlements of oil and gas derivative contracts. We present Adjusted EBITDAX because we believe Adjusted EBITDAX is an important supplemental measure of our performance that is frequently used by others in evaluating companies in our industry. Adjusted EBITDAX is not a measurement of our financial performance under GAAP, and should not be considered as an alternative to net income (loss), operating income (loss) or any other performance measure derived in accordance with GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. Adjusted EBITDAX has significant limitations, including that it does not reflect our cash requirements for capital expenditures, contractual commitments, working capital or debt service. In addition, other companies may calculate Adjusted EBITDAX differently than we do, limiting its usefulness as a comparative measure.

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The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to Adjusted EBITDAX for the periods indicated:

	Six Months Ended June 30,						Year Ended December 31,
	2017			2016			2016			2015			2014
	(unaudited)
	(in thousands)
Reconciliation of net income (loss) to Adjusted EBITDAX
Net income (loss)	$	9,601		$	(94,394	)	$	(167,921	)	$	(131,793	)	$	99,200
Interest expense		25,219			34,067			60,884			62,473			55,812
Loss on extinguishment of debt		—			—			18,151			—			—
Exploration expense		14,407			6,714			24,777			42,718			61,912
Depreciation, depletion, and amortization		51,298			44,424			92,901			143,969			141,804
Impairment expense		29,124			13,319			16,306			176,774			74,927
Accretion expense		1,052			1,075			2,174			2,076			2,198
Provision (benefit) for income taxes		285			107			(29	)		562			176
(Gain)/loss on sale of assets		—			(3,731	)		(3,542	)		(67,781	)		(87,520	)
(Gain)/loss on acquisition of oil and natural gas properties		(1,626	)		—			—			—			—
(Gain)/loss on derivative contracts(1)		(48,238	)		93,469			129,149			(17,192	)		(87,066	)
Adjusted EBITDAX	$	81,122		$	95,050		$	172,850		$	211,806		$	261,443

(1) Net of cash settlements and which includes (i) $0.9 million and $40.2 million related to settlements of oil and natural gas derivative contracts prior to contract expiry for the six months ended June 30, 2017 and 2016, respectively and (ii) $64.0 million, $41.6 million and $0.3 million related to settlements of oil and natural gas derivative contracts prior to contract expiry for the years ended December 31, 2016, 2015 and 2014, respectively.

Proved Reserves and Operating Data

Proved Reserves

The table below summarizes SEC estimated proved reserves as of December 31, 2016, which were prepared by us and audited by Ryder Scott.

	SEC Pricing(1)
Estimated Proved Reserves:
Oil (MBbls)		57,799
NGL (MBbls)		28,290
Natural gas (MMcf)		316,005
Total proved (MBOE)		138,757
Proved developed producing (MBOE)		36,117
Proved developed non-producing (MBOE)		4,254
Proved undeveloped (MBOE)		98,386
Percent Liquids(2)		62.0	%
Percent proved developed		29.0	%
PV-10 (dollars in millions)(3)	$	558.6

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(1) Our proved reserves as of December 31, 2016 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on average prices as of the first day of each of the 12 months ended on such date. These average prices were $42.75 per Bbl for oil and $2.49 per MMBtu for natural gas for December 31, 2016. Pricing was adjusted for basis differentials by field based on our historical realized prices. Ryder Scott audited the reserves in a reserves audit. The estimated realized prices for natural gas liquids using a $42.75 per Bbl benchmark and adjusted for average differentials were $15.18. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others.

(2) Liquids include both oil and natural gas liquids reserves.

(3) PV-10 was calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the twelve months ended December 31, 2016. Because we are a partnership and, as such, are not subject to income taxes, our PV-10 is the same as our standardized measure of future net cash flows, the most comparable measure under United States generally accepted accounting principles, which is reduced for the discounted value of estimated future income taxes. Calculation of PV-10 does not give effect to derivatives transactions.

Operating Data

The following table sets forth certain information regarding production volumes, average prices and average production costs associated with our sale of oil and natural gas for the periods indicated.

	Six Months Ended June 30,				Year Ended December 31,
	2017		2016		2016		2015		2014
Net production:
Oil (MBbls)		2,363		2,041		4,001		4,203		3,770
Natural gas (MMcf)		9,285		6,144		13,959		11,900		14,449
Natural gas liquids (MBbls)		646		438		956		678		537
Total (MBOE)		4,557		3,502		7,284		6,865		6,715
Total (MMcfe)		27,341		21,013		43,702		41,187		40,290
Average sales price per unit before hedging effects:
Oil (per Bbl)	$	48.41	$	36.79	$	40.91	$	47.54	$	92.27
Natural gas (per Mcf)		2.78		1.71		2.22		2.57		4.50
Natural gas liquids (per Bbl)		22.74		13.97		16.38		16.01		34.04
Combined (per BOE)		34.00		26.18		28.87		35.15		64.20
Combined (per MMcfe)		5.67		4.36		4.81		5.86		10.70
Average sales price per unit after hedging effects:
Oil (per Bbl)	$	48.38	$	66.57	$	61.53	$	67.73	$	93.38
Natural gas (per Mcf)		2.86		2.56		2.68		4.43		4.87
Natural gas liquids (per Bbl)		22.14		13.98		16.04		16.01		34.04
Combined (per BOE)		34.06		45.02		41.05		50.73		65.62
Combined (per MMcfe)		5.68		7.50		6.84		8.45		10.94
Average costs per BOE:
Lease and plant operating expense	$	7.53	$	8.73	$	7.81	$	9.86	$	9.63
Marketing and transportation expense		2.83		0.82		1.83		0.59		1.36
Production and ad valorem taxes		1.34		1.46		1.48		2.20		4.20
Workover expense		0.75		0.72		0.65		0.95		1.33
Average costs per Mcfe:
Lease and plant operating expense	$	1.26	$	1.46	$	1.30	$	1.64	$	1.61
Marketing and transportation expense		0.47		0.14		0.30		0.10		0.23
Production and ad valorem taxes		0.22		0.24		0.25		0.37		0.70
Workover expense		0.12		0.12		0.11		0.16		0.22

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RISK FACTORS

An investment in the notes involves a significant degree of risk. You should carefully consider each of the risks described below, together with all of the other information contained in this prospectus, before deciding to invest in the new notes and participate in the exchange offer. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, which in turn could adversely affect our ability to satisfy our obligations under the notes and the guarantees of the notes. Consequently, you may lose all or part of your investment.

Risks Related to the Exchange Offer

You may have difficulty selling the old notes you do not exchange.

If you do not exchange your old notes for new notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your old notes as described in the legend on the global notes representing the old notes. There are restrictions on transfer of your old notes because we issued the old notes under an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. In general, you may only offer or sell the old notes if they are registered under the Securities Act and applicable state securities laws or offered and sold under an exemption from, or in a transaction not subject to, these requirements. We do not intend to register any old notes not tendered in the exchange offer and, upon consummation of the exchange offer, you will not be entitled to any rights to have your untendered old notes registered under the Securities Act.

Broker-dealers may need to comply with the registration and prospectus delivery requirements of the Securities Act.

Any broker-dealer that (1) exchanges its old notes in the exchange offer for the purpose of participating in a distribution of the new notes or (2) resells new notes that were received by it for its own account in the exchange offer may be deemed to have received restricted securities and will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction by that broker- dealer. Any profit on the resale of the new notes and any commission or concessions received by a broker-dealer may be deemed to be underwriting compensation under the Securities Act.

You may not receive new notes in the Exchange Offer if the Exchange Offer procedure is not followed.

We will issue the new notes in exchange for your old notes only if you tender the old notes before expiration of the exchange offer in the manner required herein. Neither the exchange agent nor we are under any duty to give notification of defects or irregularities with respect to the tenders of old notes for exchange. If you are the beneficial holder of old notes that are registered in the name of your broker, dealer, commercial bank, trust company or other nominee, and you wish to tender old notes in the exchange offer, you should promptly contact the person in whose name your old notes are registered and instruct that person to tender your old notes on your behalf.

Risks Related to the New Notes

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our senior secured revolving credit facility and the notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

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If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our senior secured revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

The borrowing base under our senior secured revolving credit facility is currently $315.0 million. Our next scheduled borrowing base redetermination is expected to occur on or before November, 2017. In the future, we may not be able to access adequate funding under our senior secured revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payments on the notes.

As of the date of September 25, 2017, we had $500 million of notes outstanding, we and the guarantors had $111 million of secured indebtedness outstanding, $5 million of outstanding letters of credit reimbursement obligations and an additional $199 million available for borrowing under the senior secured revolving credit facility, to which the notes rank junior to the extent of the value of the collateral securing such obligations, and $28 million of unsecured debt outstanding in the form of founder notes; and our subsidiaries that are not guarantors had no obligations (including trade payables but excluding intercompany obligations) outstanding, to which the notes rank structurally junior.

Our level of indebtedness could affect our operations in several ways, including the following:

• require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;

• limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• increase our vulnerability to downturns and adverse developments in our business and the economy generally;

• limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

• place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

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• make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;

• make us vulnerable to increases in interest rates as our indebtedness under our senior secured revolving credit facility may vary with prevailing interest rates;

• place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and

• make it more difficult for us to satisfy our obligations under the notes or other debt and increase the risk that we may default on our debt obligations.

The notes and the guarantees are unsecured obligations and effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness and structurally subordinated to liabilities of any non-guarantor subsidiaries.

The notes and the guarantees are general unsecured senior obligations ranking effectively junior to all of our existing and future secured indebtedness (including all borrowings under our senior secured revolving credit facility) to the extent of the value of the collateral securing such indebtedness. Under our senior secured revolving credit facility, we have granted a first-priority lien on the material portion of our and our subsidiaries’ properties now owned, or acquired in the future, including substantially all of their real and personal property. If we or a guarantor is declared bankrupt, becomes insolvent or is liquidated or reorganized, the holders of our secured indebtedness or the secured indebtedness of such guarantor will be entitled to be paid in full from the proceeds of the assets, if any, securing such indebtedness before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably in any remaining proceeds with all holders of our unsecured indebtedness, including unsecured indebtedness incurred after the notes are issued that does not rank junior to the notes, including trade payables and all of our other general indebtedness, based on the respective amounts owed to each holder or creditor. In any of the foregoing events, there may not be sufficient funds to pay amounts due on the notes. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.

The notes will also be structurally subordinated to any indebtedness and other liabilities of any of our future subsidiaries that do not guarantee the notes. The indenture governing the notes permits us to form or acquire additional subsidiaries that are not guarantors of the notes in certain circumstances.

We and our subsidiaries may incur substantial additional indebtedness. This could increase the risks associated with the notes.

Subject to the restrictions in the indenture governing the notes and in other instruments governing our other outstanding indebtedness (including our senior secured revolving credit facility), we and our subsidiary guarantors may incur substantial additional indebtedness (including secured indebtedness) in the future. Although the indenture governing the notes and our senior secured revolving credit facility contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to waiver and a number of significant qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial.

If we or a guarantor incurs any additional indebtedness that ranks equally with the notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. This may have the effect of reducing the amount of proceeds paid to holders of the notes in connection with such a distribution.

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Any increase in our level of indebtedness will have several important effects on our future operations, including, without limitation, whether:

• we will have additional cash requirements in order to support the payment of interest on our outstanding indebtedness;

• increases in our outstanding indebtedness and leverage will increase our vulnerability to adverse changes in general economic and industry conditions, as well as to competitive pressure; and

• depending on the levels of our outstanding indebtedness, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be limited.

We cannot assure you that we will be able to maintain or improve our leverage position.

An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil, natural gas and NGL prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control.

Our senior secured revolving credit facility and the indenture governing the notes contain restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities.

Our senior secured revolving credit facility and the indenture governing the notes contain restrictive covenants, that could limit our ability to, among other things:

• incur additional indebtedness;

• sell assets;

• guaranty or make loans to others;

• make investments;

• enter into mergers;

• make certain payments and distributions;

• enter into or be party to hedge agreements;

• amend our organizational documents;

• incur liens; and

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

As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

In addition, our senior secured revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios, which may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of these limitations. See “Description of Certain Indebtedness” and “Description of New Notes —Certain Covenants.”

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Our 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 our indebtedness. If that occurs, we 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 us.

If we are unable to comply with the restrictions and covenants in the agreements governing the notes and our other indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would affect our ability to make principal and interest payments on the notes.

Any default under the agreements governing our indebtedness that is not cured or waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal, premium, if any, and interest, or special interest, if any, on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest, or special interest, if any, on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the agreements governing our indebtedness (including covenants in our senior secured revolving credit facility and the indenture governing the notes), we could be in default under the terms of the agreements governing such indebtedness. In the event of such 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 our senior secured revolving credit facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and

• we could be forced into bankruptcy or liquidation.

If our operating performance declines, we may in the future need to obtain waivers under our senior secured revolving credit facility to avoid being in default. If we breach our covenants under our senior secured revolving credit facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our senior secured revolving credit facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.

We may not be able to repurchase the notes upon a change of control.

If we experience certain kinds of changes of control followed by a rating decline, we may be required to offer to repurchase all outstanding notes at 101% of their principal amount, plus accrued and unpaid interest, if any. We may not be able to repurchase the notes upon a change of control because we may not have sufficient financial resources to purchase all of the notes that are tendered following a change of control. In addition, the terms of our senior secured revolving credit facility would effectively prohibit, and the terms of other future indebtedness may also prohibit, us from repurchasing notes upon a change of control. Our failure to repurchase the notes upon a change of control could cause a default under the indenture governing the notes and could lead to a cross default under our senior secured revolving credit facility. Additionally, using cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations. See “Description of New Notes — Change of Control.”

Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from guarantors.

Federal bankruptcy and state fraudulent transfer laws permit a court to void all or a portion of the obligations of a guarantor pursuant to its guarantee of the notes, or to subordinate any guarantor’s obligations

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under such guarantee to claims of its other creditors, reducing or eliminating the noteholders’ ability to recover under such guarantee. Although laws differ among these jurisdictions, in general, under applicable fraudulent transfer or conveyance laws, a guarantee could be voided as a fraudulent transfer or conveyance if (i) the guarantee was incurred with the intent of hindering, delaying or defrauding creditors or (ii) the guarantor received less than reasonably equivalent value or fair consideration in return for incurring the guarantee and either:

• the guarantor was insolvent or rendered insolvent by reason of the incurrence of the guarantee or subsequently became insolvent for other reasons;

• the incurrence of the guarantee left the guarantor with an unreasonably small amount of capital to carry on the business; or

• the guarantor intended to, or believed that it would, incur debts beyond its ability to pay such debts as they mature.

A court would likely find that a guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the guarantor did not substantially benefit directly or indirectly from the issuance of the notes. If a court were to void a guarantee, you would no longer have a claim against the guarantor. Sufficient funds to repay the notes may not be available from other sources, including the remaining guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the guarantor. The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law of the applicable jurisdiction. Generally, a guarantor would be considered insolvent if:

• the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;

• the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they became absolute and mature; or

• it could not pay its debts as they became due.

Each guarantee contains a provision intended to limit the guarantor’s liability under the guarantee to the maximum amount that the guarantor could incur without causing the incurrence of obligations under its guarantee to be deemed a fraudulent transfer. This provision may not be effective to protect the guarantees from being voided under fraudulent transfer law.

An active trading market for the notes does not exist and may not develop.

There is no existing market for the notes. The notes will not be listed on any securities exchange. There can be no assurance that a trading market for the notes will ever develop or will be maintained. Further, there can be no assurance as to the liquidity of any market that may develop for the notes, your ability to sell your notes or the price at which you will be able to sell your notes. Future trading prices of the notes will depend on many factors, including prevailing interest rates, our financial condition and results of operations, the then current ratings assigned to the notes and the market for similar securities. Any trading market that develops would be affected by many factors independent of and in addition to the foregoing, including:

• the time remaining to the maturity of the notes;

• the outstanding amount of the notes;

• the number of noteholders;

• the interest of securities dealers in making a market for the notes;

• our operating performance and financial condition;

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• the terms related to optional redemption of the notes; and

• the level, direction and volatility of market interest rates generally.

If an active market does not develop or is not maintained, the market price and liquidity of the notes may be adversely affected.

We face risks related to rating agency downgrades.

Any future downgrading of the notes by Moody’s Investors Services, Inc. or Standard & Poor’s Rating Services may materially and adversely affect the value and trading of the notes. In addition, a ratings downgrade could adversely affect our ability to raising capital and borrowing costs under our senior secured revolving credit facility and other future borrowings may increase.

Risks Related to the Business Combination with Silver Run

The closing of the business combination is subject to many conditions and if these conditions are not satisfied or waived, the business combination will not be completed.

The closing of the business combination is subject to a number of conditions as set forth in the AM Contribution Agreement that must be satisfied or waived, including, among others, the following (i) the absence of specified adverse laws or orders; (ii) if applicable, the expiration of the waiting period (or extension thereof) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (iii) the representations and warranties of the other parties being true and correct, subject to the materiality standards contained in the AM Contribution Agreement; (iv) material compliance by the other parties with their respective covenants; (v) no material adverse effect having occurred with respect to us since the signing of the AM Contribution Agreement; (vi) the approval for listing on the NASDAQ of the shares of Class A Common Stock issuable to the AM Contributor; and (vii) the approval of the business combination and the transactions by SRII’s stockholders. The closing of the transactions contemplated under the AM Contribution Agreement is also conditioned upon the simultaneous closing of the KFM Contribution Agreement and the RS Contribution Agreement. There can be no assurance whether or when the conditions to closing of the business combination will be satisfied or waived or the business combination will be consummated.

We will be subject to business uncertainties and contractual restrictions while the business combination is pending.

Uncertainty about the effect of the business combination on employees and third parties with whom we do business may have an adverse effect on us. These uncertainties may impair our ability to retain and motivate key personnel and could cause third parties that deal with us to defer entering into contracts or making other decisions or seek to change existing business relationships. All of this could negatively affect the financial condition and results of operations of the company and/or the combined company.

Under the terms of the AM Contribution Agreement, we are subject to certain restrictions on the conduct of our business prior to completing the business combination, which may adversely affect our ability to execute certain of our business strategies, including the ability in certain cases to enter into contracts, acquire or dispose of assets, incur indebtedness or incur capital expenditures. Such limitations could negatively affect our business and operations prior to the completion of the business combination.

Our ability to successfully effect the business combination and successfully operate the business thereafter will be largely dependent upon the efforts of certain key personnel. The loss of such key personnel and our inability to hire and retain replacements could negatively impact the operations and profitability of the combined company following the business combination.

Our ability to successfully effect the business combination and successfully operate the business is dependent upon the efforts of certain key personnel, including our senior management. If any such key personnel

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depart because of issues relating to the uncertainty of the business combination or a desire not to become employees of the combined company, the combined company’s ability to realize the anticipated benefits of the business combination could be reduced.

We will incur significant transaction costs in connection with the business combination.

We have and expect to incur significant, non-recurring costs in connection with consummating the business combination. Non-recurring transaction costs include, but are not limited to, legal, accounting, consulting, and investment banking fees. Our transaction expenses as a result of the business combination are currently estimated at approximately $12 million and subject to increase. This could limit funds available for operating our business which could have a negative effect on our financial condition.

Our management’s attention from our ongoing business operations may be disrupted due to the business combination.

We have expended, and continue to expend, significant management resources in an effort to complete the business combination. Management’s attention may be diverted away from the day-to-day operations of our business and execution of our existing business plan in our efforts to complete the business combination. This diversion of management resources could disrupt operations and have an adverse effect on our operating results and business.

Risks Related to Our Business and the Oil and Natural Gas Industry

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. Our capital expenditures for 2016 totaled $226 million including acquisitions. As a result of the current price environment, we have increased our budgeted capital expenditures for 2017 to approximately $363 million including acquisitions. 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. If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under our senior secured revolving credit facility and the future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

• the estimated quantities of our oil and natural gas reserves;

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

• the prices at which we sell our production;

• take-away capacity; and

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

If our revenues or the borrowing base under our senior secured revolving credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. Our senior secured revolving credit facility may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our senior secured revolving credit facility is not sufficient to meet our capital

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requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operation, financial conditions and ability to make payments on our 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 our senior secured revolving credit facility may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and we may be forced to limit or defer 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.

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 the second half of 2014. Oil prices continued to fluctuate during 2016. 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. Based on daily settlements of monthly contracts traded on the NYMEX, the average price for the 12 months ended June 30, 2017 for a barrel of oil ranged from a high of $53.46 in February 2017 to a low of $44.80 in August 2016, 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, further 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 2016 was $40.91 per barrel compared to $47.54 per barrel in 2015 and $92.27 per barrel in 2014. We received an average price of $47.18 per barrel for the second quarter of 2017, excluding hedge settlements. 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:

• the domestic and foreign supply of and demand for oil and natural gas;

• the price and quantity of foreign imports of oil and natural gas;

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

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• federal regulations applicable to exports of liquefied natural gas (“LNG”), including the recent export of the first quantities of LNG liquefied from natural gas produced in the lower 48 states of the U.S.;

• recent actions taken by members of the Organization of Petroleum Exporting Countries and other oil producing nations in connection with their arrangements to maintain oil price and production controls;

• the level of consumer product demand;

• weather conditions;

• domestic and foreign governmental regulations, including environmental initiatives and taxation;

• overall domestic and global economic conditions;

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

• stockholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas in order to minimize emissions of carbon dioxide, a GHG;

• political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, Central America, China and Russia and acts of terrorism or sabotage;

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

• technological advances affecting energy consumption;

• the price and availability of alternative fuels; and

• the impact of energy conservation efforts.

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

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 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:

• landing our wellbore in the desired drilling zone;

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

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

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

Difficulties that we face while completing our wells include the following:

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

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

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

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any

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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.

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

Lower prices could reduce our cash flows to a level that would require us to borrow to fund our remaining 2017 capital budget. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas prices could render uneconomic a significant portion of our identified drilling locations. This may result in significant downward adjustments to our estimated proved reserves and, as a result, a decline in the borrowing base under our senior secured revolving credit facility. As a result, a substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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 NGLs prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are located, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

Furthermore, our estimate of the number of our net drilling locations is based on a number of assumptions, which may prove to be incorrect. 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 of such acreage with adjacent properties controlled by third parties. Our assumptions regarding the impact on any such unitization 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.

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.

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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 remain low or we are unable to fund our anticipated capital program, there is a risk that some of our existing proved reserves and some of our unproved inventory could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. This could result in a reduction in our reserves and our growth opportunities (or the incurrence of significant costs). Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

We depend on successful exploration, exploitation, development and acquisitions to maintain reserves and revenue in the future.

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

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 2016 and 2015 of $16.3 million and $176.8 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.

During 2015 and 2016, we recognized significant impairments of proved oil and gas properties and impairments of unproved oil and gas properties, primarily as a result of lower forecasted commodity prices and changes to our drilling plans. At December 31, 2016, our estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $550.8 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 this depletion group becomes impaired in a future period,

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we could recognize non-cash impairments in that period in excess of $5.0 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, 2016. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced.

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 twelve-month unweighted arithmetic average of the closing prices on the first day of each month for the preceding twelve months from the date of the report without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

• actual prices we receive for crude oil, natural gas and NGLs;

• actual cost of development and production expenditures;

• the amount and timing of actual production;

• transportation and processing; and

• changes in governmental regulations or taxation.

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, 2016 would decrease by approximately $236.4 million to $322.2 million.

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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 plan on delaying those wells within the required five-year timeframe.

Approximately 71% of our total estimated proved reserves at December 31, 2016 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, 2016, approximately 98.4 MMBOE of our total estimated proved reserves were undeveloped. The reserve data included in our reserve reports assumes that substantial capital expenditures will be made to develop non-producing reserves. The calculation of our estimated net proved reserves as of December 31, 2016 assumes that we will spend $634.5 million, including plugging and abandonment costs, to develop our estimated PUDs, including an estimated $189.4 million during 2017. Although cost and reserve estimates attributable to our 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 our 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, continued declines in commodity prices will reduce the future net revenues of our PUDs and may result in some projects becoming uneconomical. As a result of depressed oil and natural gas prices, we reduced the budgeted capital expenditures for the development of undeveloped reserves in 2016. These delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. Further, our 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 our 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:

• increased responsibilities for our executive level personnel;

• increased administrative burden;

• increased capital requirements; and

• increased organizational challenges common to large, expansive operations.

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

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

• the results of our drilling program;

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• hydrocarbon prices;

• our ability to develop existing prospects;

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

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

• our ability to identify and acquire new exploratory prospects;

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

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

• our access to capital.

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 NGLs we produce.

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

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.

In the future we may 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

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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, our partnership agreement, our senior secured revolving credit facility and the indenture governing the notes impose certain limitations on our ability to enter into mergers or combination transactions. Our partnership agreement, senior secured revolving credit facility and the indenture governing the notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

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:

• damages to equipment caused by natural disasters such as earthquakes and adverse weather conditions, including tornadoes and flooding;

• facility or equipment malfunctions;

• pipeline or tank ruptures or spills;

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

• fires, blowouts, craterings and explosions; and

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

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

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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.

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

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

• emission of GHGs and limitations on hydraulic fracturing;

• pressure or irregularities in geological formations;

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

• equipment failures, accidents or other unexpected operational events;

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

• lack of available capacity on interconnecting transmission pipelines;

• adverse weather conditions;

• issues related to compliance with environmental regulations;

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

• declines in oil and natural gas prices;

• limited availability of financing at acceptable terms;

• title problems; and

• limitations in the market for oil and natural gas.

Our hedging activities could result in financial losses or could reduce our net income.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have entered and may continue to enter into hedging arrangements for a significant portion of our production. As of June 30, 2017, we have hedged approximately 56% of our total forecasted PDP production through 2019 at weighted average floor prices ranging from $3.17 per MMBtu to $4.43 per MMBtu for natural gas and $49.55 per Bbl to $51.67 per Bbl for oil, with the majority of the hedged volumes in 2017. 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.

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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.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a 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 decline 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 a 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, natural gas or NGLs and secure trained personnel.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. 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

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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.

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, 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 management’s practice, 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 will 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.

We are vulnerable to risks associated with operating in the inland waters region of South Louisiana.

Our operations and financial results could be significantly impacted by unique conditions in the inland waters region of South Louisiana because we explore and produce in that area. As a result of this activity, we are vulnerable to the risks associated with operating in the inland waters region of South Louisiana, including those relating to:

• adverse weather conditions and natural disasters;

• availability of required performance bonds and insurance;

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• oil field service costs and availability;

• compliance with environmental and other laws and regulations;

• new safety requirements, new regulations, increased costs of services and rig mobilizations, slowed issuance of permits for new wells and additional insurance costs and requirements;

• remediation and other costs resulting from oil spills or releases of hazardous materials; and

• failure of equipment or facilities.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We may have difficulty maintaining our historic levels of success in using current Oklahoma forced pooling process to increase our interests 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

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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 interests 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 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 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 our 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.

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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 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 Congress, 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 the 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 the FERC, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, 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

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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, the 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.

With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to produce evidence of the GHG emissions of the proposed pipeline’s customers. In August 2017, The U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, which required FERC to revise its environmental impact statement for the proposed pipeline to take into account GHG carbon emissions from downstream power plants using natural gas transported by the new pipeline. It is too early to determine the impacts of this Court decision, but it could be significant.

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 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. 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. In 2017, President Trump withdrew the United States from the Paris Agreement, but the Governors of various individual States in the United States announced their intention to continue their commitment to the Paris Agreement. As a result, 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

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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.

Hydraulic fracturing (other than that using diesel) is currently generally exempt from regulation under the SDWA’s 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 limitations 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, the Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in June 2016 a Wyoming federal judge struck down this final rule. On July 25, 2017, the BLM proposed to rescind these regulations. On September 21,

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2017, the U.S. Court of Appeals for the Tenth Circuit dismissed the litigation challenging the rule and vacated the district court’s opinion, essentially re-instating the rule, following the BLM’s proposal to rescind the rule in July 2017.

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, the U.S. 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 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 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

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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 and the Migratory Bird Treaty Act. 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 be forced to incur material additional costs. Moreover, our operations may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

Additionally, the U.S. Fish and Wildlife Service (“FWS”) may designate new or increased critical habitat areas that it believes are necessary for survival of threatened or endangered species, which designation could result in material restrictions to federal land use and private land use and could delay or prohibit land access or oil and 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.

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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 NGL prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor especially those required in horizontal drilling and completion. 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 “Business — Environmental and Occupational Safety and Health Matters” and “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 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 our business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. 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,

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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.

Our affiliates are not limited in their ability to compete with us for acquisition or drilling opportunities. This could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

The agreements governing the relationship between our affiliates do not prohibit our affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, our affiliates may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Riverstone, HPS and Bayou City are each part of a larger family of funds, which have significantly greater resources than we have, which may make it more difficult for us to compete for acquisition candidates if our affiliates were to compete against us.

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 in the STACK are in 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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Any significant reduction in our borrowing base under our senior secured revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our senior secured revolving credit facility if required as a result of a borrowing base redetermination.

Availability under our senior secured revolving credit facility is currently subject to a borrowing base of $315.0 million. See “Description of Certain Indebtedness — Senior Secured Revolving Credit Facility.” The borrowing base is subject to scheduled semiannual and other elective unscheduled borrowing base redeterminations and is based on the value of our oil and natural gas reserves as determined by the lenders under our senior secured revolving credit facility and other factors deemed relevant by our lenders. Declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our senior secured revolving credit facility. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial condition, results of operations and cash flows. Further, if the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Our borrowings under our senior secured revolving credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our senior secured revolving credit facility. Our senior secured revolving credit facility carries a floating interest rate based upon short-term interest rate indices. If interest rates increase, so will our interest costs, which may have a material adverse effect on our financial condition and results of operations. We may use interest rate hedges in an effort to mitigate this risk, but those efforts may not prove successful.

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

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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 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. If any of 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, (3) the elimination of the deduction for U.S. production activities and (4) 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, it is anticipated that the Trump administration will pass tax reform and it is possible that such legislation could negatively impact our U.S. federal income taxation. The 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.

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EXCHANGE OFFER

Purpose of the Exchange Offer

We sold old notes in transactions that were exempt from or not subject to registration requirements under the Securities Act. Accordingly, the old notes are subject to transfer restrictions. In general, you may not offer or sell the old notes unless either they are no longer subject to certain restrictions on transfer or the offer or sale is exempt from or not subject to registration under the Securities Act and applicable state securities laws.

In connection with the sale of the old notes, we entered into a registration rights agreement with the initial purchasers of the old notes. We are making the exchange offer to fulfill our contractual obligations under that agreement. A copy of the registration rights agreement has been filed as an exhibit to the registration statement of which this prospectus is a part. The exchange offer will be open for at least 20 business days.

Pursuant to the exchange offer, we will issue the new notes in exchange for old notes. The terms of the new notes are identical in all material respects to those of the old notes, except that the new notes (1) will not be subject to certain restrictions on transfer applicable to the old notes and (2) will not have registration rights or provide for any increase in the interest rate related to the obligation to register. See “Description of the New Notes” for more information on the terms of the new notes.

We are not making the exchange offer to, and will not accept tenders for exchange from, holders of old notes in any jurisdiction in which an exchange offer or the acceptance thereof would not be in compliance with the securities or blue sky laws of such jurisdiction. Unless the context requires otherwise, the term “holder” means any person whose old notes are held of record by The Depository Trust Company, or DTC, who desires to deliver such old notes by book-entry transfer at DTC.

We make no recommendation to the holders of old notes as to whether to tender or refrain from tendering all or any portion of their old notes pursuant to the exchange offer. In addition, no one has been authorized to make any such recommendation. Holders of old notes must make their own decision whether to tender pursuant to the exchange offer and, if so, the aggregate amount of old notes to tender after reading this prospectus and the letter of transmittal and consulting with their advisers, if any, based on their own financial position and requirements.

Each broker-dealer that receives new notes for its own account in exchange for old notes, where such securities were acquired by such broker-dealer as a result of market making activities or other trading activities, must acknowledge that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the new notes. See “Plan of Distribution.”

Resales of New Notes

Based on interpretations by the staff of the SEC, as described in no-action letters issued to third parties, we believe that new notes issued in the exchange offer in exchange for old notes may be offered for resale, resold or otherwise transferred by holders of the old notes without compliance with the registration and prospectus delivery provisions of the Securities Act, if:

• the new notes are acquired in the ordinary course of the holders’ business;

• the holders have no arrangement or understanding with any person to participate in the distribution of the new notes; and

• the holders are not “affiliates” of the Company within the meaning of Rule 405 under the Securities Act.

However, the SEC has not considered the exchange offer described in this prospectus in the context of a no-action letter. We cannot assure you that the staff of the SEC would make a similar determination with respect to

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the exchange offer as in the other circumstances. Each holder who wishes to exchange old notes for new notes will be required to represent that it meets the above three requirements.

Any holder who is an affiliate of ours or who intends to participate in the exchange offer for the purpose of distributing new notes or any broker-dealer who purchased old notes directly from us to resell pursuant to Rule 144A or any other available exemption under the Securities Act:

• may not rely on the applicable interpretations of the staff of the SEC mentioned above;

• will not be permitted or entitled to tender the old notes in the exchange offer; and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Unless an exemption from registration is otherwise available, any security holder intending to distribute new notes should be covered by an effective registration statement under the Securities Act. The registration statement should contain the selling security holder’s information required by Item 507 or 508, as applicable, of Regulation S-K under the Securities Act.

In addition, to comply with state securities laws, the new notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification, with which there has been compliance, is available. The offer and sale of the new notes to “qualified institutional buyers,” as defined under Rule 144A of the Securities Act, is generally exempt from registration or qualification under the state securities laws. We currently do not intend to register or qualify the sale of new notes in any state where an exemption from registration or qualification is required and not available.

Terms of the Exchange Offer

Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 5:00 p.m. New York City time on the expiration date. We will issue new notes in principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

As of the date of this prospectus, $500,000,000 in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Exchange Act and the rules and regulations of the SEC. Old notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the indenture relating to the notes.

We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

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If you tender old notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of old notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connecting with the exchange offer. It is important that you read the section labeled “— Fees and Expenses” for more details regarding fees and expenses incurred in the exchange offer.

We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the exchange offer.

Expiration Date

The exchange offer will expire at 5:00 p.m., New York City time, on November 27, 2017, unless, in our sole discretion, we extend it.

Extensions, Delays in Acceptance, Termination or Amendment

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension no later than 9:00 a.m., New York City time, on the first business day following the previously scheduled expiration date.

If any of the conditions described below under “— Conditions to the Exchange Offer” have not been satisfied, we reserve the right, in our sole discretion:

• to delay accepting for exchange any old notes,

• to extend the exchange offer, or

• to terminate the exchange offer,

by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

Any such delay in acceptance, extension, termination or amendment will be followed promptly by oral or written notice thereof to the registered holders of old notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we may extend the exchange offer. In the event of a material change in the exchange offer, including the waiver by us of a material condition, we will extend the exchange offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change.

Conditions to the Exchange Offer

We will not be required to accept for exchange, or exchange any new notes for, any old notes if the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting old notes for exchange in the event of such a potential violation.

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In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under “— Purpose and Effect of the Exchange Offer,” “— Your Representations to Us” and “Plan of Distribution” and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new notes under the Securities Act.

We expressly reserve the right to amend or terminate the exchange offer and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give prompt oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

In addition, we will not accept for exchange any old notes tendered and will not issue new notes in exchange for any such old notes if, at such time, any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939.

Procedures for Tendering

In order to participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

If you have any questions or need help in exchanging your notes, please call the exchange agent, whose contact information is set forth in “Prospectus Summary — The Exchange Offer — Exchange Agent.”

All of the old notes were issued in book-entry form, and all of the old notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the old notes may be tendered using the Automated Tender Offer Program (“ATOP”) instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

There is no procedure for guaranteed late delivery of the notes.

Determinations Under the Exchange Offer

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and

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conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the expiration date.

When We Will Issue New Notes

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

• a book-entry confirmation of such old notes into the exchange agent’s account at DTC; and

• a properly transmitted agent’s message.

Return of Old Notes Not Accepted or Exchanged

If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

Your Representations to Us

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

• any new notes that you receive will be acquired in the ordinary course of your business;

• you are not engaging in, and do not intend to engage in, and have no arrangement or understanding with any person or entity to participate in, the distribution of the new notes;

• you are not our “affiliate,” as defined in Rule 405 of the Securities Act; and

• if you are a broker-dealer that you will receive new notes for your own account in exchange for old notes that you acquired as a result of market-making activities or other trading activities and that you acknowledge that you will deliver a prospectus (or to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m. New York City time on the expiration date. For a withdrawal to be effective you must comply with the appropriate procedures of DTC’s ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any old notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under “— Procedures for Tendering” above at any time prior to 5:00 p.m., New York City time, on the expiration date.

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Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by facsimile, telephone, electronic mail or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

• all registration and filing fees and expenses;

• all fees and expenses of compliance with federal securities and state “blue sky” or securities laws;

• accounting fees, legal fees incurred by us, disbursements and printing, messenger and delivery services, and telephone costs; and

• related fees and expenses.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

Consequences of Failure to Exchange

If you do not exchange new notes for your old notes under the exchange offer, you will remain subject to the existing restrictions on transfer of the old notes. In general, you may not offer or sell the old notes unless the offer or sale is either registered under the Securities Act or exempt from the registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the old notes under the Securities Act.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes adjusted for any bond discount or premium, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

Other

Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

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USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in our outstanding indebtedness.

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SELECTED HISTORICAL FINANCIAL AND OTHER DATA

The following table presents our summary historical financial data for the periods indicated. The data as of and for the years ended December 31, 2016, 2015, 2014, 2013 and 2012 have been derived from our audited consolidated financial statements. The data as of and for the six months ended June 30, 2017 and 2016 have been derived from our unaudited condensed consolidated financial statements. For further information that will help you better understand the summary data, you should read this financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes and other financial information included elsewhere in this prospectus.

	Six Months Ended June 30,						Year Ended December 31,
	2017			2016			2016			2015			2014			2013			2012
	(unaudited)
	(in thousands)
Statement of Operations Data:
Operating revenues and other:
Oil, natural gas and natural gas liquids	$	154,932		$	91,689		$	210,293		$	241,284		$	431,125		$	374,450		$	294,981
Other revenues		202			301			415			682			1,003			1,207			4,567
Total operating revenues		155,134			91,990			210,708			241,966			432,128			375,657			299,548
Gain (loss) on sale of assets		—			3,731			3,542			67,781			87,520			(2,715	)		—
Gain on acquisition of oil and natural gas properties		1,626			—			—			—			—			—			—
Gain (loss) on derivative contracts		48,492			(27,478	)		(40,460	)		124,141			96,559			(17,150	)		19,751
Total operating revenues and other	$	205,252		$	68,243		$	173,790		$	433,888		$	616,207		$	355,792		$	319,299
Operating expenses:
Lease and plant operating expense		34,333			30,577			56,893			67,706			64,686			62,086			57,423
Marketing and transportation expense		12,900			2,887			13,326			4,030			9,134			8,364			11,624
Production and ad valorem taxes		6,107			5,126			10,750			15,131			28,214			26,369			23,485
Workover expense		3,398			2,515			4,714			6,511			8,961			13,679			12,740
Exploration expense		14,407			6,714			24,777			42,718			61,912			33,065			21,912
Depreciation, depletion and amortization		51,298			44,424			92,901			143,969			141,804			118,558			109,252
Impairment expense		29,124			13,319			16,306			176,774			74,927			143,166			96,227
Accretion expense		1,052			1,075			2,174			2,076			2,198			2,133			1,813
General and administrative expense		18,076			22,259			41,758			44,454			69,198			47,023			40,222
Total operating expenses		170,695			128,896			263,599			503,369			461,034			454,443			374,698
Income (loss) from operations		34,557			(60,653	)		(89,809	)		(69,481	)		155,173			(98,651	)		(55,399	)
Other expense:
Interest expense, net		(24,671	)		(33,634	)		(59,990	)		(61,750	)		(55,797	)		(55,064	)		(41,833	)
Litigation settlement		—			—			—			—			—			—			1,250
Loss on extinguishment of debt		—			—			(18,151	)		—			—			—			—
Total other expense		(24,671	)		(33,634	)		(78,141	)		(61,750	)		(55,797	)		(55,064	)		(40,583	)
Provision (benefit) for state income taxes		285			107			(29	)		562			176			—			(107	)
Income (loss) from continuing operations		9,601			(94,394	)	$	(167,921	)	$	(131,793	)	$	99,200			(153,715	)		(95,875	)
Statement of Cash Flow Data:
Capital expenditures	$	151,832		$	94,997		$	214,061		$	223,604		$	366,090		$	311,438		$	224,719
Net cash flow provided by (used in) operating activities		(6,593	)		(46,919	)		131,376			143,978			184,884			172,519			147,193
Net cash used in investing activities		(158,083	)		(93,639	)		(224,298	)		(105,815	)		(189,721	)		(336,147	)		(255,065	)
Net cash provided by (used in) financing activities		162,770			141,136			91,238			(30,643	)		(351	)		164,379			111,028
Balance Sheet Data (at period end):
Cash and cash equivalents	$	5,279		$	9,447		$	7,185		$	8,869		$	1,349		$	6,537		$	5,786
Property and equipment, net		832,188			566,702			721,893			537,039			697,681			700,870			655,497
Total assets		957,002			790,210			813,851			722,525			911,125			785,300			772,522
Total debt, including Founder Notes		713,082			887,846			556,862			743,523			785,682			782,008			614,071
Total equity holders’ capital (deficit)		41,707			(271,443	)		32,106			(177,049	)		(61,446	)		(160,107	)		(6,368	)

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratios of earnings to fixed charges for the periods presented (unaudited):

	Six Months Ended June 30, 2017		Year Ended December 31,
			2016		2015		2014		2013		2012
Ratio of earnings to fixed charges(1)		1.39		—		—		2.76		—		—

(1) The ratio of earnings to fixed charges is calculated by dividing (i) earnings by (ii) fixed charges. Earnings consist of pre-tax income from continuing operations before fixed charges. Fixed charges consist of interest expense, including amortization of discount on the notes, amortization of capitalized costs related to debt, and an estimate of the interest within rental expense. Earnings were inadequate to cover fixed charges for the years ended December 31, 2016, 2015, 2013 and 2012 by $168 million, $132 million, $154 million and $96 million, respectively.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial and Other Data” and the financial statements and related notes included elsewhere in this prospectus. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements”, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. The historical financial information discussed below in this Management’s Discussion and Analysis of Financial Condition and Results of Operations represents Alta Mesa’s financial information for the periods indicated.

Overview

We have been engaged in the onshore oil and natural gas acquisition, exploitation, exploration and production in the United States since 1987. Currently, we are focusing on the development and acquisition of unconventional oil and natural gas reserves in the STACK. We have transitioned our focus from our diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities. 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. 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. We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners.

The amount of revenue we generate from our operations will fluctuate based on, among other things:

• the prices at which we will sell our production;

• the amount of oil, natural gas and natural gas liquids we produce; and

• the level of our operating and administrative costs.

In order to mitigate the impact of changes in oil, natural gas and natural gas liquids prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to enter into such transactions in the future to reduce the effect of price volatility on our cash flows.

Substantially all of our oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect our proportionate interest in such activities. Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our consolidated results of operations in the future.

Recent Developments

Contribution Agreement

On August 16, 2017, we entered into a Contribution Agreement (the “AM Contribution Agreement”) with Silver Run Acquisition Corporation II, a Delaware corporation (“SRII”), High Mesa Holdings, LP, a Delaware

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limited partnership (the “AM Contributor” or “HMH”), High Mesa Holdings GP, LLC, a Texas limited liability company, our General Partner and solely for certain provisions therein, the equity owners of AM Contributor. Pursuant to the AM Contribution Agreement, SRII will acquire from the AM Contributor (i) all of its limited partner interest in the Company and (ii) 100% of the economic interests and 90% of the voting interests in our General Partner. In return, the AM Contributor will receive: (i) 220,000,000 common units (the “Common Units”) as adjusted of SRII Opco, LP, a Delaware limited partnership (“SRII Opco”) and wholly owned subsidiary of SRII; (ii) $400 million in cash, which shall be contributed to us; and (iii) up to $800 million in earn-out consideration in the form of common units of SRII Opco, LP (the “Earn-out Consideration”). At closing, the Common Units will be adjusted (i) upward for any inorganic acquisition capital expenditures invested by us during the interim period (based on a value of $10.00 per Common Unit), (ii) downward for the $200 million contribution to Alta Mesa by Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “RS Contributor” or “Riverstone”), which was made in connection with the parties entering into the Contribution Agreements (based on a value of $10.00 per SRII Opco Common Unit), and (iii) downward for debt and transaction expenses (based on a value of $10.00 per SRII Opco Common Unit). The Earn-out Consideration will be paid as set forth below if the 20-day volume-weighted average price (“VWAP”) of the Class A Common Stock of SRII (the “Class A Common Stock”) equals or exceeds the following prices:

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

Additionally, the AM Contributor will purchase non-economic capital stock of SRII, dedicated as Class C Common Stock (“Class C Common Stock”). The common units of SRII Opco, LP and corresponding Class C Common Stock are redeemable for Class A Common Stock beginning 180 days after the closing.

Simultaneous with the execution of the AM Contribution Agreement, SRII entered into (i) a Contribution Agreement (the “KFM Contribution Agreement”) with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher” or “KFM”), and, solely for certain provisions therein, the equity owners of the KFM Contributor, pursuant to which SRII will acquire 100% of the outstanding membership interests in Kingfisher (the “KFM Contribution”); and a contribution agreement (the “RS Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with the RS Contributor pursuant to which SRII will acquire from the RS Contributor all of its limited partner interests in Alta Mesa.

The acquisition of Alta Mesa and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “business combination.”

In connection with the execution of the RS Contribution Agreement, the RS Contributor made a $200 million capital contribution to us, in exchange for limited partner interests. Additionally, pursuant to that certain forward purchase agreement between SRII and Riverstone SR, dated as of August 16, 2017, Riverstone SR has agreed to purchase up to $200 million shares of SRII Class A Common Stock in order to consummate the business combination.

The AM Contribution Agreement contains customary representations and warranties and pre-closing covenants, with the representations and warranties not survive the closing. Additionally, we have agreed to transfer to the AM Contributor prior to closing all assets and liabilities related to the non-STACK assets. The closing of the AM Contribution Agreement is subject to (i) the approval of the SRII stockholders; (ii) the simultaneous closing of the KFM Contribution Agreement and the RS Contribution Agreement; (iii) a SRII Opco leverage ratio of less than 1.5x; (iv) certain regulatory approvals; and (v) the satisfaction or waiver of other

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customary closing conditions. The Contribution Agreement also contains certain customary termination rights, including if the transaction is not consummated by February 28, 2018.

The notes will continue to be obligations of the Issuers pursuant to the terms of the indenture dated December 8, 2016, after completion of the business combination.

Sixth Amended and Restated Agreement of Limited Partnership

On August 16, 2017, our General Partner, the AM Contributor and the RS Contributor entered into a Sixth Amended and Restated Agreement of Limited Partnership of Alta Mesa (the “Amended Partnership Agreement”). The Amended Partnership Agreement reflects, among other things, certain changes in the ownership of Alta Mesa, and provides for certain preemptive rights, tag-along rights, and drag-along rights for the limited partners. In connection with Amended Partnership Agreement, the existing limited partners of Alta Mesa transferred their interests in Alta Mesa to the AM Contributor. The Amended Partnership Agreement also reflects the admission of the RS Contributor and the AM Contributor to Alta Mesa as limited partners, and provides for certain distribution rights for the Class A and Class B Limited Partners (as defined therein) with respect to the STACK and non-STACK assets.

The RS Contributor was admitted as a limited partner in connection with its $200 million capital contribution to us on August 17, 2017, in exchange for limited partner interests in Alta Mesa. We used all of the capital contribution to pay down our senior secured revolving credit facility.

Fifth Amended and Restated Limited Liability Company Agreement

On August 16, 2017, the owners of our General Partner entered into a Fifth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, show certain changes in the ownership of our General Partner and reflect that the holders of Class A Units (as defined therein) are entitled to 100% of the economic rights with respect to our General Partner and the holders of Class B Units (as defined therein) are entitled to 100% of the voting rights with respect to our General Partner.

Outlook, Market Conditions and Commodity Prices

Our revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, natural gas and natural gas liquids, which are beyond our control. The relatively low level of natural gas prices prompted our shift in emphasis to oil and natural gas liquids over the past several years. Accordingly, the success of our business is significantly affected by the price of oil due to our current focus on development of oil reserves. Oil prices are subject to significant changes. Beginning in the third quarter of 2014, the price for oil began a dramatic decline, and current prices for oil are significantly less than they have been historically. Factors affecting the oil prices include 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. Sustained low prices for oil, natural gas and natural gas liquids could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of our borrowing base under our senior secured revolving credit facility.

During the twelve month period ended June 30, 2017, NYMEX West Texas Intermediate (“NYMEX WTI”) oil prices ranged from a high of $53.46 per Bbl in February 2017 to a low of $44.80 per Bbl in August 2016. During the second quarter of 2017, NYMEX WTI prices averaged approximately $48.28 per Bbl compared to $45.59 per Bbl for the same period of 2016. We received an average price of $47.18 per Bbl for the second quarter of 2017 before the effects of hedging. NYMEX Henry Hub natural gas prices (“NYMEX HH”) have also

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been volatile and ranged from a high of $3.93 per MMBtu in January 2017 to a low of $2.63 in March 2017. We received an average price of $2.64 per Mcf for natural gas in the second quarter of 2017 before the effects of hedging. On September 25, 2017, NYMEX WTI was $52.22 per Bbl and NYMEX HH was $2.92 per Mcf. Commodity prices remain volatile and unpredictable but have improved during 2017 compared to the second half of 2016.

We have increased our anticipated capital expenditures, including acquisitions, for 2017 to $363 million, which is 61% over the $226 million of capital expenditures, including acquisitions made in 2016. Additionally, we anticipate that up to an additional $108 million will be funded for 2017 drilling and completions activity in the STACK by BCE-STACK Development LLC (“BCE”) pursuant to our joint development agreement. We have allocated over 95% of our 2017 capital expenditure to develop the STACK. We anticipate operating up to seven drilling rigs by the end of 2017, which will result in drilling a total of approximately 120 gross wells in the STACK in 2017. Of the total anticipated gross wells to be drilled in 2017, we plan to drill approximately 32 gross wells as part of our joint development agreement with BCE.

Our derivative contracts are reported at fair value on our condensed consolidated balance sheets and are sensitive to changes in the price of oil, natural gas and natural gas liquids. Changes in these derivative assets and liabilities are reported in our condensed consolidated statements of operations as gain (loss) on derivative contracts, which include both the non-cash increase and decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. In the first six months of 2017, we recognized a net gain on our derivative contracts of $48.5 million, which includes $0.3 million in cash settlements received on derivative contracts. The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil, natural gas and natural gas liquids revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and these gains and losses will continue to reflect changes in oil, natural gas and natural gas liquids prices.

As of June 30, 2017, we have hedged approximately 56% of our forecasted production of proved developed producing reserves through 2019 at weighted average floor prices ranging from $3.17 per MMBtu to $4.43 per MMBtu for natural gas and $49.55 per Bbl to $51.67 per Bbl for oil. If oil, natural gas and natural gas liquids prices decline for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional oil, natural gas and natural gas liquids production at favorable prices.

Depressed oil, natural gas and natural gas liquids prices have impacted our earnings by necessitating impairment write-downs in some of our oil and natural gas properties, either directly by decreasing the market values of the properties, or indirectly, by lowering rates of return on oil and natural gas development projects and increasing the chance of impairment write-downs. We recorded total non-cash impairment expenses of $29.1 million and $13.3 million for the six months ended June 30, 2017 and 2016, respectively. Approximately $18.8 million of the total impairment expense in the first six months of 2017 were to unproved property. In the first six months of 2017 and 2016, write-downs were primarily due to downward revisions in proved reserves and the effects of decreased prices for oil, natural gas and natural gas liquids on producing wells and undeveloped acreage in certain non-STACK fields. In the first six months of 2017 and 2016, our impairments were primarily related to our non-STACK properties. Further declines in oil and/or natural gas prices may result in additional impairment expenses.

The primary factors affecting our production levels are capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped reserves, enhanced completions and well recompletions, and other enhanced recovery methods. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to

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timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, exploration and development activities, and to satisfy our contractual obligations, primarily for the payment of debt interest and any amounts owed during the period related to our hedging positions.

Our 2016 capital budget was primarily focused on the development of our STACK and Weeks Island Area properties through exploitation and development. We spent approximately $226 million in 2016 for exploration and development, including acquisitions, of which over 90% was allocated to our STACK operations and the Weeks Island Areas. The revised capital expenditures for 2016 reflected our plans to drill wells that were funded through the joint development agreement with BCE for the remainder of the year. We reduced our capital expenditures for 2016 from 2015 levels in response to the continued depressed oil prices and to preserve liquidity.

Our 2017 capital budget is primarily focused on the development of our STACK play. Currently, we plan to spend approximately $363 million in 2017, which includes acquisitions, of which over 95% is allocated to develop our STACK properties. Additionally, we anticipate that up to an additional $108 million will be funded for 2017 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement. We have expended approximately $158.1 million of our capital budget through June 30, 2017. Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including the consummation of the transactions under the Contribution Agreement, drilling results, oil, natural gas and natural gas liquids prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production, revenues and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations. However, because a large percentage of our acreage is held by production, we have the ability to materially increase or decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage. In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

We funded our 2016 capital expenditures predominantly with cash flows from operations, drilling and completion of capital funded through our joint development agreement with BCE and capital contributions from High Mesa, Inc., supplemented by borrowings under our senior secured revolving credit facility and the issuance of the old notes. In connection with the final sale of preferred stock to Bayou City in October 2016, High Mesa, Inc. contributed $300 million from the Bayou City investment to us. In November 2016, we repaid all amounts outstanding under our senior secured term loan facility with such proceeds and paid down amounts owed under our senior secured revolving credit facility, providing us with additional liquidity.

We expect to fund our 2017 capital budget predominantly with cash flows from operations, drilling and completion capital funded through our joint development agreement with BCE, capital contribution from RS Contributor and borrowings under our senior secured revolving credit facility. If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuances of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to facilitate drilling on our large

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undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

As we execute our business strategy, we will continually monitor the capital resources available to meet future financial obligations and planned capital expenditures. We believe our cash flows provided by operating activities, cash on hand and availability under our senior secured revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2017 development drilling activities. However, future cash flows are subject to a number of variables, including the level of oil, natural gas and natural gas liquids production and prices, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We cannot make assurances that operational and other needed capital will be available on acceptable terms, or at all.

On December 8, 2016, we and our wholly owned subsidiary Alta Mesa Finances Services Corp., issued $500.0 million in aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024 at par (the “old notes”), which resulted in aggregate net proceeds to us of $491.3 million, after deducting commission offering expenses. We used the proceeds from the issuance of the old notes to fund the repurchase of the outstanding 9.625% senior unsecured notes due 2018 (“2018 Notes”) pursuant to a tender offer and the redemption of any of the 2018 Notes that remained outstanding after consummation of the tender offer. The remainder of the proceeds were used to repay a portion of our indebtedness under our senior secured revolving credit facility. Pursuant to the terms of the exchange offer described in this prospectus, we are offering to exchange the old notes for an identical principal amount of new notes.

In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. On June 13, 2017, we entered into an Agreement and Amendment No. 2 (the “Second Amendment”) to the credit facility which, among other things: (a) increased our borrowing base from $287.5 million to $315.0 million until the next scheduled redetermination and (b) permits us to make a one-time cash distribution of no more than $1.0 million to a limited partner. As of June 30, 2017, we had $195.7 million outstanding with $114.0 million of available borrowing capacity under the credit facility. The letters of credit outstanding as of June 30, 2017 and December 31, 2016 were approximately $5.3 million and $7.6 million, respectively. The borrowing base is currently $315.0 million and is redetermined semi-annually in May and November of each year. The principal amount is payable on the maturity date of November 10, 2020.

The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association. The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00. The Reference Rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s Reference Rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00. The weighted average and effective interest rate on outstanding borrowings was 5.90% as of June 30, 2017 and 4.00% as of December 31, 2016.

The credit facility includes covenants requiring that we maintain certain financial covenants including a modified current and a leverage ratio. As of June 30, 2017, we were in compliance with all financial covenants of the credit facility. See “Description of Certain Indebtedness — Senior Secured Revolving Credit Facility.”

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Cash Flows Provided by Operating Activities

Operating activities used cash of $6.6 million during the six months ended June 30, 2017 as compared to cash used by operating activities of $46.9 million during the comparable period in 2016, an increase in cash of $40.3 million. The increase in operating cash flows was attributable to various factors. Cash-based items of net income (loss), including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $10.1 million in the first six months of 2017. Changes in restricted cash, working capital and other assets and liabilities resulted in an increase of $50.4 million in the first six months of 2017 as compared to the corresponding period in 2016.

Operating activities provided cash of $131.4 million in 2016, as compared to $144.0 million in 2015. The $12.6 million decrease in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $36.1 million in earnings and a negative impact on cash flow. The changes in our working capital accounts provided $27.8 million in cash as compared to having provided $4.5 million in cash in 2015.

Operating activities provided cash of $144.0 million in 2015, as compared to $184.9 million in 2014. The $40.9 million decrease in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $43.2 million in earnings and a negative impact on cash flow. The changes in our working capital accounts provided $4.5 million as compared to having provided $2.2 million in cash in 2014.

Cash Flows Used in Investing Activities

Investing activities used cash of $158.1 million during the six months ended June 30, 2017 as compared to $93.6 million during the comparable period of 2016. Capital expenditures for property and equipment, including acquisitions used cash of $158.1 million and $95.0 million in the first six months of 2017 and 2016, respectively. Sales of properties provided proceeds of $1.4 million in the first six months of 2016.

Investing activities used cash of $224.3 million for the year ended December 31, 2016 as compared to $105.8 million for the year ended December 31, 2015. The increase in cash used in investing activities was primarily related to proceeds from the sale of property in 2015 of approximately $141.4 million. The increase in cash used for investing activities was partially offset by decreased expenditures for drilling and development and decreased acquisitions in 2016.

Investing activities used cash of $105.8 million for the year ended December 31, 2015 as compared to $189.7 million for the year ended December 31, 2014. The decrease in cash used in investing activities was primarily related to decreased expenditures for drilling and development, partially offset by lower proceeds from the sale of assets and an increase in acquisitions. In 2015, the sale of the remaining portion of our interest in the Eagleville field provided net proceeds of approximately $115.0 million and the acquisition of undeveloped leasehold interests in Oklahoma resulted in a use of cash of $47.4 million. In addition, release of non-invested funds in the restricted cash account, provided cash of $24.6 million in 2015.

Cash Flows Provided by Financing Activities

Financing activities provided cash of $162.8 million during the six months ended June 30, 2017 as compared to $141.1 million during the comparable period in 2016. During the first six months of 2017, we increased our borrowings under our credit facility by approximately $155.1 million (net), and paid $0.2 million of deferred financing costs related to our credit facility and notes. In addition, we received $7.9 million in capital

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contributions from High Mesa, Inc. In the first six months of 2016, we drew down $141.9 million on our credit facility and deposited the cash in a controlled account pursuant to the Thirteenth Amendment of our credit facility. In addition, we paid $0.8 million of deferred financing costs related to our credit facility.

Financing activities provided cash of $91.2 million during 2016 as compared to cash used of $30.6 million during 2015, an increase of $121.8 million. During 2016, we used proceeds from the issuance of the old notes of $500.0 million, capital contributions from High Mesa, Inc. of $303.5 million and borrowings under our senior secured revolving credit facility of $222.6 million to repay $459.4 million on the 2018 Notes, repay $127.7 million on our senior secured term loan facility and pay down $333.9 million under our senior secured revolving credit facility. In addition, we incurred $13.7 million of deferred financing costs.

Financing activities used cash of $30.6 million during 2015 as compared to $0.4 million during 2014, an increase of $30.2 million. During 2015, we used proceeds from the sale of our remaining interests in Eagleville properties of $115.0 million and proceeds from the issuance of our senior secured term loan facility of $121.0 million, net of issuance cost to reduce the outstanding balance under our senior secured revolving credit facility by $295.0 million. We received $252.5 million in proceeds from long-term debt consisting of $125.0 million under our senior secured term loan facility and $127.5 million in borrowings under our senior secured revolving credit facility. We made capital distributions of $3.8 million in 2015 as compared to a capital distribution of $0.5 million in 2014. We received capital contributions of $20 million from High Mesa, Inc. in 2015. No contributions were received in 2014. We incurred $4.3 million of deferred financing cost in 2015 related to the borrowing of our senior secured term loan facility.

Results of Operations: Six Months Ended June 30, 2017 v. Six Months Ended June 30, 2016

	Six Months Ended June 30,					Increase (Decrease)
	2017			2016					% Change
	(in thousands, except average sales prices and unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		2,363			2,041		322			16	%
Natural gas (MMcf)		9,285			6,144		3,141			51	%
Natural gas liquids (MBbls)		646			438		208			47	%
Total oil equivalent (MBOE)		4,557			3,502		1,055			30	%
Average daily oil production (MBOE per day)		25.2			19.2		6.0			30	%
Average Sales Price:
Oil (per Bbl) including settlements of derivative contracts	$	48.38		$	66.57	$	(18.19	)		(27	)%
Oil (per Bbl) excluding settlements of derivative contracts		48.41			36.79		11.62			32	%
Natural gas (per Mcf) including settlements of derivative contracts		2.86			2.56		0.30			12	%
Natural gas (per Mcf) excluding settlements of derivative contracts		2.78			1.71		1.07			63	%
Natural gas liquids (per Bbl) including settlements of derivative contracts		22.14			13.98		8.16			58	%
Natural gas liquids (per Bbl) excluding settlements of derivative contracts		22.74			13.97		8.77			63	%
Combined (per BOE) including settlements of derivative contracts		34.06			45.02		(10.96	)		(24	)%
Combined (per BOE) excluding settlements of derivative contracts		34.00			26.18		7.82			30	%
Hedging Activities:
Settlements of derivatives (paid) received, oil	$	(81	)	$	60,775	$	(60,856	)		(100	)%
Settlements of derivatives received, natural gas		725			5,212		(4,487	)		(86	)%
Settlements of derivatives (paid) received, natural gas liquids		(391	)		5		(396	)		NA

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	Six Months Ended June 30,					Increase (Decrease)
	2017		2016						% Change
	(in thousands, except average sales prices and unit costs)
Summary Financial Information
Revenues and other
Oil	$	114,416	$	75,087		$	39,329			52	%
Natural gas		25,821		10,487			15,334			146	%
Natural gas liquids		14,695		6,115			8,580			140	%
Other revenues		202		301			(99	)		(33	)%
Gain on sale of assets		—		3,731			(3,731	)		(100	)%
Gain on acquisition of oil and natural gas properties		1,626		—			1,626			NA
Gain (loss) on derivative contracts		48,492		(27,478	)		75,970			276	%
Total Operating Revenues and Other		205,252		68,243			137,009			201	%
Expenses
Lease and plant operating expense		34,333		30,577			3,756			12	%
Marketing and transportation expense		12,900		2,887			10,013			347	%
Production and ad valorem taxes		6,107		5,126			981			19	%
Workover expense		3,398		2,515			883			35	%
Exploration expense		14,407		6,714			7,693			115	%
Depreciation, depletion, and amortization expense		51,298		44,424			6,874			15	%
Impairment expense		29,124		13,319			15,805			119	%
Accretion expense		1,052		1,075			(23	)		(2	)%
General and administrative expense		18,076		22,259			(4,183	)		(19	)%
Interest expense, net		24,671		33,634			(8,963	)		(27	)%
Provision for state income taxes		285		107			178			166	%
Net Income (loss)	$	9,601	$	(94,394	)	$	(103,995	)		(110	)%
Average Unit Costs per BOE:
Lease and plant operating expense	$	7.53	$	8.73		$	(1.20	)		(14	)%
Marketing and transportation expense		2.83		0.82			2.01			245	%
Production and ad valorem tax expense		1.34		1.46			(0.12	)		(8	)%
Workover expense		0.75		0.72			0.03			4	%
Exploration expense		3.16		1.92			1.24			65	%
Depreciation, depletion and amortization expense		11.26		12.69			(1.43	)		(11	)%
General and administrative expense		3.97		6.36			(2.39	)		(38	)%

Revenues

Oil revenuesin the six months ended June 30, 2017 increased $39.3 million, or 52%, to $114.4 million from $75.1 million in the corresponding period in 2016. The increase in revenue was primarily attributable to an increase in average price as well as an increase in production. The average price of oil exclusive of derivative contract settlements increased $11.62 per Bbl or 32% in the first six months of 2017 compared to the first six months of 2016, resulting in an increase in oil revenues of approximately $27.4 million. When including the effects of derivative contract settlements, the overall price decreased 27% from $66.57 per Bbl in the first six months of 2016 to $48.38 per Bbl in the first six months of 2017. The overall price included settlement of oil derivative contracts prior to contract expiry of approximately $0.9 million in the first six months of 2017 compared to $37.8 million of similar settlements of oil derivative contracts in the corresponding period in 2016. Production increased 322 MBbls, resulting in an increase of $11.9 million in oil revenues. The oil production volume increase is primarily due to new production from wells coming online in the STACK of 624 MBbls, partially offset by a decrease in production in the Weeks Island Area of 261 MBbls due to a natural decline in production.

Natural gas revenuesin the six months ended June 30, 2017 increased $15.3 million, or 146%, to $25.8 million from $10.5 million in the same period in 2016. The increase in natural gas revenue was primarily attributable to an increase in average price as well as an increase in production during the first six months of

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2017. The average price of natural gas exclusive of derivative contract settlements increased $1.07 per Mcf in the first six months of 2017, resulting in an increase in natural gas revenues of approximately $10.0 million. When including the effects of derivative contract settlements, the overall price increased 12% from $2.56 per Mcf in the first six months of 2016 to $2.86 Mcf in the first six months of 2017. The overall price in the second quarter of 2016 includes $2.4 million we received related to settlement of several of our natural gas derivative contracts prior to contract expiry. Production increased 3.1 Bcf resulting in an increase of $5.3 million in natural gas revenues. The natural gas volume increase is primarily due to new production from wells coming online in the STACK of 3.8 Bcf as natural gas is produced in association with oil.

Natural gas liquids revenuesincreased $8.6 million, or 140%, during the first six months of 2017 to $14.7 million from $6.1 million in the same period in 2016. The increase in natural gas liquids revenue was attributable to an increase in higher average price as well as an increase in processed volumes during the first six months of 2017. The average price of natural gas liquids exclusive of derivative contract settlements increased $8.77 per Bbl or 63% in the first six months of 2017 compared to the first six months of 2016, resulting in an increase in natural gas liquids revenues of $5.7 million. The overall price including derivative contract settlements increased 58% from $13.98 per Bbl in the first six months of 2016 to $22.14 per Bbl in the first six months of 2017. Production increased 208 MBbls from 438 MBbls to 646 MBbls, resulting in an increase of $2.9 million in natural gas liquids revenue. The natural gas liquids volume is predominately in the STACK where natural gas liquids processed volumes increased 214 MBbls.

Gain on sale of assets was a gain of $3.7 million in the first six months of 2016, primarily due to the sale of certain non-core assets.

Gain on acquisition of oil and natural gas properties was a gain of $1.6 million in the first six months of 2017, primarily related to the acquisition of additional working interests in certain non-STACK oil and natural gas properties at a purchase price below fair value.

Gain (loss) on derivative contractswas a gain of $48.5 million in the first six months of 2017 as compared to a loss of $27.5 million during the same period in 2016. The fluctuation from period to period is due to the volatility of oil, natural gas and natural gas liquid prices and changes in our outstanding hedge contracts during these periods. The $27.5 million loss in the first six months of 2016 is inclusive of $66.0 million in settlements received on derivative contracts of which $40.2 million were from settlements of oil and natural gas derivative contracts prior to contract expiry. The $48.5 million gain in the first six months of 2017 is inclusive of $0.3 million in settlements received on derivative contracts of which $0.9 million were from settlements of oil and natural gas derivative contracts prior to contract expiry.

Expenses

Lease and plant operating expenseincreased $3.7 million or 12% in the first six months of 2017 as compared to the first six months of 2016, to $34.3 million from $30.6 million. In general, there was an increase in compression, repairs and maintenance and salt water disposal fees of $3.8 million. On a per unit basis, lease and plant operating expense was $7.53 per BOE and $8.73 per BOE in the first six months of 2017 and 2016, respectively.

Marketing and transportation expenseincreased $10.0 million to $12.9 million in the first six months of 2017 as compared to $2.9 million in the first six months of 2016. The increase is primarily due to increased throughput for our properties in the STACK at the KFM processing facility commissioned during the second quarter of 2016. In addition, the increase is due to a higher marketing and transportation fee charged to provide effective gathering, efficient processing and assurance that our production will continue to flow as the activity in the basin expands at the KFM processing facility. On a per unit basis, marketing and transportation expense was $2.83 per BOE and $0.82 per BOE in the first six months of 2017 and 2016, respectively.

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Production and ad valorem taxesincreased $1.0 million, or 19%, to $6.1 million in the first six months of 2017, as compared to $5.1 million in the first six months of 2016. The increase is primarily due to an increase in production taxes as a result of the increase in oil, natural gas and natural gas liquids revenues. Production taxes increased from $4.4 million in the first six months of 2016 to $5.4 million in the first six months of 2017.

Workover expenseincreased $0.9 million during the first six months of 2017, as compared to the first six months of 2016. This expense varies depending on activities in the field and is attributable to several properties.

Exploration expenseincludes dry hole costs, the costs of our geology department, costs of geological and geophysical data, expired leases, plug and abandonment expenditures, and delay rentals. Exploration expense increased $7.7 million to $14.4 in the first six months of 2017, as compared to $6.7 million in the first six months of 2016. The increase is primarily due to an increase in expired leasehold and settlements of our asset retirement obligation in excess of our estimate of $6.1 million, and an increase in G&G seismic expense of $1.3 million.

Depreciation, depletion and amortization expenseincreased from $44.4 million in the first six months of 2016 to $51.3 million in the first six months of 2017. On a per unit basis, this expense decreased from $12.69 per BOE in the first six months of 2016 to $11.26 per BOE in the first six months of 2017. Depreciation, depletion, and amortization is a function of capitalized costs of proved properties, proved reserves and production by field. In addition, the impairment of proved properties in the second quarter of 2017 and in previous periods and an increase in proved reserves contributed to the lowered depletable base and rate in the first six months of 2017.

Impairment expenseincreased from $13.3 million in the first six months of 2016 to $29.1 million in the first six months of 2017. This expense varies with the results of exploratory and development drilling, as well as with well performance, declines in commodity price and other factors that may render some fields uneconomic, resulting in impairment. Impairment expense in the first six months of 2017 and 2016 were primarily write-downs in our non-STACK areas.

Accretion expenseis related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $1.1 million in each of the first six months of 2017 and 2016.

General and administrative expensedecreased $4.2 million in the first six months of 2017 to $18.1 million from $22.3 million in the first six months of 2016. The decrease is primarily due to a decrease in salary and benefits of $2.5 million including prior period performance bonus accrual adjustments, and a decrease in legal fees of $2.6 million, partially offset by an increase in IT and engineering consulting fees of $1.2 million. During the first six months of 2016, legal fees included non-recurring tender offer fees and debt restructuring fees of $1.9 million. On a per unit basis, general and administrative expenses were $3.97 per BOE and $6.36 per BOE in the first six months of 2017 and 2016, respectively.

Interest expense, netdecreased from $33.6 million in the first six months of 2016 to $24.7 million in the first six months of 2017. The interest on our senior unsecured notes decreased $2.2 million due to the repurchase and redemption of our $450 million aggregate principal amount of 9.625% senior unsecured notes due 2018 by issuing $500 million aggregate principal amount of 7.875% senior unsecured notes due 2024. In addition, interest on our senior secured revolving credit facility decreased $1.0 million due to a lower outstanding balance, and interest on our senior secured term loan decreased $5.4 million as we retired our $125 million secured term loan during the fourth quarter of 2016.

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Results of Operations: Year Ended December 31, 2016 v. Year Ended December 31, 2015

	Year Ended December 31,						Increase (Decrease)			% Change
	2016			2015
	(in thousands, except average sales prices and unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		4,001			4,203			(202	)		(5	)%
Natural gas (MMcf)		13,959			11,900			2,059			17	%
Natural gas liquids (MBbls)		956			678			278			41	%
Total oil equivalent (MBOE)		7,284			6,865			419			6	%
Average daily oil production (MBOE per day)		19.9			18.8			1.1			6	%
Average Sales Price:
Oil (per Bbl) including settlements of derivative contracts	$	61.53		$	67.73		$	(6.20	)		(9	)%
Oil (per Bbl) excluding settlements of derivative contracts		40.91			47.54			(6.63	)		(14	)%
Natural gas (per Mcf) including settlements of derivative contracts		2.68			4.43			(1.75	)		(40	)%
Natural gas (per Mcf) excluding settlements of derivative contracts		2.22			2.57			(0.35	)		(14	)%
Natural gas liquids (per Bbl) including settlements of derivative contracts(1)		16.04			16.01			0.03			N/A
Natural gas liquids (per Bbl) excluding settlements of derivative contracts(1)		16.38			16.01			0.37			2	%
Combined (per BOE) including settlements of derivative contracts		41.05			50.73			(9.68	)		(19	)%
Combined (per BOE) excluding settlements of derivative contracts		28.87			35.15			(6.28	)		(18	)%
Hedging Activities:
Settlements of derivatives received, oil	$	82,522		$	84,856		$	(2,334	)		(3	)%
Settlements of derivatives received, natural gas		6,500			22,093			(15,593	)		(71	)%
Settlements of derivatives (paid), natural gas liquids		(333	)		—			(333	)		N/A
Summary Financial Information
Operating Revenues and Other
Oil	$	163,677		$	199,799		$	(36,122	)		(18	)%
Natural gas		30,953			30,621			332			1	%
Natural gas liquids		15,663			10,864			4,799			44	%
Other revenues		415			682			(267	)		(39	)%
Gain on sale of assets		3,542			67,781			(64,239	)		(95	)%
Gain (loss) on derivative contracts		(40,460	)		124,141			(164,601	)		(133	)%
Total Operating Revenues and Other		173,790			433,888			(260,098	)		(60	)%
Expenses
Lease and plant operating expense		56,893			67,706			(10,813	)		(16	)%
Marketing and transportation expense		13,326			4,030			9,296			231	%
Production and ad valorem taxes		10,750			15,131			(4,381	)		(29	)%
Workover expense		4,714			6,511			(1,797	)		(28	)%
Exploration expense		24,777			42,718			(17,941	)		(42	)%
Depreciation, depletion, and amortization expense		92,901			143,969			(51,068	)		(35	)%
Impairment expense		16,306			176,774			(160,468	)		(91	)%
Accretion expense		2,174			2,076			98			5	%
General and administrative expense		41,758			44,454			(2,696	)		(6	)%
Interest expense, net		59,990			61,750			(1,760	)		(3	)%
Loss on extinguishment of debt		18,151			—			18,151			N/A
Provision for (benefit from) state income taxes		(29	)		562			(591	)		(105	)%
Net Loss	$	(167,921	)	$	(131,793	)	$	(36,128	)		(27	)%

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	Year Ended December 31,				Increase (Decrease)			% Change
	2016		2015
	(in thousands, except average sales prices and unit costs)
Average Unit Costs per BOE:
Lease and plant operating expense	$	7.81	$	9.86	$	(2.05	)		(21	)%
Marketing and transportation expense		1.83		0.59		1.24			210	%
Production and ad valorem tax expense		1.48		2.20		(0.72	)		(33	)%
Workover expense		0.65		0.95		(0.30	)		(32	)%
Exploration expense		3.40		6.22		(2.82	)		(45	)%
Depreciation, depletion and amortization expense		12.75		20.97		(8.22	)		(39	)%
General and administrative expense		5.73		6.48		(0.75	)		(12	)%

(1) We entered into derivative contracts for natural gas liquids in the fourth quarter of 2015. The derivative contracts for natural gas liquids became effective in 2016.

Revenues

Oil revenuesfor the year ended December 31, 2016 decreased $36.1 million, or 18%, to $163.7 million in 2016 from $199.8 million in 2015. The decrease in oil revenue was primarily attributable to lower prices as well as decreased production volumes. The average price of oil exclusive of settlements of derivative contracts decreased 14% in 2016 resulting in a decrease in oil revenues of approximately $26.5 million. The average price inclusive of settlements of derivative contracts decreased 9% from $67.73 per Bbl in 2015 to $61.53 per Bbl in 2016. A decrease in production of 202 MBbls, or 5% resulted in an approximate $9.6 million decrease in oil revenues. The decrease in oil volumes is primarily due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 of 430 MBbls and natural production decline at the Weeks Island Area of 293 MBbls. This decrease was partially offset by new production from the STACK, which increased 564 MBbls, from 2,006 MBbls in 2015 to 2,570 MBbls in 2016.

Natural gas revenuesfor the year ended December 31, 2016 increased $0.3 million, or 1%, to $30.9 million in 2016 from $30.6 million in 2015. The increase in natural gas revenue was attributable to increased production volumes partially offset by lower prices during 2016. An increase in production of 2.1 Bcf, or 17% resulted in an increase in natural gas revenues of approximately $5.3 million in 2016 as compared to 2015. The increase in natural gas volumes is attributable to new production from the STACK, which increased 3.9 Bcfe, from 4.3 Bcfe in 2015 to 8.2 Bcfe in 2016. This increase was partially offset by natural production decline at the Weeks Island Area of 825 MMcf and the sale of the remainder of our Eagleville properties in the third quarter of 2015 of 415 MMcf. The average price of natural gas exclusive of settlements of derivative contracts decreased 14% in 2016 resulting in a decrease in natural gas revenues of approximately $5.0 million. The average price inclusive of settlements of derivative contracts decreased 40% from $4.43 per Mcf in 2015 to $2.68 per Mcf in 2016.

Natural gas liquids revenuesfor the year ended December 31, 2016 increased $4.8 million, or 44% to $15.7 million in 2016 from $10.9 million in 2015. The increase in natural gas liquids revenue was primarily attributable to increased volumes as well as an increase in prices. An increase in volumes of 278 MBbls or 41% resulted in an increase in natural gas liquids revenue of $4.4 million in 2016 as compared to 2015. The increase in natural gas liquid volumes is due primarily to an increase in output in the STACK, which increased 324 MBbls, from 499 MBbls in 2015 to 823 MBbls in 2016. This increase was partially offset by lower volumes due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 of 84 MBbls. The average price of natural gas liquids exclusive of settlements of derivative contracts increased 2%, from $16.01 per Bbl in 2015 to $16.38 per Bbl in 2016 resulting in an increase in natural gas liquids revenue of $0.4 million.

Other revenues were $0.4 million during 2016 as compared to $0.7 million during 2015. The decrease is partially the result of a decrease in income from gas processing fees, as well as a decrease in pipeline revenue.

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Gain on sale of assets was a gain of $3.5 million in 2016 as compared to a gain of $67.8 million in 2015. The sale of South Louisiana properties in 2016 resulted in a gain of $3.5 million. The sale of our remaining Eagleville properties in the third quarter of 2015 resulted in a gain of $67.6 million.

Gain (loss) on derivative contractswas a loss of $40.5 million inclusive of derivative settlements received of $88.7 million in 2016 as compared to a gain of $124.1 million inclusive of derivative settlements received of $106.9 million in 2015. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedge contracts during these periods.

Expenses

Lease and plant operating expensedecreased $10.8 million to $56.9 million, or 16% in 2016 as compared to $67.7 million in 2015. The decrease is primarily due to lower salt water disposal costs, and a decrease in repairs, maintenance, and field services, totaling $10.3 million. On a per unit basis, lease and plant operating expense decreased 21% from $9.86 to $7.81 per BOE for 2015 and 2016, respectively.

Marketing and transportation expenseincreased $9.3 million to $13.3 million in 2016 as compared to $4.0 million in 2015. The increase is primarily in the STACK due to increased throughput at the KFM processing facility beginning in the second quarter of 2016. In addition, the increase is due to a higher marketing and transportation fee charged for utilizing a more efficient facility at the KFM plant. On a per unit basis, marketing and transportation expense increased from $0.59 to $1.83 per BOE for 2015 and 2016, respectively.

Production and ad valorem taxesdecreased $4.4 million to $10.7 million, or 29%, for 2016, as compared to $15.1 million for 2015. Production taxes decreased $4.3 million primarily due to the decrease in oil revenues. Ad valorem taxes decreased $0.1 million. On a per unit basis, the production and ad valorem taxes decreased from $2.20 to $1.48 per BOE for 2015 and 2016, respectively.

Workover expensedecreased $1.8 million to $4.7 million from $6.5 million for 2016 and 2015, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased $17.9 million to $24.8 million in 2016 from $42.7 million in 2015. The decrease in exploration expense is primarily due to decreases in dry hole expense of $22.3 million, partially offset by an increase in expired leasehold of $4.6 million. As of December 31, 2016, our property, plant, and equipment balance includes $2.1 million in exploratory well costs which are deferred, pending determination of proved reserves. Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes.

Depreciation, depletion and amortization decreased $51.1 million to $92.9 million for 2016 as compared to $144.0 million for 2015. On a per unit basis, this expense decreased 39% from $20.97 to $12.75 per BOE for 2015 and 2016, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense decreased $160.5 million to $16.3 million in 2016 from $176.8 million in 2015. This non-cash expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “— Critical Accounting Policies and Estimates — Property and Equipment — Impairment” below for more details related to impairment. Certain developed fields were impaired due to downward revisions in reserves based on lower commodity prices, performance or development drilling results that were below expectations. The impairments in 2016 were primarily due to write-downs in developed fields, most notably in the Northwest, East Texas and South Louisiana, totaling $15.4 million. The impairments in 2015 were primarily

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due to write-downs of both unproved oil and gas costs and developed fields, primarily the Weeks Island Area, the STACK, East Texas and South Louisiana, totaling $167.8 million.

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $2.2 million and $2.1 million in 2016 and 2015, respectively.

General and administrative expense decreased $2.7 million to $41.8 million in 2016 from $44.5 million in 2015. The decrease is primarily due to lower litigation settlement expenses recorded in 2016 as compared to 2015 of $5.3 million, partially offset by an increase in salaries, benefits and deferred compensation of $2.6 million in 2016. On a per unit basis, general and administrative expenses decreased 12% from $6.48 to $5.73 per BOE for 2015 and 2016, respectively.

Interest expense, netdecreased $1.8 million to $60.0 million in 2016 from $61.8 million in 2015. The decrease was primarily due to the tender and redemption of the 2018 Notes during the fourth quarter of 2016, which decreased interest costs. These decreases were partially offset by an increase in interest expense related to our senior secured revolving credit facility and senior term loan facility. The senior term loan facility was repaid in full during the fourth quarter of 2016. Interest expense incurred on our borrowings under our senior secured revolving credit facility increased $1.4 million due to an increase in average outstanding balance. Interest expense incurred on our borrowing under senior secured term loan facility increased $3.0 million as we recognized almost a full year of interest expense and additional amortized deferred financing costs of $0.3 million as compared to prior year. We entered into the senior secured term loan facility during the second quarter of 2015.

Loss on Extinguishment of Debt was $18.2 million in 2016. During the fourth quarter of 2016, we repurchased an aggregate principal amount of our $450 million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees. We recognized a loss related to the repurchase of $13.5 million, which included unamortized discount and unamortized deferred financing costs write-offs of $4.1 million. In addition, we repaid all amounts outstanding under the senior secured term loan facility of $127.7 million, which includes accrued interest and a prepayment premium of $2.5 million. We recognized a loss related to the repayment of $4.7 million, which included unamortized deferred financing costs write-offs of $2.0 million.

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Results of Operations: Year Ended December 31, 2015 v. Year Ended December 31, 2014

	Year Ended December 31,					Increase (Decrease)
	2015			2014					% Change
	(in thousands, except average sales prices and unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		4,203			3,770		433			11	%
Natural gas (MMcf)		11,900			14,449		(2,549	)		(18	)%
Natural gas liquids (MBbls)		678			537		141			26	%
Total oil equivalent (MBOE)		6,865			6,715		150			2	%
Average daily oil production (MBOE per day)		18.8			18.4		0.4			2	%
Average Sales Price:
Oil (per Bbl) including settlements of derivative contracts	$	67.73		$	93.38	$	(25.65	)		(27	)%
Oil (per Bbl) excluding settlements of derivative contracts		47.54			92.27		(44.73	)		(48	)%
Natural gas (per Mcf) including settlements of derivative contracts		4.43			4.87		(0.44	)		(9	)%
Natural gas (per Mcf) excluding settlements of derivative contracts		2.57			4.50		(1.93	)		(43	)%
Natural gas liquids (per Bbl) excluding settlements of derivative contracts(1)		16.01			34.04		(18.03	)		(53	)%
Combined (per BOE) including settlements of derivative contracts		50.73			65.62		(14.89	)		(23	)%
Combined (per BOE) excluding settlements of derivative contracts		35.15			64.20		(29.05	)		(45	)%
Hedging Activities:
Settlements of derivatives received, oil	$	84,856		$	4,187	$	80,669			1927	%
Settlements of derivatives received, natural gas		22,093			5,306		16,787			316	%
Summary Financial Information
Operating Revenues and Other
Oil	$	199,799		$	347,842	$	(148,043	)		(43	)%
Natural gas		30,621			65,002		(34,381	)		(53	)%
Natural gas liquids		10,864			18,281		(7,417	)		(41	)%
Other revenues		682			1,003		(321	)		(32	)%
Gain on sale of assets		67,781			87,520		(19,739	)		(23	)%
Gain on derivative contracts		124,141			96,559		27,582			29	%
Total Operating Revenues and Other		433,888			616,207		(182,319	)		(30	)%
Expenses
Lease and plant operating expense		67,706			64,686		3,020			5	%
Marketing and transportation expense		4,030			9,134		(5,104	)		(56	)%
Production and ad valorem taxes		15,131			28,214		(13,083	)		(46	)%
Workover expense		6,511			8,961		(2,450	)		(27	)%
Exploration expense		42,718			61,912		(19,194	)		(31	)%
Depreciation, depletion, and amortization expense		143,969			141,804		2,165			2	%
Impairment expense		176,774			74,927		101,847			136	%
Accretion expense		2,076			2,198		(122	)		(6	)%
General and administrative expense		44,454			69,198		(24,744	)		(36	)%
Interest expense, net		61,750			55,797		5,953			11	%
Provision for state income taxes		562			176		386			219	%
Net income (loss)	$	(131,793	)	$	99,200	$	(230,993	)		(233	)%

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	Year Ended December 31,				Increase (Decrease)
	2015		2014					% Change
	(in thousands, except average sales prices and unit costs)
Average Unit Costs per BOE:
Lease and plant operating expense	$	9.86	$	9.63	$	0.23			2	%
Marketing and transportation expense		0.59		1.36		(0.77	)		(57	)%
Production and ad valorem tax expense		2.20		4.20		(2.00	)		(48	)%
Workover expense		0.95		1.33		(0.38	)		(29	)%
Exploration expense		6.22		9.22		(3.00	)		(33	)%
Depreciation, depletion and amortization expense		20.97		21.12		(0.15	)		(1	)%
General and administrative expense		6.48		10.30		(3.82	)		(37	)%

(1) We entered into derivative contracts for natural gas liquids in the fourth quarter of 2015. The derivative contracts for natural gas liquids became effective in 2016.

Revenues

Oil revenuesfor the year ended December 31, 2015 decreased $148.0 million, or 43%, to $199.8 million from $347.8 million for 2014. The decrease in revenue was attributable to lower average prices partially offset by increased production volumes. The average price of oil exclusive of settlements of derivative contracts decreased 48% in 2015; the overall price including settlements of derivative contracts decreased 27% from $93.38 per Bbl in 2014 to $67.73 per Bbl in 2015 resulting in a decrease in oil revenues of approximately $188.0 million, partially offset by an increase in production of 433 MBbls, or 11% resulting in an approximately $40.0 million increase in oil revenues. This increase is primarily due to new production from the STACK, which increased 934 MBbls, from 1,072 MBbls in 2014 to 2,006 MBbls in 2015, partially offset by lower sales volume due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 and natural production decline at Weeks Island Area. Production from our Eagleville field decreased 383 MBbls from 815 MBbls in 2014 to 432 MBbls in 2015, and our Weeks Island Area decreased 61 MBbls from 1,505 MBbls in 2014 to 1,444 MBbls in 2015.

Natural gas revenuesfor the year ended December 31, 2015 decreased $34.4 million, or 53%, to $30.6 million from $65 million for 2014. The decrease in natural gas revenue was attributable to lower average prices during 2015 as well as decreased production volumes. The average price of natural gas exclusive of settlements of derivative contracts decreased 43% in 2015 resulting in a decrease in natural gas revenues of approximately $22.9 million. The overall price including settlements of derivative contracts decreased 9% from $4.87 per Mcf in 2014 to $4.43 per Mcf in 2015. A decrease in production of 2.5 Bcf, or 18% resulted in a decrease in natural gas revenues of approximately $11.5 million in 2015 compared to 2014. The decline is due to an emphasis on liquids-rich assets in our capital spending. The decrease in production is attributable to the sale of our remaining working interests in the Hilltop field in the third quarter of 2014. The Hilltop field produced 2.8 Bcf in 2014. In addition, production decreased 3.8 Bcf in East Texas and 0.6 Bcf in South Texas, partially offset by an increase in production in the STACK of 2.2 Bcf.

Natural gas liquids revenuesdecreased during 2015 to $10.9 million from $18.3 million for 2014. Our average price decreased by 53%, from $34.04 per Bbl in 2014 to $16.01 per Bbl in 2015, partially offset by a 26% increase in volumes from 537 MBbls in 2014 to 678 MBbls in 2015. The decline in prices is due to increased supply of natural gas liquids as a result of increased liquids-targeted drilling. The increase in volume is due primarily to an increase in production in the STACK during 2015 of 184 MBbls, partially offset by lower sales volumes due to the sale of the remainder of our Eagleville properties in the third quarter of 2015.

Other revenues were $0.7 million during 2015 as compared to $1.0 million during 2014. The decrease is partially the result of a decrease in income from gas processing fees, as well as a decrease in pipeline revenue.

Gain on sale of assets was a gain of $67.8 million in 2015 as compared to a gain of $87.5 million in 2014. The divestiture of our remaining Eagleville properties in 2015 resulted in a gain of $67.6 million. The divestiture

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of a portion of our oil and gas properties in Eagleville field and the divestiture of the remainder of our Hilltop Field properties during 2014 resulted in a gain of $72.5 million and $15.9 million, respectively.

Gain on derivative contractswas a gain of $124.1 million for 2015 as compared to a gain of $96.6 million for 2014. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

Expenses

Lease and plant operating expenseincreased $3.0 million to $67.7 million in 2015 as compared to $64.7 million in 2014. On a per unit basis, lease and plant operating expense increased 2% from $9.63 to $9.86 per BOE for 2014 and 2015, respectively. The increase is primarily due to higher field services, rental equipment, and compression expense, totaling $6.9 million. The increase was partially offset by a decrease in chemical and fuel usage and salt water disposal of $3.7 million.

Marketing and transportation expense decreased $5.1 million to $4.0 million in 2015 from $9.1 million in 2014. The decrease is primarily due to the divestiture of a portion of our oil and gas properties in Eagleville field and the divestiture of the remainder of our Hilltop Field properties during 2014. Hilltop Field properties produced primarily dry gas. On a per unit basis, marketing and transportation expense decreased 57% from $1.36 to $0.59 per BOE for 2014 and 2015, respectively.

Production and ad valorem taxesdecreased $13.1 million to $15.1 million, or 46%, for 2015, as compared to $28.2 million for 2014. Production taxes decreased $11.6 million primarily due to the decrease in oil and natural gas revenues. Ad valorem taxes decreased $1.5 million primarily due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 and the sale of our Hilltop field in the third quarter of 2014. On a per unit basis, the production and ad valorem taxes decreased 48% from $4.20 to $2.20 per BOE for 2014 and 2015, respectively.

Workover expensedecreased $2.5 million to $6.5 million from $9.0 million for 2015 and 2014, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased $19.2 million to $42.7 million for 2015 from $61.9 million for 2014. The decrease in exploration expense is primarily due to decreases in G&G seismic expenditures of $11.7 million, dry hole expense of $7.6 million and plug and abandonment expenditures of $2.2 million, partially offset by an increase in delay rentals and expired leasehold of $2.2 million. As of December 31, 2015, our property, plant, and equipment balance includes $6.0 million in exploratory well costs which are deferred, pending determination of proved reserves. Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes.

Depreciation, depletion and amortization increased $2.2 million to $144.0 million for 2015 as compared to an expense of $141.8 million for 2014. On a per unit basis, this expense decreased 1% from $21.12 to $20.97 per BOE for 2014 and 2015, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense increased $101.9 million to $176.8 million in 2015 from $74.9 million in 2014. This non-cash expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “— Critical Accounting Policies and Estimates — Property and Equipment — Impairment” below for more details related to impairment. The increase in impairment expense is primarily due to a 47% decrease in the twelve month weighted average price for oil and a 41% decrease in the twelve month weighted average price for

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natural gas at December 31, 2015. The impairments in 2015 were primarily due to write-downs of both unproved oil and gas costs and developed fields. The primary prospects impaired were in South Texas of approximately $4.1 million and Weeks Island Area of approximately $0.6 million. Several developed fields were impaired due to downward revisions in reserves based on lower commodity prices, performance or development drilling results that were below expectations. The most significant of these were in Weeks Island Area of $129.1 million, the STACK of $15.7 million, South Louisiana of $9.4 million and East Texas of $8.9 million.

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $2.1 million and $2.2 million in 2015 and 2014, respectively.

General and administrative expense decreased $24.7 million to $44.5 million in 2015 from $69.2 million in 2014. The decrease is primarily due to non-recurring capital restructuring expenditures of $13.9 million in 2014, as well as a bonus accrual reduction of $9.9 million and a decrease in deferred compensation expense of $1.8 million in 2015. This decrease was partially offset by an increase in accrued settlement expense of $2.6 million. On a per unit basis, general and administrative expenses decreased 37% from $10.30 to $6.48 per BOE for 2014 and 2015, respectively.

Interest expense, netincreased $6.0 million to $61.8 million in 2015 from $55.8 million in 2014. This increase is primarily due to incurred interest expense of $6.2 million and amortization of deferred financing costs of $0.5 million, related to the senior secured term loan facility that we entered into during 2015. The increase in interest expense was partially offset by an increase in interest income of $0.7 million and lower interest expense of $0.1 million on our senior secured revolving credit facility due to a lower average balance outstanding.

Risk Management Activities — Commodity Derivative Instruments

Due to the risk of low oil and natural gas prices, we periodically enter into price-risk management transactions (e.g., swaps, collars, puts, calls, and financial basis swap contracts) for a portion of our oil, natural gas, and natural gas liquids production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. The commodity derivative instruments apply to only a portion of our production, and provide only partial price protection against declines in oil, natural gas, and natural gas liquids prices, and may partially limit our potential gains from future increases in prices. At December 31, 2016, commodity derivative instruments were in place covering approximately 92% of our projected oil production, approximately 72% of our natural gas production, and approximately 11% of our natural gas liquids production from proved developed properties for 2017. See “Note 7 — Derivative Financial Instruments” in the accompanying notes to consolidated financial statements included elsewhere in this prospectus for additional information.

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Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2016:

	Year Ended December 31,
	Total		2017		2018-2019		2020-2021		Thereafter
	(in thousands)
Debt	$	567,579	$	—	$	—	$	67,579	$	500,000
Interest(1)		327,320		41,000		82,000		86,195		118,125
Operating Leases		11,374		3,956		2,998		3,213		1,207
Drilling rigs(2)		6,285		6,285		—		—		—
Abandonment liabilities(3)		61,504		376		1,094		6,989		53,045
Total	$	974,062	$	51,617	$	86,092	$	163,976	$	672,377

(1) Interest includes interest on the outstanding balance under our senior secured revolving credit facility maturing in 2020, payable quarterly; on the old notes, payable semiannually; and on the debt to our founder, which is payable with principal, at maturity in 2021. In November 2016, the debt under our senior secured revolving credit facility was amended to extend the maturity from April 2018 to November 2020. The weighted average rate on our outstanding borrowings as of December 31, 2016 of 4.00% was utilized to calculate the projected interest for our senior secured revolving credit facility. Projected obligation amounts are based on the payment schedules for interest, and are not presented on an accrual basis.

(2) The drilling rigs are included at the gross contractual value. Due to our various working interests where the drilling rig contracts will be utilized, it is not feasible to estimate a net contractual obligation. Net payments under these contracts are accounted for as capital additions to our oil and gas properties and could be less than the gross obligation disclosed. The drillings rigs are utilized in drilling wells that may or may not be included as part of our joint development agreement with BCE.

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

Off-Balance Sheet Arrangements

As of December 31, 2016, we had no guarantees of third-party obligations. Our off-balance sheet obligations include the obligations under operating leases, the $2.2 million contingent properties payment for properties acquired in 2008 and prior years, and the $1.5 million contingent payment if we decide to forego certain drilling activities. We also have bonds posted in the aggregate amount of $24.0 million, primarily to cover future abandonment costs, and $7.6 million in letters of credit provided under our senior secured revolving credit facility. We typically enter into short-term drilling contracts which are customary in the oil and gas industry. We have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity and capital resources.

We have no plans to enter into any additional off-balance sheet arrangements in the foreseeable future.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). As used herein, the following acronyms have the following meanings: “FASB” means the Financial Accounting Standards Board; the “Codification” refers to the Accounting Standards Codification, the collected accounting and reporting guidance maintained by the FASB; “ASC” means Accounting Standards Codification and is generally followed by a number indicating a particular section of the Codification; and “ASU” means Accounting Standards Update, followed by an identification number, which are the periodic updates made to the Codification by the FASB.

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The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies.

Use of Estimates. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.

Property and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed at least quarterly for impairment following the guidance provided in ASC 360-10-35, Property, Plant and Equipment, Subsequent Measurement, whenever events or changes in circumstances indicate that the carrying amount of a long-lived

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asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations.

Depreciation, Depletion and Amortization — Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances.

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see “Note 6 — Fair Value Disclosures” in the accompanying notes to consolidated financial statements included elsewhere in this prospectus for additional information concerning fair value).

Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) on derivative contracts.” Cash flows from settlements of derivative contracts are classified as operating cash flows.

Income Taxes. We have elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal operations taxes is included in the consolidated financial statements.

We are subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for state income tax” on the consolidated statement of operations. We record state income tax (current and deferred) based on taxable income as defined under the rules for the margin tax.

Acquisitions.Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition.

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Asset Retirement Obligations. We estimate the present value of future costs of dismantlement and abandonment of our wells, facilities, and other tangible, long-lived assets, recording them as liabilities in the period incurred. We follow ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows for abandonment discounted generally at our cost of capital at the time of recognition.

Investments. Our investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method and we have recorded $9.0 million of Investment in LLC on the consolidated balance sheets as of December 31, 2016 and 2015. Under this method, our share of earnings or losses of the investment are not included in the consolidated statements of operations. Distributions from Orion are recognized in current period earnings as declared.

Alta Mesa is a part owner of AEM with an ownership interest of less than 10%. AEM markets our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee.

Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statement of operations.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 deferred the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company has not yet selected a transition method and is currently assessing the impact on the consolidated financial statements. The Company is continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements.

In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

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In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company does not plan to adopt the standard early. The Company enters into lease agreements to support its operations. These lease agreements are for assets such as office space, vehicles, field services and equipment. The Company continues to evaluate the impacts of the amendments to our financial statements and accounting practices for leases.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.

In October 2016, the FASB issued ASU No. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control. This guidance provides an amendment to the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. We have adopted this ASU and there was no current impact to our consolidated financial statements.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash, which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.

In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

We are exposed to certain market risks that are inherent in our consolidated financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but we do not enter into derivative agreements for speculative purposes.

We do not designate these derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

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Commodity Price Risk and Hedges

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for natural gas. We have used, and expect to continue to use, oil, natural gas and natural gas liquids derivative contracts to reduce our exposure to the risks of changes in the prices of oil, natural gas and natural gas liquids. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated with pre-existing or anticipated sales of oil, natural gas and natural gas liquids.

As of December 31, 2016, we have hedged approximately 63% of our forecasted production from proved developed reserves through 2019 at average annual floor prices ranging from $3.06 per MMBtu to $4.50 per MMBtu for natural gas and $47.68 per Bbl to $50.00 per Bbl for oil. Forecasted production from proved reserves is estimated in our December 2016 reserve report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, perhaps materially. Please read the disclosures under “Our estimated 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” in “Risk Factors” above.

The fair value of our oil and natural gas derivative contracts and basis swaps at December 31, 2016 was a net liability of $24.9 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $29.0 million (decrease in value) or $25.6 million (increase in value), respectively, as of December 31, 2016.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our derivative contracts currently in place have investment grade ratings.

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

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

Interest Rates

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts. A 1% increase in interest rates (100 LIBOR basis points) would increase interest expense on our variable rate debt by approximately $0.4 million, based on the balance outstanding at December 31, 2016.

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Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2016 or 2015. Although the impact of inflation has been insignificant in recent years, it could cause upward pressure on the cost of oilfield services, equipment and general and administrative expenses.

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BUSINESS

Our Company

Alta Mesa is a privately-held, independent exploration and production company primarily engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids within the United States. We have transitioned our focus from our diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the eastern portion of the Anadarko Basin in Oklahoma (the “STACK”) with an extensive inventory of drilling opportunities.

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 high drilling success rates. As of August 31, 2017, we have assembled a highly contiguous position of approximately 110,000 net acres largely in the up-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma. As of December 31, 2016, we have over 4,000 identified gross horizontal drilling locations in the STACK, over 2,000 of which we expect to operate. These drilling locations are in our primary 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 five horizontal drilling rigs in the STACK with plans to increase to seven rigs by the end of 2017. Our anticipated capital expenditures for 2017 are $363 million, of which we have allocated over 95% to the STACK.

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, 2016, we increased our STACK production at a compound annual growth rate (“CAGR”) of approximately 88%. We increased our leasehold interests from approximately 45,000 net acres in early 2015 to approximately 110,000 net acres as of August 31, 2017 primarily through the acquisition of largely undeveloped leasehold. We had average daily net production in the STACK of approximately 22,200 BOE/d for the month of June 2017 (66% liquids).

Beginning in the early 1990s, our operations in 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. In addition to our existing horizontal development of the Osage, Meramec and Oswego formations, we also plan to commence the drilling of horizontal wells in the Manning formation in 2017.

As of December 31, 2016, our estimated total proved reserves were approximately 138.8 MMBOE, of which 93% were in the STACK. The estimated total proved reserves in the STACK were approximately 129.6 MMBOE, representing a 93% increase over 2015 year-end estimated proved reserves of 67.0 MMBOE in the STACK. Our total proved reserve mix is approximately 42% oil, 38% natural gas, and 20% natural gas liquids.

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Silver Run Contribution Agreement

On August 16, 2017, we entered into the AM Contribution Agreement with SRII, the AM Contributor, our General Partner and solely for certain provisions therein, the equity owners of AM Contributor. Pursuant to the AM Contribution Agreement, SRII will acquire from the AM Contributor (i) all of its limited partner interest in Alta Mesa and (ii) 100% of the economic interests and 90% of the voting interests in our General Partner. In return, the AM Contributor will receive: (i) 220,000,000 Common Units as adjusted of SRII Opco and wholly owned subsidiary of SRII; (ii) $400 million in cash, which shall be contributed to us; and (iii) up to $800 million in earn-out consideration in the form of common units of SRII Opco, LP. At closing, the Common Units will be adjusted (i) upward for any inorganic acquisition capital expenditures invested by us during the interim period (based on a value of $10.00 per Common Unit), (ii) downward for the $200 million contribution to Alta Mesa by the RS Contributor, which was made in connection with the parties entering into the Contribution Agreements (based on a value of $10.00 per SRII Opco Common Unit), and (iii) downward for debt and transaction expenses (based on a value of $10.00 per SRII Opco Common Unit). The Earn-out Consideration will be paid as set forth below if the 20-day VWAP of the Class A Common Stock equals or exceeds the following prices:

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

Additionally, the AM Contributor will purchase non-economic capital stock of SRII, dedicated as Class C Common. The common units of SRII Opco, LP and corresponding Class C Common Stock are redeemable for Class A Common Stock beginning 180 days after the closing.

Simultaneous with the execution of the AM Contribution Agreement, SRII entered into (i) the KFM Contribution Agreement with the “KFM Contributor, KFM, and, solely for certain provisions therein, the equity owners of the KFM Contributor, pursuant to which SRII will acquire 100% of the outstanding membership interests in Kingfisher; and the RS Contribution Agreement with the RS Contributor pursuant to which SRII will acquire from the RS Contributor all of its limited partner interests in Alta Mesa.

The acquisition of Alta Mesa and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “business combination.”

In connection with the execution of the RS Contribution Agreement, the RS Contributor made a $200 million capital contribution to us, in exchange for limited partner interests. Additionally, pursuant to that certain forward purchase agreement between SRII and Riverstone SR, dated as of August 16, 2017, Riverstone SR has agreed to purchase up to $200 million shares of SRII Class A Common Stock in order to consummate the business combination.

The AM Contribution Agreement contains customary representations and warranties and pre-closing covenants, with the representations and warranties not survive the closing. Additionally, we have agreed to transfer to the AM Contributor prior to closing all assets and liabilities related to our non-STACK assets. The closing of the AM Contribution Agreement is subject to (i) the approval of the SRII stockholders; (ii) the simultaneous closing of the KFM Contribution Agreement and the RS Contribution Agreement; (iii) a SRII Opco leverage ratio of less than 1.5x; (iv) certain regulatory approvals; and (v) the satisfaction or waiver of other customary closing conditions. The Contribution Agreement also contains certain customary termination rights, including if the transaction is not consummated by February 28, 2018.

The notes will continue to be obligations of the Issuers pursuant to the terms of the indenture dated December 8, 2016, after completion of the business combination.

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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 crude oil, natural gas, and natural gas liquids prices beginning in the third quarter of 2014 with oil prices falling below $30.00 per barrel on several occasions during the first quarter of 2016 and natural gas prices declining to $1.64 MMBtu on March 3, 2016. Commodity prices improved in late 2016 with NYMEX West Texas Intermediate (“NYMEX WTI”) reaching $53.72 per barrel and NYMEX Henry Hub reaching $3.72 per MMBtu on December 31, 2016. As of March 28, 2017, NYMEX WTI was $48.37 per barrel and NYMEX Henry Hub was $3.10 per MMBtu. Commodity prices remain unpredictable. 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.

We have increased our anticipated capital expenditures, which includes acquisitions, for 2017 to $363 million, which is a 61% increase over the $226 million of capital expenditures in 2016. Additionally, we anticipate that up to an additional $108 million will be funded for 2017 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement. Our 2017 outlook is focused on the development of our assets in the STACK and, accordingly, we have allocated approximately 95% of our 2017 capital expenditures to the STACK. We currently operate five drilling rigs in the STACK and anticipate increasing to seven drilling rigs by the end of 2017, which will result in drilling a total of approximately 120 gross wells in the STACK. Of the total anticipated gross wells to be drilled in 2017, we plan to drill approximately 32 gross wells as part of our joint development agreement with BCE.

Our Strategy

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

• Economically grow production, cash flow and reserves by developing our extensive drilling inventory in the core of the STACK. We consider our large inventory of identified horizontal drilling locations in our primary target formations within the STACK to be relatively low-risk based on information gained from our own production history, the large number of existing wells in the area, the industry activity surrounding our acreage and the consistent and predictable geology on and surrounding our position. We intend to grow our reserves and production through the development of a multi-year inventory of identified drilling locations in our primary target formations within the STACK. As of December 31, 2016, we have 3,712 gross (1,636 net) identified horizontal drilling locations to develop the Osage and Meramec formations and 484 gross (190 net) identified horizontal drilling locations to develop the Oswego formation in our STACK acreage.

• Maximize the present value of future cash flows from our acreage position. We intend to increase the recovery of oil and natural gas from our acreage position in the most economically efficient manner possible to enhance future cash flows. To date, this effort has focused on developing our identified drilling locations, continuously optimizing well completions and horizontal and vertical spacing of our horizontal wells based on the results of our seven spacing tests. We also expect to establish the productive capability of additional formations including the Big Lime, Prue, Skinner, Red Fork, Cherokee Shale, Manning Lime, Woodford Shale and Hunton Lime formations. Based on results from our horizontal drilling program and those of offset operators, we believe significant development opportunities exist in these formations in the STACK as well as downspacing opportunities throughout our acreage position, thus potentially increasing our horizontal drilling inventory significantly.

• Expand drilling inventory through strategic acquisitions. We believe that our highly contiguous acreage position and extensive knowledge of the STACK will allow us to add acreage through grassroots leasing, acquisitions, pooling of interests and farm-ins. We believe our understanding of the

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geology, geophysics and reservoir properties of potential acquisition targets will allow us to identify and acquire highly prospective acreage in order to further grow our resource base. We increased our position in the STACK from approximately 45,000 net acres in early 2015 to approximately 110,000 net acres as of August 31, 2017 primarily through the acquisition of undeveloped acreage. We have significant experience in successfully sourcing, evaluating and executing acquisition opportunities and intend to pursue future acquisitions, farm-ins and forced pooling to meet our strategic and financial objectives.

• Maximize single-well returns by optimizing drilling and completion techniques through the experience and expertise of our operating team. Our team uses a multi-disciplinary approach on an ongoing basis to evaluate our techniques for well targeting, drilling, completions and operating results and compares our methods and results against other operators in our area in order to improve our performance and identify opportunities to optimize our drilling and completion techniques. We have incorporated increased understanding of rock properties to target landing zones for horizontal wells, as well as optimized completion designs. A key element of cost reduction has been efficiency gains in drilling time, improving from an average of over 40 days from wells spud in 2012 to an average of 15 days in 2016.

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

• Preserve a strong and flexible capital structure to pursue our development program and acquisition opportunities. We seek to maintain a strong capital structure that protects our balance sheet and liquidity. We expect to fund our growth with cash flow from operations, availability under our senior secured revolving credit facility and debt and equity offerings when appropriate. Consistent with our disciplined approach to financial management, we expect to maintain an active hedging program to protect our cash flow and the funding of our capital program.

Our Strengths

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

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

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• Large, highly contiguous acreage position with multi-year inventory of low-risk horizontal drilling locations. Our acreage in the STACK is characterized by a liquids-weighted inventory of horizontal drilling locations that provides attractive growth opportunities. Our core production area in the STACK has supported production since the 1940s and has a well-established infrastructure from historical operations. Our large, highly contiguous acreage blocks and focus on maintaining operational control provide us the flexibility to adjust our drilling and completion techniques in order to optimize our well results. Additionally, our highly contiguous acreage allows us to leverage existing infrastructure for more cost-efficient development and transportation. Our acreage position in the STACK also provides growth potential from an inventory of 3,712 identified gross horizontal drilling locations to develop the Osage and Meramec formations, and 484 identified gross horizontal drilling locations to develop the Oswego formation. Based on results from our horizontal drilling program and those of other operators, we believe significant development opportunities exist in other formations in the STACK.

• Substantial experience in the STACK and unconventional drilling techniques. We have owned portions of our current acreage position since 1992 and developed a deep familiarity with STACK geology due to the length of our operating history. Additionally, we have an experienced and technically-adept management team, averaging more than 24 years of industry experience. We have built a strong technical staff of geologists and geophysicists, field operations managers, and engineers. Our technical expertise, coupled with our STACK experience has enabled us to grow proved reserves and production in the STACK since 2012. Our recent focus in the STACK has been to implement a multi-year, multi-rig program to develop the Osage, Meramec and Oswego formations using horizontal drilling and multi-stage hydraulic fracturing technology. Our completion design has increased in number of stages and sand per stage with each new generation of wells. Since early 2013, our completion practices have progressed through four major generations in completion hardware, hydraulic fracture spacing, fluid selection and proppant loading in order to optimize single-well returns. We have proactively modified completion designs with each generation of new wells, which has led to improved well response.

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

• Financial strength and flexibility. We have a strong financial position and a prudent financial management strategy, which will allow us to actively allocate capital in order to grow production, reserves and cash flow. We believe our cash flow from operations, along with borrowing capacity and existing cash, will provide us with sufficient liquidity to execute on our 2017 capital program. Additionally, we have an effective hedging program in place to protect our future cash flows and provide more certainty for the budgeting of our capital plan. We plan to continue our hedging program to protect future revenues.

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Partnership Structure

We are structured as a private partnership. Since our inception in 1987, we have funded exploration, development and operating activities primarily through cash from operations, contributions by our limited partners, borrowings under our senior secured credit facilities and proceeds from the issuance of senior unsecured notes.

Our partnership agreement currently provides for two classes of limited partners, Class A and Class B. Our limited partners include our General Partner, High Mesa Holdings, LP (“HMH”) and Riverstone VI Alta Mesa Holdings, L.P. (“Riverstone”).

As a limited partnership, our operations and activities are managed by the board of directors (the “Board of Directors”) of our General Partner. Our General Partner is owned by (i) HMH, (ii) affiliates of Bayou City Management LLC (“Bayou City”), (iii) affiliates of HPS Investment Partners, LLC (formerly known as Highbridge Principal Strategies LLC) (“HPS”), (iv) Harlan Chappelle and (v) Michael E. Ellis. HMH holds all of the Class A and 90% of the Class B membership interests of our General Partner. Each of (i) the affiliates of Bayou City, (ii) the affiliates of HPS, (iii) Harlan Chappelle, and (iv) Michael Ellis own 2.5% of the Class B membership interests of our General Partner. Our General Partner’s Board of Directors is comprised of a number of managers determined by the members holding Class B Units. For so long as HMH is a Class B member, the members shall cause the composition of the General Partner’s Board of Directors to be the same as the composition of the board of directors of High Mesa, Inc. (“High Mesa”). High Mesa has been funded through investments from HPS and Bayou City in exchange for 100% of the preferred stock in High Mesa. HPS and Bayou City are private equity firms that are focused on energy and commodities and that manage other portfolio companies that are engaged in the oil and natural gas industry. With their extensive investment experience in the oil and natural gas industry and their network of industry relationships, we believe that HPS and Bayou City provide us with valuable financial management expertise and assistance in making strategic decisions. HPS and Bayou City and their respective portfolio companies are not prohibited from competing with us to acquire oil and gas properties.

With respect to distributions of net cash flow attributable to the STACK Assets, one hundred percent (100%) will go to the holders of Class A membership interests pro rata. With respect to distributions of net cash flow attributable to non-STACK assets, one hundred percent (100%) will go to the holders of Class B membership interest pro rata.

Reserve and Production Overview

The following table describes our proved reserves and production profile as of December 31, 2016:

	Total Estimated Proved Reserves (MMBOE)		% Proved Developed(1)			Liquids as % of Total Proved Reserves(1)			PV-10 ($ in Millions)(2)(5)			Net Acreage(3)		Net Producing Wells(4)		Average Daily Net Production 2016 (MBOE/d)(6)
STACK		129.6		26	%		62	%	$	534.5			97,554		338.9		13.0
Weeks Island Area		4.4		61	%		94	%		38.4			12,159		54.6		3.4
Other		4.8		96	%		29	%		(14.3	)		335,167		68.6		3.5
All Properties		138.8		29	%		62	%	$	558.6			444,880		462.1		19.9

(1) Computed as a percentage of total reserves of the area.

(2) PV-10 was calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the twelve months ended December 31, 2016. Because we are a partnership and, as such, are not

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subject to income taxes, our PV-10 is the same as our standardized measure of future net cash flows, the most comparable measure under United States generally accepted accounting principles, which is reduced for the discounted value of estimated future income taxes. Calculation of PV-10 does not give effect to derivatives transactions. The unweighted arithmetic average prices as of the first of each month during the twelve months ended December 31, 2016 were $42.75 per Bbl of oil and $2.49 per MMBtu of natural gas. The estimated realized prices for natural gas liquids using a $42.75 per Bbl benchmark and adjusted for average differentials were $15.18. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others.

(3) Includes developed and undeveloped acreage.

(4) Calculated as gross wells times our working interest percentage.

(5) A negative PV-10 is due to future abandonment liabilities and/or near-term operating expenses that exceed income as a result of low commodity prices. These properties, by definition, do not have any proved reserves associated with them.

(6) Actual average daily net production in the year ended December 31, 2016. Pro forma average daily net production in 2016, including interests in the 24 producing wells High Mesa, Inc. purchased from BCE and contributed to us on December 31, 2016 (the “Contributed Wells”), was 21.8 MBOE/d, of which approximately 15.0 MBOE/d was contributed by our STACK assets. See “— Our Properties — STACK, Oklahoma — Bayou City Joint Development Agreement” below.

Our Properties

STACK, Oklahoma

As of December 31, 2016, we have assembled a highly contiguous position of approximately 100,000 net acres largely in the up-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma, which makes up about 93% 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.

In the second quarter of 2017, we brought 33 horizontal wells on production in the Osage/Meramec interval of the STACK, 10 of which were funded through our joint development agreement with BCE. We had 49 horizontal wells in progress as of the end of the second quarter of 2017, 5 of which were funded through our joint development agreement with BCE. Subsequent to the end of the second quarter of 2017, 13 of the 49 horizontal wells in progress as of June 30, 2017 were on production.

As of June 30, 2017, we had six drilling rigs operating in the STACK. We plan to continue 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 formations.

Production from our STACK assets in the second quarter of 2017 was an average of approximately 20,500 BOE/d net to our interest, 65% oil and natural gas liquids, as compared to an average of approximately 12,300 BOE/d, 73% oil and natural gas liquids, in the second quarter of 2016. Production from our STACK properties in the first six months of 2017 was an average of approximately 19,900 BOE/d net to our interest, 68% oil and natural gas liquids, as compared to an average of approximately 11,700 BOE/d, 75% oil and natural gas liquids, in the first six months of 2016.

As of December 31, 2016, we had a 73% average working interest in 467 gross producing wells. We produced 4,768 MBOE net to us from our properties in Oklahoma in 2016, an increase of 48% as compared to 3,218 MBOE in 2015. Our pro forma production from our properties in Oklahoma, including contributed

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interests in 24 producing wells by High Mesa Inc., was 5,477 MBOE. During 2016, we spent approximately $209 million in the STACK for the drilling and completion of wells, as well as other expenditures for facilities and acquisition of leaseholds. We currently operate five drilling rigs in the STACK for horizontal development. We plan to increase to seven drilling rigs by the end of 2017, 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.

We have allocated approximately $349 million of our 2017 capital expenditure budget, including acquisition, to the STACK. In 2017, we plan to drill and complete approximately 120 gross wells in the STACK, which is inclusive of approximately 32 gross wells we expect to be drilled and completed through our joint development agreement at a cost of up to $108 million to be funded by BCE.

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 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 reserves from the Contributed Wells were 3.1 MMBOE, primarily classified as proved developed producing reserves. The drilling program will fund the development of 80 additional wells, in four tranches of 20 wells each. As of June 30, 2017, 31 additional joint wells have been drilled or spudded leaving 49 joint wells to be drilled under the joint development agreement. Of the approximate 120 gross wells we plan to drill in 2017, 32 are expected 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 in 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, KFM commissioned a 60 MMcf/d cryogenic gas processing facility within our acreage footprint. This facility receives natural gas from the KFM 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. KFM has commenced a 200 MMcf/d expansion that it expects to be operational in the fourth quarter of 2017.

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We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM. As part of the KFM contract, we have secured firm processing rights of 260 MMcf/d at the expanding KFM 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 KFM contract. Affiliates of High Mesa, Inc., own minority equity interests in KFM, as described more in detail under “Certain Relationships and Related Party Transactions — Gathering Agreements.” Additionally, after the business combination, we and KFM will be combined with SRII.

Weeks Island Area, South Louisiana

The Weeks Island Area, located in Iberia and St. Mary Parish, Louisiana, contains some of our largest proved developed oil reserves and consists of the Weeks Island and Cote Blanche Island fields. The Weeks Island field, located in Iberia Parish, Louisiana, is a historically-prolific oil field with 55 potential pay zones that are structurally and stratigraphically trapped around a piercement salt dome, which we believe offer significant future opportunities for added production and reserves. The Cote Blanche Island field, located near Weeks Island field in St. Mary Parish, is also a salt dome structure. The geology is similar to Weeks Island field, and over the long term we plan on utilizing the same geologic interpretation methods and engineering development techniques at Cote Blanche that we use at Weeks Island field to increase reserves and production.

Production from the Weeks Island Area in the second quarter of 2017 was approximately 2,400 BOE/d, net to our interest, 96% oil, as compared to 3,900 BOE/d, 90% oil, for the second quarter of 2016. Production from the Weeks Island Areas in the first six months of 2017 was approximately 2,300 BOE/d, net to our interest, 96% oil, as compared to 4,000 BOE/d, 92% oil in the first six months of 2016.

As of December 31, 2016, we had a 96% average working interest in a total of 57 gross producing wells, and had identified 7 PUD locations in the Weeks Island Area. Average daily production from the Weeks Island Area during 2016 was approximately 3,400 BOE/d.

Other Assets

We conduct operations in other areas and continually evaluate the operations in these areas to determine future development, expansion, acquisition opportunities, and strategic divestiture plans.

Our Oil and Natural Gas Reserves

The table below summarizes our estimated net proved reserves as of December 31, 2016:

	As of December 31, 2016
	Oil and NGLs (MBbls)		Gas (MMcf)
Proved Reserves(1)
Developed		24,809		93,361
Undeveloped		61,280		222,644
Total Proved		86,089		316,005

(1) Our proved reserves as of December 31, 2016 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the twelve months ended on such date. These average prices were $42.75 per

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Bbl for oil and $2.49 per MMBtu for natural gas. Pricing was adjusted for basis differentials by field based on our historical realized prices. See “Note 19 — Supplemental Oil and Natural Gas Disclosures (Unaudited)” in the accompanying notes to consolidated financial statements included elsewhere in this prospectus for information concerning proved reserves.

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

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

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

• Registered Professional Engineer in Oklahoma.

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:

• no employee’s compensation is tied to the amount of reserves booked;

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

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

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

Ryder Scott Company, L. P. (“Ryder Scott”), a third party consulting firm, audited 97% of our 2016 proved reserves on a 6:1 MCF/BBL conversion basis.

Copies of the audit letters issued by Ryder Scott are filed with this prospectus as Exhibits 99.2, 99.3, 99.4, and 99.5. The qualifications of the technical persons at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.

Kevin Gangluff earned a B.S. in Chemical Engineering at the University of Notre Dame and a Masters of Business Administration at the University of Texas at Austin. Mr. Gangluff is a licensed Professional Engineer in the State of Texas. Based on his educational background, professional training and more than thirty years of practical experience in the estimation and evaluation of petroleum reserves and resources, Mr. Gangluff 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.

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 thirty-five years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

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

A reserves audit and a financial audit are separate activities with unique and different processes and results. These two activities should not be confused. As currently defined by the SEC within Regulation S-K, Item 1202, a reserves audit is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

Proved Undeveloped Reserves

At December 31, 2016, we had PUDs of 98.4 MMBOE, or approximately 71% of total proved reserves. Total PUDs at December 31, 2015 were 44.6 MMBOE, or 57% of our total proved reserves.

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The following table reflects the changes in PUDs during 2016:

	MBOE
Proved undeveloped reserves, December 31, 2015		44,624
Converted to proved developed		(1,509	)
Proved undeveloped reserve extensions and discoveries		51,306
Proved undeveloped reserves acquired		—
Proved undeveloped reserves sold		—
Proved undeveloped reserve revisions		3,965
Proved undeveloped reserves, December 31, 2016		98,386

PUDs converted to proved developed reserves were primarily in the STACK, our most active development area. During 2016, we incurred approximately $8.4 million in expenditures to convert the December 31, 2015 PUDs to proved developed reserves. In addition, we spent approximately $2.7 million to convert PUDs that were added during 2016 to proved developed reserves, a portion of these drilling costs were funded through the joint development agreement. Extensions and discoveries were due to increases in PUD reserves associated with our successful drilling activity in the STACK. In 2016, we had positive revisions of 7,322 MBOE due to increase efficiencies of operations at the KFM plant in Oklahoma, which were partially offset by negative price revisions of 3,357 MBOE. These reserves were moved out of the PUD reserve category in compliance with the SEC five-year rule. Estimated future development costs, including plugging and abandonment cost (“P&A”), for PUDs remaining are approximately $634.5 million at December 31, 2016.

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, 2016 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 as seen in the recent decline 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.

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

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indicated below. For additional information on price calculations, please see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”:

	Six Months Ended June 30,		Year Ended December 31,
	2017		2016		2015		2014
Net production:
Oil (MBbls)		2,363		4,001		4,203		3,770
Natural gas (MMcf)		9,285		13,959		11,900		14,449
Natural gas liquids (MBbls)		646		956		678		537
Total (MBOE)		4,557		7,284		6,865		6,715
Total (MMcfe)		27,341		43,702		41,187		40,290
Average sales price per unit before hedging effects:
Oil (per Bbl)	$	48.41	$	40.91	$	47.54	$	92.27
Natural gas (per Mcf)		2.78		2.22		2.57		4.50
Natural gas liquids (per Bbl)		22.74		16.38		16.01		34.04
Combined (per BOE)		34.00		28.87		35.15		64.20
Combined (per MMcfe)		5.67		4.81		5.86		10.70
Average sales price per unit after hedging effects:
Oil (per Bbl)	$	48.38	$	61.53	$	67.73	$	93.38
Natural gas (per Mcf)		2.86		2.68		4.43		4.87
Natural gas liquids (per Bbl)		22.14		16.04		16.01		34.04
Combined (per BOE)		34.06		41.05		50.73		65.62
Combined (per MMcfe)		5.68		6.84		8.45		10.94
Average costs per BOE:
Lease and plant operating expense	$	7.53	$	7.81	$	9.86	$	9.63
Marketing and transportation expense		2.83		1.83		0.59		1.36
Production and ad valorem taxes		1.34		1.48		2.20		4.20
Workover expense		0.75		0.65		0.95		1.33
Average costs per Mcfe:
Lease and plant operating expense	$	1.26	$	1.30	$	1.64	$	1.61
Marketing and transportation expense		0.47		0.30		0.10		0.23
Production and ad valorem taxes		0.22		0.25		0.37		0.70
Workover expense		0.12		0.11		0.16		0.22

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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 93% of our total proved reserves as of December 31, 2016.

	Six Months Ended June 30,		Year Ended December 31,
STACK	2017		2016		2015		2014
Net production:
Oil (MBbls)		1,845		2,570		2,006		1,072
Natural gas (MMcf)		7,004		8,247		4,276		2,083
Natural gas liquids (MBbls)		589		823		499		316
Total (MBOE)		3,601		4,768		3,218		1,734
Total (MMcfe)		21,608		28,610		19,310		10,407
Average sales price per unit before hedging effects:
Oil (per Bbl)	$	48.39	$	41.16	$	45.90	$	89.34
Natural gas (per Mcf)		2.89		2.43		2.51		4.34
Natural gas liquids (per Bbl)		23.18		17.21		16.74		34.09
Combined (per BOE)		34.20		29.35		34.55		66.61
Average production costs per BOE:
Lease and plant operating expense	$	4.81	$	4.75	$	6.40	$	7.60
Marketing and transportation expense		3.38		2.44		0.49		0.63
Production and ad valorem taxes		0.69		0.58		0.58		1.45
Workover expense		0.47		0.72		0.78		1.49
Average production costs per Mcfe:
Lease and plant operating expense	$	0.80	$	0.79	$	1.07	$	1.27
Marketing and transportation expense		0.56		0.41		0.08		0.10
Production and ad valorem taxes		0.11		0.10		0.10		0.24
Workover expense		0.08		0.12		0.13		0.25

Delivery Commitments

As of December 31, 2016, 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, 2016, 2015 and 2014, 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

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assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

	Year Ended December 31,
	2016		2015		2014
Development wells (net):
Productive		29.9		34.6		46.6
Dry		—		2.0		0.1
Total development wells		29.9		36.6		46.7
Exploratory wells (net):
Productive		3.0		3.9		1.0
Dry		—		4.9		5.6
Total exploratory wells		3.0		8.8		6.6

Present Activities

As of June 30, 2017, we were drilling 45 gross (27.7 net) wells.

Productive Wells

The following table sets forth information with respect to our ownership interest in productive wells as of December 31, 2016:

	December 31, 2016
	Gross		Net
Oil wells:
STACK		435		319.1
Weeks Island Area		54		51.8
Other		73		26.4
All properties		562		397.3
Natural gas wells
STACK		32		19.8
Weeks Island Area		3		2.8
Other		84		42.2
All properties		119		64.8

Of the total well count as of December 31, 2016, 3 gross wells (2.6 net) are multiple completions.

Productive wells are producing wells, shut-in wells we deem capable of production, wells awaiting for 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.

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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, 2016, all of which is located in the United States:

	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Property:
STACK		94,771		70,835		28,613		26,719		123,384		97,554
Weeks Island Area		9,940		9,940		2,219		2,219		12,159		12,159
Other		59,350		26,156		369,057		309,011		428,407		335,167
All properties		164,061		106,931		399,889		337,949		563,950		444,880

As is customary in the oil and natural gas industry, we can generally retain an interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases, by paying delay rentals during the remaining primary term of leases, pooling process, automatic extensions or negotiated extensions of the leases, and other terms of the leases such as shut-in payments. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in leasehold acreage, both developed and undeveloped.

Undeveloped Acreage Expirations

The following table sets forth information with respect to our gross and net undeveloped oil and natural gas acreage under lease as of December 31, 2016, all of which is located in the United States, that will expire over the following three years by core area unless production is established within the spacing units covering the acreage prior to the expiration dates:

	2017				2018				2019
	Gross		Net		Gross		Net		Gross		Net
Property:
STACK		5,225		4,415		7,183		6,739		6,968		6,151
Weeks Island Area		1,824		1,824		395		395		—		—
Northwest		17,331		11,635		28,903		19,424		36,507		24,834
Other		2,508		1,774		17,670		9,713		5,383		4,470
All properties		26,888		19,648		54,151		36,271		48,858		35,455

We have lease acreage that is generally subject to lease expirations if initial wells are not drilled within a specified period, generally a period of three to five years. As is customary in the oil and gas industry, we can retain our interest in undeveloped acreage by maintaining the lease through: (i) the commencing operations for drilling, completion and production operations, (ii) pooling process, (iii) production, (iv) automatic extensions or negotiated extensions of the leases and (v) other terms of the leases such as shut-in payments. As of December 31, 2016, the vast majority of our acreage does not have associated proved undeveloped reserves, and proved undeveloped reserves attributed to acreage in which the lease expiration date precedes the scheduled initial drilling date is not material. Our leases are mainly fee leases with primary terms of three to five years. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests.

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Marketing and Customers

The market for our oil and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

We sell the oil and natural gas from several properties we operate primarily through a marketing agreement with ARM Energy Management, LLC (“AEM”). We are a part owner of AEM at less than 10%. AEM markets our oil and natural gas and subsequently sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. Our marketing agreement with AEM commenced in June 2013. The agreement will terminate in 2018, with additional provisions for extensions beyond five years, and for early termination. During the second half of 2013 and throughout 2014 to 2016, AEM marketed majority of our production from operated fields. Production from non-operated fields, the most significant of which were our Eagleville field in South Texas, and our Hilltop natural gas field in East Texas prior to their sale, was marketed on our behalf by the operators of those properties. Production from our interests in Eagleville was sold by the operator, Murphy Oil Corporation. We sold our remaining interests in Eagleville in the third quarter of 2015. See “Note 4 — Significant Acquisitions and Divestitures” in the accompanying notes to the consolidated financial statements included elsewhere in this prospectus for additional information.

Natural gas liquids are sold under various contracts with processors typically in the vicinity of the production at spot market rates, after processing costs.

For the year ended December 31, 2016, revenues marketed by AEM were $160.7 million, or 80% of total revenue excluding hedging activities.

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

Competition

We encounter intense competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and natural gas business for a much longer time than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory prospects and mineral leases and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Larger competitors may be able to absorb the decline in prices for oil and natural gas and the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. 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 and to consummate transactions in this highly competitive environment.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development, exploitation and exploration activities. We are unable to predict when, or if, such shortages may occur or how they would affect our exploitation and development program.

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We compete for capital in the domestic financial marketplace to fund our exploration and development activities to the extent our operations cannot support them at any given time. See “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry — 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.”

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Oklahoma Forced Pooling Process

In the past we have used, and we expect to continue to use, the Oklahoma “forced pooling” process to ensure all working interest owners participate in drilling and spacing units for wells we propose to drill as operator on our STACK acreage. Where applicable, this process allows us to increase our working interest in those units. Any such increase in working interest would lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well. Under Oklahoma law, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and natural gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may commence a “forced pooling” process. Under current regulations, drilling and spacing units for our targeted horizons in our STACK acreage are based on drilling a maximum of four to eight horizontal wells, depending on the formation, on a land section consisting of 640 acres. In a forced pooling action, which is common in Oklahoma, the proposed operator files an application for a pooling order with the Oklahoma Corporation Commission (“OCC”) and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate in an administrative proceeding that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair market value of the mineral interests in the unit is determined in the administrative proceeding by reference to market transactions involving nearby oil and natural gas rights, especially what has been paid for mineral leases in the particular drilling and spacing unit and the immediately surrounding drilling and spacing units.

Assuming the application is granted and a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair market value for their interest, usually in the form of a cash payment, an overriding royalty, or some combination, based on the fair market value established and approved through the administrative hearing. The pooling order usually also addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.

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

As a result of forced pooling processes, we have increased our working interest in approximately 95% of the 112 total operated horizontal wells we have drilled on our STACK acreage since January 1, 2014. In those wells in which forced pooling proceedings were initiated, we increased our working interest by an average of approximately 15% of our initial working interest in the drilling unit. In one instance in 2016, we proposed and drilled a well as operator in a section where our working interest ownership was initially approximately 10%,

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which through the implementation of the forced pooling process increased our working interest to approximately 90%. In recent years, the collective working interest of third party owners of mineral rights in these drilling units who have elected to participate in these wells has been low, which we believe could largely be attributed to the absence of available capital following the substantial oil and gas price downturns that commenced in late 2014. Due to the increased interest in the STACK as an economic play in the current price and cost environment, we believe that third party interest holders may be more likely to bear their share of the costs of the proposed future wells on our acreage. Nevertheless, we expect that forced pooling will continue to increase our leasehold interests within of our STACK acreage. The successful use of forced pooling to increase our working interest in proposed wells that are attributed undeveloped reserves is not reflected in our reserve reports.

Title to Properties

As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.

Employees

As of June 30, 2017, we had 268 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services. See “Certain Relationships and Related Party Transactions.”

Insurance

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to our oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things.

Currently, we have general liability insurance coverage up to $1 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles (generally ranging from $25,000 to $1.8 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

Our offshore reserves are not a significant portion of our total reserves; the fields are in declining production with no drilling activity. Our consolidated balance sheets include asset retirement liabilities which we believe are sufficient to cover the eventual costs of dismantlement and abandonment. We believe that due to the nature of the operations in these fields, and the limited activity, the risk of environmental damage is not as high as it would be in an actively drilling offshore field. Our insurance program includes property damage, pollution liability, and control of well. The property damage coverage extends to total loss of the equipment (not the reserves) with replacement cost coverage retained on one of the five fields. The pollution coverage, which is applicable to both offshore and onshore events, is $10 million per incident with a $100,000 deductible.

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We require all of our third-party contractors, including those that perform hydraulic fracturing operations, to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider. Similarly, we generally agree to indemnify each third-party contractor against claims made by our employees and other contractors. Additionally, each party generally is responsible for damage to its own property. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.

We re-evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

Legal Proceedings

Environmental Claims

Various landowners have sued Alta Mesa in lawsuits concerning several fields in which it has or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from Alta Mesa’s oil and natural gas operations. Alta Mesa is unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, Alta Mesa has not provided any material amounts for these claims in its condensed consolidated financial statements at June 30, 2017.

Due to the nature of Alta Mesa’s business, some contamination of the real estate property owned or leased by it is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. As of December 31, 2016, Alta Mesa’s revised estimated remediation liability for soil contamination in Florida was approximately $0.1 million and as of December 31, 2015, Alta Mesa had estimated a liability of $1.3 million, based on its undiscounted engineering estimates. The obligations are included in accounts payable and accrued liabilities at December 31, 2016 and other long-term liabilities at December 31, 2015 in the consolidated balance sheets included in the financial statements herein. Alta Mesa’s existing equity owners will assume the case and liabilities related thereto as part of the transfer of the non-STACK assets.

Title/Lease Disputes

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

Environmental and Occupational Safety and Health Matters

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

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

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• require the installation of pollution control equipment in connection with operations and place other conditions on our operations;

• place restrictions on the use of the material based on our operations and upon the disposal of waste from our operations;

• restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

• limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

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

• impose specific safety and health criteria addressing worker protection.

These laws, rules and regulations often impose difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in remedial or corrective action obligations, occurrence of delays or cancellations in the permitting, performance or expansion of projects and in issuance of orders enjoining performance in particular areas for non-compliance.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, for example, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017 to 2019, although the outlook for this initiative remains unclear with the change in Presidential administration. Consequently, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.

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

Non-hazardous and Hazardous Wastes and Hazardous Substances Handling

RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of non-hazardous and hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016.

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Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our financial condition and results of operations.

CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” (or in the case of state laws, other classes of materials) into the environment. Under CERCLA, such persons may be subject to joint and several, strict liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of hazardous substances. These classes of persons, or so-called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the hazardous substance release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at such a site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. We generate materials in the course of our operations that may be regulated as hazardous substances.

We currently own, lease or operate and in the past have owned, leased or operated numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such materials have been taken for treatment or disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed materials (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging or pit closure operations to prevent future contamination, the costs of which could be material.

Water Discharges and Subsurface Injections

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

The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Army Corps”). The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 as that appellate court and several other courts hear lawsuits opposing implementation of the rule. In January 2017, the United

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States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule is ongoing. In February 2017, President Trump signed an executive order directing the EPA and the Army Corps to begin a process to revise or rescind these rules; the agencies published a notice of intent on March 6, 2017 to review and rescind or revise the rules and the U.S. Department of Justice filed a motion with the U.S. Supreme Court on March 6, 2017 requesting a court stay of its review of the rules; the Court denied this request. The outlook for these rules is unclear. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. The primary federal law related to oil spill liability is the OPA, which amends and augments oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. The OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by the OPA, they are limited.

Our underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the SDWA and analogous state and local laws and regulations. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced waters and other substances, which could affect our business.

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

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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.

Hydraulic Fracturing

Many of our development projects require hydraulic fracturing procedures to economically develop the formations. Generally, we perform two types of hydraulic fracturing. In the STACK play, we perform hydraulic fracturing in horizontally drilled wells. These procedures are more extensive, time-consuming and expensive than hydraulic fracturing of vertical wells. We also perform hydraulic fracturing in vertical wells in our East Texas fields, including primarily Urbana and Cold Springs (both in East Texas); among the target zones are the Wilcox and Frio formations.

Currently, most hydraulic fracturing activities are regulated at the state level, as the SDWA’s UIC program exempts EPA regulation of most hydraulic fracturing except for hydraulic fracturing activities involving the use of diesel. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the hydraulic fracturing process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In other examples, in June 2016, the EPA published an effluent limitations 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, the BLM published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in June 2016 a Wyoming federal judge struck down this final rule. On July 25, 2017, the BLM proposed to rescind these regulations. On September 21, 2017, the U.S. Court of Appeals for the Tenth Circuit dismissed the litigation challenging the rule and vacated the district court’s opinion, essentially re-instating the rule, following the BLM’s proposal to rescind the rule in July 2017.

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, the U.S. 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.

Many states, including Oklahoma, where we conduct operations, and other regional and local regulatory authorities have enacted, and other states or other regional and local authorities are considering, laws or other regulatory initiatives on hydraulic fracturing, including disclosure requirements and regulations that could restrict or prohibit drilling in general or hydraulic fracturing in particular, in certain circumstances. Some states have also considered or adopted other restrictions or regulations on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be 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

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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.

Air Emissions

Our operations are subject to CAA and comparable state laws and implementing regulations that restrict the emission of air pollutants from many sources through air emissions standards, construction and operating permit programs and the imposition of other compliance standards. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay our projects or development of oil and natural gas projects.

Over the next several years, we may incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard for ground-level ozone from the current standard of 75 parts per million to 70 parts per million under both the primary and secondary standards. State implementation of these revised standards could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Also, the EPA finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small production facilities such as tank batteries and compressor stations, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements and increasing our expenditures for permitting and pollution control equipment. Additionally, the EPA issued final CAA regulations in 2012 that include NSPS for completions of hydraulically fractured natural gas wells and issued added CAA regulations in June 2016 that include new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category, including production activities. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects, increase our costs and reduce the demand for the oil and natural gas that we produce.

Climate Change Regulation and Legislation

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

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

With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to produce evidence of the GHG emissions of

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the proposed pipeline’s customers. In August 2017, The U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, which required FERC to revise its environmental impact statement for the proposed pipeline to take into account GHG carbon emissions from downstream power plants using natural gas transported by the new pipeline. It is too early to determine the impacts of this Court decision, but it could be significant.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published Subpart OOOOa, requirements for certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand the previously issued Subpart OOOO, requirements issued in 2012 by using certain equipment-specific emissions control practices. 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; 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. In 2017, President Trump withdrew the United States from the Paris Agreement, but the Governors of various individual States in the United States announced their intention to continue their commitment to the Paris Agreement. As a result, the ongoing commitment of the United States to the Paris Agreement is unclear.

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.

Activities on Federal Lands

Oil and natural gas exploration and production activities on federal lands, including Indian lands, may be subject to NEPA, which requires federal agencies, including the EPA, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as

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proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions and costs upon the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in the Environmental Assessments or Environmental Impact Statement, we could incur added costs, which may be significant.

Occupational Safety and Health Matters

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPCRA and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Other Laws and Regulations

Our operations are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are often based on negligence, trespass, nuisance, strict liability or fraud.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, (the “FERC”). Federal and state regulations govern the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission by pipeline in some circumstances may also affect the intrastate transportation of oil and natural gas by other means.

Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices.

Exports of U.S. Crude Oil Production, Natural Gas and Liquefied Natural Gas

The federal government has recently ended its decades-old prohibition of exports of oil produced in the lower 48 states of the United States. President Trump has announced his support for increasing exports of crude

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

Drilling and Production

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

• the location of wells;

• the method of drilling and casing wells;

• the timing of construction or drilling activities, including seasonal wildlife closures;

• the rates of production or “allowables”;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

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

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

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Forced Pooling in Oklahoma

The pooling process before the OCC provides a mechanism to develop a unit when two or more of its owners cannot voluntarily agree to pool their interests for the purposes of drilling and development. This

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procedure, which is standard in an actively developed field in Oklahoma, is specific to a given reservoir. The parties that are the recipient of pooling applications and orders under the OCC may elect to: (i) lease their unleased minerals for stated terms; (ii) participate in the well and pay their proportionate share of costs; or (iii) be bought out for fair, just and reasonable compensation determined by the OCC. Under this process, we pooled 68 sections in 2016 and on average increased our interest in the 68 units by 15%.

Natural Gas Sales and Transportation

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

Under the Energy Policy Act of 2005 (“EPAct”), Congress amended the Natural Gas Act (“NGA”) to give FERC) substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery.

FERC also regulates interstate natural gas transportation rates, terms and conditions of natural gas service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule-makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

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

Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transmission services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional

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transportation facilities as non-jurisdictional gathering facilities, and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In March 2016, the PHMSA issued a Notice of Proposed Rulemaking proposing to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines, including both high consequence areas (“HCAs”) and non-HCAs.

Oil and NGLs Sales and Transportation

Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

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

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Any transportation of our crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

President Obama had regularly refused to approve a Presidential Permit for the Keystone XL Pipeline or the Dakota Access Pipeline. A Presidential Permit is required for an applicant to construct any oil or natural gas pipelines crossing the international border of the United States, for example, with Canada or Mexico. In one of his early actions, President Trump issued Presidential Permits to both pipelines.

In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters.

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State Regulation

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

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

Louisiana severance tax laws are more complex than those of other states. Different schedules of taxes are imposed based on the different hydrocarbons produced. The basic (and highest) rate for natural gas is $0.164 per Mcf for full rate wells. The basis (and highest) rate for oil is 12.5% of value for full rate oil and condensate. There is a severance tax exemption for oil and gas produced from horizontal wells. Last year, Louisiana imposed on operators of wells a security deposit requirement for plugging and abandonment obligations. Those who own between 11 and 99 wells pay a deposit of $250,000. The fee is $500,000 for every 100 wells. Owners of single wells pay by the depth. The deposit is $7 per foot for the first 3,000 feet with lower rates the deeper the well is drilled.

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

Other Regulation

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity.

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MANAGEMENT

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

All of our executive management personnel are employees of Alta Mesa Services and devote all of their time to our business and affairs. We also utilize a significant number of employees of Alta Mesa Services to operate our properties and provide us with certain general and administrative services. Under the shared services and expenses agreement with Alta Mesa Services, we reimburse Alta Mesa Services for its operational personnel who perform services for our benefit.

Board Leadership Structure

Our Chairman is Michael E. Ellis, our Chief Operating Officer and founder of the Company. Our Board of Directors has no policy regarding the separation of the positions of Chief Executive Officer and Chairman. We also do not have a lead independent director.

Board Oversight of Risk

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

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

Executive Officers and Directors

The following table sets forth the names, ages and positions of our present directors and executive officers as of June 30, 2017. Members of our Board of Directors are elected for one-year terms.

			Director
Name	Age		Since		Position
Harlan H. Chappelle		61		2005	President, Chief Executive Officer and Director
Michael E. Ellis		60		1987	Founder, Chairman, Vice President of Engineering and Chief Operating Officer
Michael A. McCabe		62		2014	Vice President, Chief Financial Officer and Director
David Murrell		55		—	Vice President of Land and Business Development
Homer “Gene” Cole		53		2015	Vice President, Chief Technical Officer and Director
Don Dimitrievich		46		2014	Director
William W. McMullen		32		2016	Director
Mickey Ellis		58		1987	Director
Mark Stoner		36		2016	Director

The following is a biographical summary of the business experience of these directors and executive officers:

Harlan H. Chappellejoined Alta Mesa as President, CEO and director in November 2004, and has led us in a period of significant growth, building a strong management and technical team, focusing us on our greatest

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opportunities, making strategic acquisitions, and restructuring our financing. Mr. Chappelle has over 30 years in field operations, engineering, management, marketing and trading, acquisitions and divestitures, and field re-development. He has worked for Louisiana Land & Exploration Company, Burlington Resources, Southern Company, and Mirant. Mr. Chappelle retired as a Commander from the U.S. Navy Reserve. He has a Bachelor of Chemical Engineering from Auburn University and a Master of Science in Petroleum Engineering from The University of Texas at Austin.

Michael E. Ellisfounded Alta Mesa in 1987 after beginning his career with Amoco, and is our Chairman and Chief Operating Officer, as well as Vice President of Engineering. Mr. Ellis manages all day-to-day engineering and field operations of Alta Mesa. He built our asset base by starting with small earn-in exploitation projects, then progressively grew the company with successive acquisitions of fields from major oil companies, and consistent success in exploration and development drilling. He has over 30 years’ experience in management, engineering, exploration and acquisitions and divestitures. Mr. Ellis holds a Bachelor of Science in Civil Engineering from West Virginia University. Mr. Ellis is the spouse of Mickey Ellis, our director.

Michael A. McCabe, our CFO as well as a Vice President, joined Alta Mesa in September 2006 and became a director in 2014. Mr. McCabe has over 25 years of corporate finance experience, with a focus on the energy industry. From 2004 until 2006, Mr. McCabe served as President and sole owner of Bridge Management Group, Inc., a private consulting firm primarily providing advisory services to us and to MultiFuels, Inc., a Houston based developer of natural gas storage facilities. He has served in senior positions with Bank of Tokyo, Bank of New England, and Key Bank. Mr. McCabe holds a Bachelor of Science in Chemistry and Physics from Bridgewater State University, a Master of Science in Chemical Engineering from Purdue University and a Master of Business Administration in Financial Management from Pace University.

David Murrellhas served as our Vice President, Land and Business Development since 2006. Mr. Murrell has over 30 years of experience in Gulf Coast leasing, exploration and development programs, contract management and acquisitions and divestitures. He created a structured land management system for Alta Mesa, and built a team of division order analysts, lease analysts, landmen, and field representatives that has facilitated our growth. Mr. Murrell earned a Bachelor of Business Administration in Petroleum Land Management from the University of Oklahoma and is a Certified Professional Landman through the Association of Professional Landmen.

Homer “Gene” Colejoined Alta Mesa in 2007 and has served in the position of Vice President and Chief Technical Officer since August 2015 and became a director in August 2015. Mr. Cole has over 25 years of extensive domestic and international oilfield experience in management, well completions and well stimulation design and execution. He started his career with Schlumberger Dowell as a Field Engineer and served from 1986 to 2007 in numerous positions of increasing responsibility with Schlumberger in the areas of field operations, engineering and management. He has a Bachelor of Science in Petroleum Engineering from Marietta College.

Don Dimitrievich was appointed to our Board of Directors as HPS’s director nominee in March 2014. Mr. Dimitrievich is a Managing Director at HPS Investment Partners, a leading global investment firm with approximately $39 billion of assets under management. At HPS, Mr. Dimitrievich oversees HPS’s private credit investment strategy for the energy and power sectors. HPS has invested over $4 billion in direct energy-related investments since inception in 2007. Prior to joining HPS in 2012, Mr. Dimitrievich was a Managing Director of Citi Credit Opportunities, a credit-focused principal investment group. At Citi Credit Opportunities, Mr. Dimitrievich oversaw the energy and power portfolio and invested over $800 million in mezzanine, special situation and equity co-investments, and secondary market opportunities. Mr. Dimitrievich began his career as a corporate attorney in the New York office of Skadden, Arps, Slate, Meagher & Flom LLP focusing on energy mergers and acquisitions and capital markets transactions. Mr. Dimitrievich also serves on the board of Energy & Exploration Partners, Inc. Mr. Dimitrievich has a Law degree with Great Distinction from McGill University in Montreal, Canada and earned a Chemical Engineering degree with Great Distinction from Queen’s University in Kingston, Canada.

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William W. McMullenwas appointed to our Board of Directors as Bayou City’s director nominee in August 2016. Mr. McMullen is the founder and managing partner of Bayou City an oil and gas focused private equity firm based in Houston, Texas. Mr. McMullen founded Bayou City in 2015 after successfully managing a smaller private equity vehicle, Bayou City Energy Partners (“BCEP”), focused on investments in the oil and gas sector. Prior to BCEP, Mr. McMullen served as Vice President at White Deer Energy from August 2012 to October 2014, an oil and gas focused private equity firm, where he was responsible for origination, analysis, structuring and execution of upstream investments. Before White Deer Energy, Mr. McMullen served as an Associate at Denham Capital from August 2010 to July 2012. Prior to Denham Capital, Mr. McMullen served as an Analyst in UBS Investment Bank’s Global Energy group. Mr. McMullen earned his Bachelor’s degree in Economics, with Honors, from Harvard University.

Mickey Ellis has served as a director since our inception in 1987. Mrs. Ellis is actively involved in the leadership of charitable organizations, as a Board Member of The Confessing Movement of the United Methodist Church, Committee Member on several committees within Grace Fellowship United Methodist Church, and Building Relocation Coordinator for Mission Bend Christian Academy. She is a major fundraiser for the Susan G. Komen Foundation, student at the Bible Seminar Master of Divinity, and an active volunteer for CanCare. Ms. Ellis is the spouse of Michael E. Ellis, our Chairman, Chief Operating Officer and Vice President of Engineering.

Mark Stonerwas appointed to our Board of Directors as Bayou City’s second director nominee in September 2016. Mr. Stoner is a partner at BCE. Prior to joining BCE in 2015, Mr. Stoner was the Vice President of Finance of Alta Mesa. Mr. Stoner joined us in March 2008 and helped oversee our financing. While he was our Vice President of Finance, Mr. Stoner had leadership roles in the initial and subsequent high yield debt offerings as well as its recapitalization by HPS in 2014 and was a member of the acquisition and divestiture team which sourced and evaluated acquisition and divestiture opportunities. Prior to joining us, Mr. Stoner worked as a Financial Analyst at Leor Energy from 2006 to 2007. Mr. Stoner earned his Bachelor’s degree in Business from Southwestern University.

Qualifications of Directors

Mr. Chappelle’s experience as our Chief Executive Officer since 2004, combined with his significant equity ownership of us, and over 30 years of experience in the oil and gas industry uniquely qualify him to serve as a director of our General Partner.

Mr. Ellis is our founder; his experience in that capacity and as one of our executive officers since 1987 provide him intimate knowledge of our operations, finances and strategy and uniquely qualifies him to serve as the Chairman of our General Partner.

Ms. Ellis’ role in working with us since our inception in 1987 provides her with valuable knowledge of our business and operations and uniquely qualifies her to serve as a director of our General Partner.

Mr. Dimitrievich provides the Board of Directors with significant financial and energy expertise which uniquely qualifies him to serve as a director of our General Partner.

Mr. McCabe’s experience as our Chief Financial Officer since 2006 and over 25 years of corporate finance experience uniquely qualifies him to serve as a director of our General Partner.

Mr. Cole’s experience as our Chief Technical Officer since 2015 and over 25 years of domestic and international oilfield experience in well completions, and well simulations design and execution uniquely qualifies him to serve as a director of our General Partner.

Mr. McMullen provides the Board of Directors with significant financial and energy expertise which uniquely qualifies him to serve as a director of our General Partner.

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Mr. Stoner provides the Board of Directors with significant financial and energy expertise which uniquely qualifies him to serve as a director of our General Partner.

Audit and Compensation Committee

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

Code of Ethics

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

Executive Compensation

Compensation Discussion and Analysis

This Compensation Discussion and Analysis, describes our compensation objectives and the principles underlying our compensation policy relating to 2016 compensation for our named executive officers (“NEOs”).

Our Board of Directors is responsible for overseeing our executive remuneration programs and the fair and competitive compensation of our executive officers and meets each year to review our compensation program and to determine compensation levels for the ensuing fiscal year.

Objectives of Our Compensation Program

Our executive compensation program is intended to motivate our executive officers to achieve strong financial and operating results for us. In addition, our program is designed to achieve the following objectives:

• attract and retain highly qualified executive officers by providing reasonable total compensation levels competitive with that of executives holding comparable positions in similarly situated organizations;

• provide total compensation that is justified by individual performance; and

• reward our executives for their contributions to our overall performance as well as for their individual performance.

What Our Compensation Program is Designed to Reward

Our primary business objective is to increase value. Our compensation program is designed to reward performance that contributes to the achievement of our business strategy. In addition, we reward qualities that we believe help achieve our strategy, such as teamwork; individual performance in light of general economic and industry specific conditions; performance that supports our core values; resourcefulness; the ability to manage our existing corporate assets; the ability to explore new avenues to increase oil and natural gas production and reserves; level of job responsibility; and tenure with us.

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Elements of Our Compensation Program and Why We Pay Each Element

To accomplish our objectives, our compensation program is comprised of the following elements: base salary, cash bonus, long term incentives and benefits. Our Board of Directors approved and adopted a deferred compensation and supplemental executive retirement plan in 2013 and a performance appreciation rights plan in 2014.

We pay base salary in order to recognize each executive officer’s unique value and historical contributions to our success in light of salary norms in the industry and the general marketplace; to match competitors for executive talent; to provide executives with sufficient, regularly-paid income; and to reflect an executive’s position and level of responsibility.

We include an annual cash bonus as part of our compensation program because we believe this element of compensation helps to motivate executives to achieve key corporate objectives by providing annual recognition of achievement. The annual cash bonus also allows us to be competitive from a total remuneration standpoint.

We provide a supplemental executive retirement plan to certain key employees, including all our executive officers, to provide additional flexibility and tax planning advantages to them. In addition, the retirement benefits enhance employee compensation on a discretionary basis and encourage their continued service to us.

We grant performance appreciation rights units (“PARS”) as long-term compensation to certain key employees, including our executive officers, who make significant contributions to us. The PARs are payable on a fixed determination date which is generally between five and ten years from the grant date of the award or in the event of a Liquidity Event (as defined in the PARs Plan), and therefore, provide the grantee with a significant interest in us tied to long-term performance.

We offer benefits such as a 401(k) plan and payment of insurance premiums in order to provide a competitive remuneration package as well as a measure of financial security to our employees. In 2013 we introduced a deferred compensation plan offered to all employees, to provide flexibility and tax planning advantages to them.

How We Determine Each Element of Compensation

In determining the elements of compensation, we consider our ability to attract and retain executives as well as various measures of company and industrial performance including debt levels, revenues, cash flow, capital expenditures, reserves of oil and natural gas and costs. We did not retain a consultant with respect to determining 2016 compensation.

Messrs. Ellis, Chappelle, McCabe, and Murrell are parties to employment agreements with Alta Mesa Services. The employment agreements automatically renew annually, subject to prior notice of cancellation by either us or the executive. These employment agreements establish set minimum base salaries for each officer. On March 25, 2014, these employment agreements were amended and restated and the salaries for each officer were set at $485,000, $485,000, $435,000, and $360,000 per annum, to Messrs. Ellis, Chappelle, McCabe and Murrell, respectively, which we believe are competitive with other independent oil and natural gas companies with whom we compete for managerial talent. In addition, the employment agreements provide that the executives are each entitled to an annual bonus equal to a percentage of his respective annual base salary if performance criteria set by the Board of Directors for the applicable period are met. The agreements also provide for benefits such as reimbursement of business expenses and participation in employee benefit plans.

Base salary. In reviewing base salaries, the Board of Directors takes into account a combination of subjective factors, primarily relying on their own personal judgment and experience. Subjective factors the Board of Directors considers include individual achievements, our performance, level of responsibility, experience,

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leadership abilities, increases or changes in duties and responsibilities and contributions to our performance. Mr. Ellis and Mr. Chappelle participate in and are present during the Board of Directors’ review and determination of their respective base salaries. For 2016, the Board of Directors set the base salaries for Messrs. Ellis, Chappelle and McCabe at $485,000, $485,000 and $435,000, respectively. In addition, the Board of Directors determined Mr. Murrell’s and Mr. Cole’s salary of $360,000 and $350,000 for 2016 was appropriate.

Bonus.A portion of each executive’s total compensation may be paid as bonus compensation. The Board of Directors takes into consideration our achievements during the year and each executive’s contribution toward such achievements. While performance criteria may be set, the Board of Directors takes into account subjective factors in determining if these criteria were met. Bonuses for any one year are usually determined and paid in the second or third quarter of the following year. Accordingly, bonus compensation for our executive officers for 2016 has not yet been determined. However, bonuses paid in 2016 for 2015 performance ranged from approximately 45% to 85% of base salary.

Long-Term Incentives.On September 23, 2014, the Board of Directors approved and adopted a long-term compensation plan, the Alta Mesa Holdings, LP Performance Appreciation Rights Plan (the “PARs Plan”), as amended and restated effective September 24, 2014, to provide long term incentive compensation to key employees and consultants who make significant contributions to us to align our employees with our long term performance. The PARs Plan is administered by the Board of Directors, which will determine from time to time which participants will participate in the PARs Plan, the number of PARs to be granted to each participant, the stipulated initial designated value (“SIDV”) of each PAR, the designated value of each PAR as of its valuation date, the vesting schedule of each PAR, and any other terms and conditions of the PAR award. Under the PARs Plan, there are special provisions for valuation and payment of a vested PAR award in the event of a Liquidity Event, which is generally defined as follows: an event that (a) satisfies the definition of “change in control” under Section 409A of the Code (“Section 409A”) and (b) is (i) a sale of the all of the assets of High Mesa, (ii) a disposition of all of the equity securities of High Mesa, (iii) an initial public offering of the equity securities of High Mesa or any of its subsidiaries that hold all or substantially all of the assets or (iv) a public offering resulting in gross proceeds of at least $300,000,000, provided that such event also qualifies as a change in control event under Section 409A. The business combination will result in the vesting and payment of all outstanding PARs. In addition, we will not issue any additional PARs following the business combination.

A total of 1,000,000 PARs are available for grants to participants under the PARs Plan. The aggregate designated value of all 1,000,000 PARs is approximately equal to 10% of the fair market value of the aggregate interests of all the Class A members in our General Partner.

Absent an intervening Liquidity Event, payment of a PAR award is made on the fixed determination date elected in advance by the recipient of the PAR award, with such fixed determination date occurring no earlier than April 1 of the fifth year following the year of the grant and no later than ten years from the grant date. All payments made under the PARs Plan in any year are subject to a floating annual cap on the amount of all PAR awards paid under the PARs Plan in a given year (the “Annual Cap”). The Annual Cap is equal to 2.5% multiplied by the fair market value of the aggregate interests of all the Class A members in our General Partner minus $400,000,000. If the Annual Cap applies in a year, the amount payable to a PAR award holder on the fixed determination date is his pro-rata amount of the aggregate payments to be made on that date as adjusted for the amount of Annual Cap remaining for that year. Any amounts in excess of the Annual Cap are paid in the next following year, again subject to the Annual Cap.

Upon the occurrence of a payment event, the participant will be entitled to receive a cash amount equal to the increase, if any, between the SIDV of the PAR as of its grant date and the designated value of the PAR as of its payment valuation date. No PARs will be settled in shares; rather, all PAR exercises will be settled solely in cash. Participants will have no rights whatsoever as a shareholder of our General Partner or of a subsidiary in respect of any PARs.

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In 2016, the Board awarded 15,000 PARs to David Murrell, which vests over a five-year period. The SIDV is $40 per unit and payout is based on the increase of the value of the units over the SIDV at the earlier of a Liquidity Event or at a fixed determination date which is generally at least five years from the grant date of the award. In 2015, no PARs were awarded to any of the NEOs. In 2014, the Board of Directors awarded 60,000 PARs to Michael A. McCabe, of which 50,000 units vested immediately, and the remaining 10,000 units vest over a three-year period. The SIDV is $10.00 per unit, and payout is based on the increase of the value of the units over the SIDV as determined at the earlier of a Liquidity Event at or at a fixed determination date which is generally at least five years from the grant date of the award. The Board of Directors also granted 15,000 PARs to David Murrell. The SIDV of 10,000 of the units is $40 per unit and vest over a five-year period, and the remaining 5,000 units have a SIDV of $30 per unit of which 1,500 vest immediately and the remaining 3,500 vest over a three-year period, and payout is based on the increase of the value of the units over the SIDV at the earlier of a Liquidity Event or at a fixed determination date which is generally at least five years from the grant date of the award.

Benefits.We provide company benefits or perquisites that we believe are standard in the industry to all of our employees. These benefits consist of a group medical and dental insurance program for employees and their qualified dependents and a 401(k) employee savings and protection plan. The costs of these benefits are paid for entirely by us. We do not provide employee life insurance amounts surpassing the Internal Revenue Service maximum. We make matching contributions to the 401(k) contribution of each qualified participant. We pay all administrative costs to maintain the plan. In addition, we provide Messrs. Ellis, Chappelle, McCabe, Murrell, and Cole with company automobiles. Beginning annually in 2014, we also reimburse each officer, with the exception of Mr. Cole, up to $5,000 annually for tax preparation and planning.

Nonqualified Deferred Compensation.We established a nonqualified deferred compensation plan in 2013, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”), to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees. The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us. If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years. Participants will receive a distribution of vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring for a fixed time period or until separation from service. On December 29, 2016, the Board of Directors, in its discretion, authorized elective employer contributions to be credited to the accounts of Messrs. Chappelle, Ellis, McCabe, Murrell and Cole in the amounts of $1.6 million, $0.7 million, $0.6 million, $0.3 million and $0.5 million, respectively, effective January 1, 2017. The Board of Directors elected to make this distribution subject to a five-year vesting schedule, with 20% vested each subsequent year, with the exception of Messrs. Murrell and Cole, with none vested in year one and 25% vested each subsequent year beginning in year two of the five-year vesting schedule.

Other Compensation. As part of his employment agreement, we provide Mr. McCabe an apartment near our headquarters and pay his commuting expenses to and from his permanent home to Houston. In 2016, these housing and commuting expenses totaled approximately $89,000. We agreed to provide these benefits to Mr. McCabe because our Board believed it was necessary to retain Mr. McCabe’s services despite the fact that his permanent residence is outside of the Houston area. The Board of Directors considered the value of this additional compensation in evaluating Mr. McCabe’s total compensation package.

How Elements of Our Compensation Program are Related to Each Other

We view the various components of compensation as related but distinct and emphasize “pay for performance” with a portion of total compensation reflecting a risk aspect tied to our financial and strategic goals. We determine the appropriate level for each compensation component based in part, but not exclusively, on our view of internal equity and consistency, and other considerations we deem relevant, such as rewarding extraordinary performance.

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Assessment of Risk

Our Board of Directors takes risk into account when making compensation decisions and has concluded that the executive compensation program as it is currently structured does not encourage excessive risk or unnecessary risk-taking.

Accounting and Tax Considerations

We have structured our compensation program to comply with Section 409A. If an employee is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such compensation does not comply with Section 409A, then the benefits are generally taxable to the extent they are not subject to a substantial risk of forfeiture. In such case, the employee is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefits includible in income.

Under the PARs Plan, participants are granted PARs with a SIDV. The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between SIDV and the designated value of the PAR on the payment valuation date. The payment valuation date is the earlier of a Liquidity Event (as defined in the PARs Plan, but generally can be construed in accordance with the meaning of the term “change in control event”) or as a fixed determination date selected by the participant, which is no earlier than within the fifth year from the end of the year containing the grant date. In the case of a Liquidity Event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the PARs Plan) resulting from the Liquidity Event. After any payment valuation date, rested PARs expire regardless of whether or not there is a payment relating thereto. We are unable to express an opinion with respect to the likelihood of a Liquidity Event which would result in any payment under the PARs Plan or to estimate any amount which may become payable under the PARs Plan. We consider the possibility of payment at a fixed determination date absent the occurrence of a Liquidity Event to be remote. Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2016 or 2015.

Stock Ownership Guidelines

Stock ownership guidelines have not been implemented for our named executive officers or directors. We will continue to periodically review best practices and reevaluate its position with respect to stock ownership guidelines.

Securities Trading Policy

Our securities trading policy provides that executive officers, including the named executive officers, and its directors, may not, among other things, purchase or sell puts or calls to sell or buy its stock, engage in short sales with respect to its stock, buy its securities on margin or otherwise hedge their ownership of its stock. The purchase or sale of stock by our executive officers and directors may only be made during certain windows of time and under the other conditions contained in its policy.

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Summary Compensation

The following table summarizes, with respect to our NEOs, information relating to the compensation earned for services rendered in all capacities during the fiscal years ended December 31, 2016, 2015 and 2014. None of the NEOs participate in a defined benefit pension plan.

Name and Principal Position:	Year		Salary		Bonus(1)		All Other Compensation(7)		Total
Harlan H. Chappelle		2016	$	485,000	$	—	$	1,423,656	$	1,908,656
President, Chief Executive Officer		2015	$	485,000	$	—	$	42,555	$	527,555
		2014	$	485,000	$	—	$	38,515	$	523,515
Michael E. Ellis		2016	$	485,000	$	—	$	900,280	$	1,385,280
Chief Operating Officer, Vice President of		2015	$	485,000	$	300,000	$	20,423	$	805,423
Engineering and Chairman of the Board		2014	$	485,000	$	—	$	13,078	$	498,078
Michael A. McCabe		2016	$	435,000	$	—	$	847,348	$	1,282,348
Vice President, Chief Financial Officer		2015	$	435,000	$	300,000	$	126,095	$	861,095
		2014	$	435,000	$	400,000	$	3,120,848	$	3,955,848
David Murrell		2016	$	360,000	$	—	$	294,163	$	654,163
Vice President of Land and		2015	$	360,000	$	175,000	$	14,819	$	549,819
Business Development		2014	$	360,000	$	25,000	$	22,850	$	407,850
Homer “Gene” Cole		2016	$	344,230	$	—	$	479,949	$	824,179
Vice President, Chief Technical Officer		2015	$	300,000	$	250,000	$	20,371	$	570,371

(1) Bonuses for 2016 have not yet been determined. We expect these bonuses will be determined before the end of November 2017.

(2) Mr. Chappelle’s other compensation for the year ended December 31, 2016 consists of $1,375,000 in an elective contribution made by us to his Retirement Plan account, $11,192 in his matching funds to his 401(k), $32,827 in auto expenses, and approximately $4,637 for club membership. Mr. Chappelle’s other compensation for the year ended December 31, 2015 consists of $8,954 in his matching funds to his 401(k), $30,131 in auto expenses, and approximately $3,470 for club membership. Mr. Chappelle’s other compensation for the year ended December 31, 2014 consists of $9,110 in matching funds to his 401(k) account and $29,405 in auto expenses.

(3) Mr. Ellis’ other compensation for the year ended December 31, 2016 consists of $875,000 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account and $12,030 in auto expenses. Mr. Ellis’ other compensation for the year ended December 31, 2015 consists of $10,600 in matching funds to his 401(k) account and $9,823 in auto expenses. Mr. Ellis’ other compensation for the year ended December 31, 2014 consists of $8,750 in matching funds to his 401(k) account and $4,328 in auto expenses.

(4) For the year ended December 31, 2016, Mr. McCabe’s other compensation consists of $750,000 in an elective contribution made by us to his Retirement Plan account, $8,270 in matching funds to his 401(k) account, and $89,078 in travel and living expenses, which includes $41,735 for an apartment in Houston and $47,343 for travel, which consists primarily of airfare and the cost of a leased car and parking. For the year ended December 31, 2015, Mr. McCabe’s other compensation consists of $8,319 in matching funds to his 401(k) account, and $117,776 in travel and living expenses, which includes $41,049 for an apartment in Houston and $76,727 for travel, which consists primarily of airfare and the cost of rental cars and parking. For the year ended December 31, 2014, Mr. McCabe’s other compensation consists of $3,000,000 in an elective contribution made by us to his Retirement Plan account, $7,131 in matching funds to his 401(k) account, and $113,717 in travel and living expenses, which includes $32,597 for an apartment in Houston and $81,120 for travel, which consists primarily of airfare and the cost of rental cars and parking.

(5) Mr. Murrell’s other compensation for the year ended December 31, 2016 consists of $275,000 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account,

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and $5,913 in auto expense. Mr. Murrell’s other compensation for the year ended December 31, 2015 consists of $10,600 in matching funds to his 401(k) account and $4,219 in auto expense. Mr. Murrell’s other compensation for the year ended December 31, 2014 consists of $11,500 in matching funds to his 401(k) account and $11,350 in auto expense.

(6) Mr. Cole became an executive officer of the Company in 2015. Mr. Cole’s other compensation for the year ended December 31, 2016 consists of $450,000 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account and $16,699 in auto expense. Mr. Cole’s other compensation for the year ended December 31, 2015 consists of $9,692 in matching funds to his 401(k) account and $10,679 in auto expense.

(7) In 2016, the Board of Directors awarded 15,000 PARs to Mr. Murrell, which vest over a five-year period. The SIDV is $40 per unit and payout is based on the increase of the value of the units over the SIDV at the earlier of a Liquidity Event or at a fixed determination date which is generally at least five years from the grant date of the award. No PARs were awarded in 2015. In 2014, the Board of Directors awarded 60,000 PARs to Mr. McCabe, of which 50,000 units vested immediately, and the remaining 10,000 units vest over a three-year period. The SIDV is $10.00 per unit, and payout is based on the increase of the value of the units over the SIDV as determined at the earlier of a Liquidity Event or at a fixed determination date which is generally at least 5 years from the grant date of the award. The Board of Directors also granted 15,000 PARs to Mr. Murrell. The SIDV of 10,000 of the units is $40 per unit and vest over a five-year period, and the remaining 5,000 units have a SIDV of $30 per unit of which 1,500 vest immediately and the remaining 3,500 vest over a three-year period, and payout is based on the increase of the value of the units over the SIDV at the earlier of a Liquidity Event or at a fixed determination date which is generally at least five years from the grant date of the award.

Narrative Disclosure to Summary Compensation Table

Employment agreements

Mr. Chappelle

Mr. Chappelle entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as President and Chief Executive Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Chappelle is terminated by us without cause or he dies or is disabled.

Mr. Chappelle’s employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. Ellis

Mr. Ellis entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Operating Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of thethen-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Ellis is terminated by us without cause or he dies or is disabled.

Mr. Ellis’ employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe

Mr. McCabe entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Financial Officer until March 25, 2018, subject to automatic one year

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renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. McCabe is terminated by us without cause or he dies or is disabled.

Mr. McCabe’s employment agreement provides for a minimum base salary of $435,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe’s employment agreement also provides that he is allowed to work from his residence in Massachusetts as well as in our Houston office so long as he is capable of performing his duties assigned to him. In his employment agreement, we also agree to provide Mr. McCabe with suitable housing (or a housing allowance) and an automobile or reimbursement for the lease of an automobile while he is in Houston.

Mr. Murrell

Mr. Murrell entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President of Land and Business Development until March 25, 2015, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Murrell is terminated by us without cause or he dies or is disabled.

Mr. Murrell’s employment agreement provides for a minimum base salary of $360,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion, subject to a minimum of $50,000.

Outstanding Equity Awards Value at 2016 Fiscal Year-End

There were no outstanding equity awards for our NEOs as of December 31, 2016.

Option Exercises and Equity Awards Vested in Fiscal Year 2016

There were no exercises of equity awards and no vesting of equity awards for our NEOs during fiscal 2016.

Pension Benefits

We do not provide pension benefits for our NEOs.

Nonqualified Deferred Compensation

We established the Retirement Plan, to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees. The Board of Directors administers the Retirement Plan, and at its sole discretion, designates employees who are eligible to participate. Participants may defer up to 90% of their salary and up to 100% of their cash bonus under the Retirement plan. The Board of Directors may also, at its sole discretion, make elective employer contributions on behalf of selected participants. The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us. If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years. Participants may withdraw vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring for a fixed time period or until separation from service with us. The Retirement Plan is an unsecured and unfunded promise to pay deferred cash compensation to its participants, who are our general creditors.

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The following table shows each NEOs accumulated benefits under our nonqualified deferred compensation plans for 2016.

NONQUALIFIED DEFERRED COMPENSATION

Name	Aggregate Balance at December 31, 2015 ($)		Executive Contributions in 2016 ($)		Company Contributions in 2016 ($)(a)			Aggregate Earnings in 2016 ($)		Aggregate Withdrawals / Distributions during 2016 ($)		Aggregate Balance at December 31, 2016 ($)(b)
Harlan H. Chappelle	$	—	$	—	$	1,375,000	(c)	$	—	$	—	$	1,375,000
Michael E. Ellis		—		—		875,000	(c)		—		—		875,000
Michael A. McCabe		3,000,000		—		750,000	(c)		—		—		3,750,000
David Murrell		325,000		—		275,000	(d)		—		—		600,000
Homer “Gene” Cole		500,000		—		450,000	(d)		—		—		950,000

(a) The amounts shown in this column are also included in “All Other Compensation” column on the Summary Compensation Table.

(b) Certain portions shown for each NEO were also reported in the Summary Compensation Table in prior years

(c) The contributions are subject to a five-year vesting schedule, with 20% vested each subsequent year.

(d) The contributions are subject to a five-year vesting schedule, with zero vested in year one and 25% vested each subsequent year beginning in year two of the five-year vesting period.

In 2016, no amounts of salary or bonus were elected to be deferred under the Retirement Plan by any NEO. In 2014, one elective employer contribution was made for the account of Michael A. McCabe. The Board of Directors elected to make this distribution subject to a three-year vesting schedule, with 50% vested immediately and 16.67% to vest each subsequent year. In 2013, one elective employer contribution was made for the account of David Murrell. The Board of Directors elected to make this distribution subject to a four-year vesting schedule, with 20% vested immediately and 20% to vest each subsequent year.

As of fiscal year end 2016, we considered the possibility of payment with respect to outstanding PARs absent the occurrence of a Liquidity Event to be remote. Therefore, no accumulated benefits under the PARs Plan for 2016 has been included. For a description of the PARs Plan, please see the section above entitled “How Alta Mesa Determines Each Element of Compensation—Long-Term Incentives.”

Termination of Employment and Change–in–Control Provisions

Messrs. Chappelle, Ellis, McCabe and Murrell are parties to employment agreements that provide them with post–termination benefits in a variety of circumstances. The amount of compensation payable in some cases may vary depending on the nature of the termination, whether as a result of retirement/voluntary termination, involuntary not–for–cause termination, termination following a change of control and in the event of disability or death of the executive. The discussion below describes the varying amounts payable in each of these situations. It assumes, in each case, that the officer’s termination was effective as of December 31, 2016. In presenting this disclosure, we describe amounts earned through December 31, 2016 and, in those cases where the actual amounts to be paid out can only be determined at the time of such executive’s separation from us, our estimates of the amounts which would be paid out to the executives upon their termination.

Provisions under the Employment Agreements

Under the employment agreements, if the executive’s employment with us terminates, the executive is entitled to unpaid salary for the full month in which the termination date occurred. However, if the executive is terminated for cause, the executive is only entitled to receive accrued but unpaid salary through the termination date. In addition, if the executive’s employment terminates, the executive is entitled to unpaid vacation days for that year which have accrued through the termination date, reimbursement of reasonable business expenses that

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were incurred but unpaid as of the termination date, a pro rata portion of the annual bonus for that year and COBRA coverage as required by law. Salary and accrued vacation days are payable in cash lump sum less applicable withholdings. Business expenses are reimbursable in accordance with normal procedures.

If the executive’s employment is involuntarily terminated by us (except for cause or due to the death of the executive) or if the executive’s employment is terminated due to disability or retirement or by the executive for good reason, we are obligated to pay as additional compensation an amount in cash equal to two years, of the executive’s base salary in effect as of the termination date. Under the terms of Mr. Murrell’s amended and restated employment agreement, as of December 31, 2016, upon such involuntary termination, provides for 18 months’ base salary and two times the annual bonus then in effect. Assuming termination as of December 31, 2016, for both Messrs. Chappelle and Ellis, the termination benefit would have been $970,000; for Mr. McCabe, $870,000; and for Mr. Murrell, $540,000. In addition, all vested amounts in the executive’s account balance under the Retirement Plan would be distributed. Assuming termination as of December 31, 2016, Mr. Chappelle, Mr. Ellis, Mr. McCabe and Mr. Murrell would have received a distribution of $275,000, $175,000, $2,650,000 and $260,000. Our executives are each entitled under their employment agreements to continued group health plan coverage following the termination date for the executive and the executive’s eligible spouse and dependents for the maximum period for which such qualified beneficiaries are eligible to receive COBRA coverage. For the first twelve months of COBRA coverage, the executive shall not be required to pay more for COBRA coverage than officers who are then in active service for us and receiving coverage under the plan. Assuming termination as of December 31, 2016, for each of Messrs. Chappelle, Ellis, McCabe, and Murrell, this amount would have been $12.00 to each. Our total cost of providing this benefit would have been $20,830 for Mr. Chappelle, $30,422 for Mr. Ellis, $20,830 for Mr. McCabe, and $20,830 for Mr. Murrell.

“Cause” means:

• the executive’s conviction by a court of competent jurisdiction of a crime involving moral turpitude or a felony, or entering the plea ofnolo contendere to such crime by the executive;

• the commission by the executive of a demonstrable act of fraud, or a misappropriation of funds or property, of or upon us or any affiliate;

• the engagement by the executive without approval of us and the Board of Directors in any material activity which directly competes with the business of us or any affiliate or which would directly result in a material injury to the business or reputation of us or any affiliate (including the partners of Alta Mesa); or

• the breach by the executive of any material provision of the employment agreement, and the executive’s continued failure to cure such breach within a reasonable time period set by us but in no event less than twenty calendar days after the executive’s receipt of such notice.

“Good reason” means the occurrence of any of the following, if not cured and corrected by us or our successor, within 60 days after written notice thereof is provided by the executive to us or our successor:

• the demotion or reduction in title or rank of the executive, or the assignment to the executive of duties that are materially inconsistent with the executive’s current positions, duties, responsibilities and status with us, or any removal of the executive from, or any failure to re-elect the executive to, any of such positions (other than a change due to the executive’s disability or as an accommodation under the Americans with Disabilities Act), except for any such demotion, reduction, assignment, removal or failure that occurs in connection with (i) the executive’s termination of employment for cause, disability or death, or (ii) the executive’s prior written consent;

• the reduction of the executive’s annual base salary or bonus opportunity as effective immediately prior to such reduction without the prior written consent of the executive; or

• a relocation of the executive’s principal work location to a location in excess of 50 miles from its then current location.

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“Retirement” means the termination of the executive’s employment for normal retirement at or after attaining age 70, provided that the executive has been with us for at least five years.

The employment agreements do not separately provide for benefits upon a change of control.

The Retirement Plan generally defines “cause” as above for the employment agreements. Under the terms of the Retirement Plan, separation from service for any reason other than cause would result in a distribution event for the participant’s vested account balance. The terms of the Retirement Plan also include provisions whereby each participant’s account balance becomes immediately fully vested if the participant (i) is terminated during the first year after a change in control event for any reason other than cause or (ii) terminates due to death or disability. Normal retirement age is defined under the Plan as 65 years of age.

Compensation of Directors

The employee and non-employee members of the Board of Directors do not receive compensation for their services as directors. However, our directors may be reimbursed for their expenses in attending Board of Directors meetings.

Compensation Committee Interlocks and Insider Participation

We do not currently have a compensation committee or an equivalent committee. None of our NEOs has served as a director or member of the compensation committee of any other entity whose executive officers served as a director or member of our compensation committee.

THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our Amended Partnership Agreement.

Organization and Duration

We were organized in September 2005 and will have a perpetual existence.

Purpose

Our purpose under the Amended Partnership Agreement is to engage in any lawful act or activity for which limited partnerships may be formed under the Texas Business Organizations Code.

Units

The units in the Company are divided into non-economic general partner interests owned by the General Partner (“GP Units”) and two classes of non-voting economic units referred to as “Class A Units” and “Class B Units” with the relative rights and obligations specified in the Amended Partnership Agreement. HMH holds 88.0552% of our Class A Units and 99.8002% of our Class B Units. Riverstone owns 11.7650% of our Class A Units. The General Partner’s interest in the Company is represented by GP Units, Class A Units and Class B Units.

Capital Contributions

At any time the General Partner determines that additional funds are required to operate the Company, the General Partner may, on a class-by-class basis, request that the Limited Partners of a class make additional

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Capital Contributions and, in such case, shall issue in exchange therefor additional LP Units of such class;provided,however, no Limited Partner shall be obligated or (other than in accordance with the Amended Partnership Agreement) permitted to make any additional Capital Contributions. Subject to the Amended Partnership Agreement, the terms and conditions of any additional Capital Contribution shall be determined by the General Partner.

Distributions

The Amended Partnership Agreement specifies the manner in which we will make cash distributions to our partners.

Distributions from Operations. Current distributions of Net Cash Flow and distributions upon the liquidation, sale, merger, consolidation, dissolution or winding up of the Company shall be made by the General Partner as described below. The General Partner shall have sole discretion to determine the timing of any distribution and the aggregate amounts available for such distribution and such distributions will be made:

• With respect to distributions of Net Cash Flow attributable to the STACK Assets, one hundred percent (100%) to the Class A Partners Pro Rata. Notwithstanding the foregoing, to the extent the Partnership makes a payment under the Founder Notes, such payment shall be treated as an advance against and, thus, shall reduce the amount otherwise distributable to the High Mesa Holder under the Partnership Agreement.

• With respect to distributions of Net Cash Flow attributable to the Non-STACK Assets, one hundred percent (100%) to the Class B Partners Pro Rata.

“Net Cash Flow” means all cash flow, receipts and revenues generated by the Company minus amounts necessary for (i) Operating Expenses (as such term is defined in the Amended Partnership Agreement), (ii) a reserve fund for future Operating Expenses, (iii) debt service of the Company, or (iv) any other expenses of the Company.

“STACK Assets” means (a) interests in each of Alta Mesa Finance Services Corp., a Delaware corporation, Oklahoma Energy Acquisitions, LP, a Texas limited partnership, and Alta Mesa Services, LP, a Texas limited partnership, (b) all assets held by each of the foregoing as of the date hereof and (c) all oil and gas properties acquired by the Partnership or any of its subsidiaries after the date hereof in any of Kingfisher, Garfield, Major, Blaine, Logan, Canadian, Dewey, Woodward and Oklahoma counties, in each case, in the State of Oklahoma.

Distributions upon Liquidation. Upon dissolution of the partnership, the Limited Partners shall select a liquidator, and the assets of the partnership shall be liquidated and the proceeds thereof shall be applied in the following order:

• first, to the satisfaction of the partnership’s liabilities to creditors in the order of priority required by law, including the creation of a reasonable reserve for reasonably foreseeable contingent liabilities to be distributed when and as the General Partner determines; and

• thereafter, to the partners as set forth above in “Distribution from Operations”, which is intended to be consistent with a liquidation in accordance with relative capital account balances.

Management by General Partner

Generally, our General Partner has full, complete, and exclusive power and authority to manage and control the business, affairs, and properties of the Company, to make all decisions regarding the same, and to perform any and all other acts or activities customary or incident to the management of our business.

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Limitation on Transfers

Our Amended Partnership Agreement places certain limitations on the ability of Class A Limited Partners to transfer their Class A Units:

Direct Transfers.Except for Transfers to Permitted Transferees, each Limited Partner may Transfer or Pledge all or any of its Units only with the consent of the General Partner;provided,however, that, from and after August 31, 2019, any Partner may Transfer or Pledge all or any of its Units without the consent of the General Partner and, in the case of a Transfer by Riverstone, without the need to comply with the Tag-Along Rights section of the Amended Partnership Agreement, and, notwithstanding anything to the contrary herein, such transferee shall become a Substitute Partner upon such Transfer.

“Permitted Transfer” means, with respect to any Limited Partner, (a) a Transfer to an Affiliate of such Limited Partner, (b) a Transfer by a Limited Partner that is an individual by gift to, or for the benefit of, any member or members of such Limited Partner’s immediate family (which shall include any spouse, lineal ancestor or descendant or sibling) or to a trust, partnership or limited liability company for the benefit of such family members;provided,however, that such Limited Partner (or, in the case of a trust, such Limited Partner or the trustees of such trust immediately prior to such Transfer or their successors) retains sole and exclusive control over the voting and disposition of such Units until the termination of the Amended Partnership Agreement, or (c) any Transfer by a Limited Partner that is an individual to the heirs, executors or legatees of such Limited Partner by operation of law upon the death or incapacity of such Limited Partner.

Tag-Along Right. If any Partner (the “Tag-Along Partner”) proposes to transfer all or any portion of its Units to any prospective purchaser (other than pursuant to a Permitted Transfer) either in a single transfer or in a series of related transfers, then each of the other Partners holding the same class of Units that the Tag-Along Partner elects to Transfer, may, subject to the other provisions of the Amended Partnership Agreement, require the Tag-Along Partner to include in the Tag-Along Sale a proportionate number of its Units.

Drag-Along Right. In the event that the General Partner proposes to Transfer all of the Units of the Company to a third party, then the General Partner shall have the right to require the other Partners to sell all of those other Partners’ Units to such third party in connection with that sale on the same terms and conditions as the General Partner (a “Drag-Along Transaction”);provided, however, that, until August 31, 2019, the General Partner shall not have such right in respect of any transaction for which the aggregate consideration to be received by Riverstone will not equal or exceed an amount equal to (i) the aggregate Capital Contributions made by Riverstone, minus (ii) the aggregate distributions made to Riverstone. Such right shall be exercisable by written notice (a “Drag-Along Notice”) given by the General Partner to each Partner other than the General Partner which shall (i) state the purchase price per Unit for each class of Unit to be sold (which shall be based on the fair market value of the assets and liabilities indirectly attributable to such class of Units), (ii) state all other material terms and conditions of that sale (including the identity of the Third Party) and (iii) be accompanied by the written transfer agreement between the General Partner and that Third Party. Upon receipt of a Drag-Along Notice, each Partner shall be obligated to approve and participate in the Drag-Along Transaction in accordance with the terms set forth in the Amended Partnership Agreement.

General Partner Transfer Restrictions. The General Partner may transfer or Pledge its Units only upon the approval of the Limited Partners that hold in the aggregate more than fifty percent (50%) of all Units in the Company then entitled to vote (which, unless such transfer is to an affiliate of the General Partner or in connection with a Drag-Along Transaction, must include the approval of Riverstone) of each class of Units.

Withdrawal or Removal of the General Partner

The General Partner shall serve in such capacity unless and until replaced pursuant to the Amended Partnership Agreement. In the event of the death, liquidation, dissolution, bankruptcy, withdrawal, or disability

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of any Person named as General Partner, the Limited Partners shall appoint a successor General Partner who must be approved by the Limited Partners that hold in the aggregate more than fifty percent (50%) of all Units in the Company then entitled to vote (which, unless such successor is the result of a Transfer in connection with a Drag-Along Transaction or is an Affiliate of the General Partner, must include the approval of Riverstone), excluding in such computation the Unit(s) of the then General Partner.

Other Activities of the Partners

Neither the Amended Partnership Agreement nor the relationship created thereby shall preclude or limit, in any respect, the right of the partners to engage, directly or indirectly, through participation, investment, or otherwise, in any opportunity or business of any type, including those that may be the same as or similar to us or our business, those that compete with us, and those in which we have invested. The partners shall not have any obligation to offer to us or any other partner the right to participate in any such activity. Neither the Company nor the partners shall have any right, by virtue of the Amended Partnership Agreement or the relationship created by the Amended Partnership Agreement, with respect to any such activity.

Amendment of the Amended Partnership Agreement

Except as otherwise provided in our Amended Partnership Agreement, the Amended Partnership Agreement may not be amended, altered, or modified except by an instrument in writing approved by the Limited Partners that hold in the aggregate more than fifty percent (50%) of all Units in the Company then entitled to vote (or the duly-authorized agent of any party), excluding each Partner who has Transferred its entire interest in the Partnership to an Assignee;provided,however, no amendment, alternation, modification or waiver of the Amended Partnership Agreement shall be effected that materially, adversely and disproportionately (as compared to other Limited Partners holding Class A Units) affects the rights of Riverstone under certain sections in the Amended Partnership Agreement without the approval of Riverstone.

Dissolution

We will dissolve upon the first to occur of any of the following events or occurrences, and upon no other event or occurrence:

• The bankruptcy, death, disability, declaration of incompetence, or any other occurrence that would legally disqualify the last remaining General Partner from acting under the Amended Partnership Agreement;

• The retirement, resignation, or withdrawal from the Partnership by the last remaining General Partner;

• The execution by all the Partners of an instrument requiring the winding-up of the Partnership; or

• An event requiring such action pursuant to TBOC.

Organizational Expenses

Under our Amended Partnership Agreement, the partnership is responsible for all out-of-pocket fees, costs and expenses actually incurred by the General Partner and its affiliates and paid to third parties in connection with: (a) maintaining the continued organization and existence of the partnership; (b) the qualification of the partnership to do business in any state in which the General Partner determines that such qualification is advisable; (c) the legal (including tax advice) and accounting fees and disbursements of the partnership; and (d) other out-of-pocket expenses of a similar nature incurred by the General Partner or its affiliates and paid to third parties in connection with such activities.

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Reimbursement of Expenses

Our Amended Partnership Agreement does not allow us to reimburse for the General Partner for its overhead allocable to the business of the Partnership;provided, however, we shall reimburse the General Partner for any and all reasonable out-of-pocket expenses, fees, and costs incurred in connection with the organization, business, and affairs of the Partnership.

Indemnification

To the fullest extent permitted by law, none of (a) the General Partner, the Limited Partners, the Tax Representative and their respective partners, members, officers, directors, managers, employees, agents, owners, and stockholders, (b) each Person not identified in clause (a) of this definition who is a director or officer of any subsidiary of the Partnership and (c) any other Person the General Partner designates as an “Indemnitee” under the Amended Partnership Agreement (each an “Indemnitee”), shall be liable to the Partnership or any Limited Partner for any act or omission taken or suffered by the Indemnitee in connection with the conduct of the affairs of the Partnership, unless such Indemnitee’s conduct constituted fraud, bad faith or willful misconduct.

To the fullest extent permitted by law, the Partnership shall indemnify and hold harmless each Indemnitee from and against any and all claims, liabilities, damages, losses, costs and expenses (including amounts paid in satisfaction of judgments, in compromises and settlements, as fines and penalties and legal or other costs and reasonable expenses, including attorneys’ fees, and of investigating or defending against any claim or alleged claim) of any nature whatsoever, known or unknown, liquidated or unliquidated, that are incurred by any Indemnitee and arise out of or in connection with the affairs of the Partnership or in connection with the Partnership’s business (collectively, the “Indemnified Expenses”);provided, however, an Indemnitee shall not be entitled to indemnification hereunder if and to the extent that there is a final adjudication, in an underlying action or Proceeding in which the Indemnified Expenses were incurred, that the Indemnitee’s conduct constituted fraud, bad faith or willful misconduct.

The Partnership may, as determined by the General Partner, pay or reimburse the Indemnified Expenses reasonably incurred by an Indemnitee that may be subject to a right of indemnification hereunder as those expenses are incurred in advance of any final disposition;provided, however, the Partnership may, as determined by the General Partner, condition that advancement on receipt of an undertaking by or on behalf of the Indemnitee to repay the full amount advanced if there is a final adjudication, in the underlying action or Proceeding in which the Indemnified Expenses were incurred, that the Indemnitee’s conduct constituted fraud, bad faith or willful misconduct.

The Partnership and each Partner acknowledges that certain of the Indemnitees (“Sponsor Indemnitees”) have certain rights to indemnification, advancement of expenses or insurance provided by certain other Persons (collectively, the “Sponsor Indemnitors”). The Partnership agrees, and the Partners acknowledge, that (a) to the extent legally permitted and as required by the terms of the Amended Partnership Agreement and the Certificate (or by the terms of any other agreement between the Partnership and a Sponsor Indemnitee), (i) the Partnership is the indemnitor of first resort (i.e., its obligations to each Sponsor Indemnitee are primary and any obligation of the Sponsor Indemnitors to advance expenses or to provide indemnification for the same expenses or liabilities incurred by any Sponsor Indemnitee are secondary) and (ii) the Partnership shall be required to advance the full amount of expenses incurred by a Sponsor Indemnitee and shall be liable for the full amount of all expenses, judgments, penalties, fines and amounts paid in settlement, without regard to any rights that a Sponsor Indemnitee may have against the Sponsor Indemnitors and (b) the Partnership irrevocably waives, relinquishes and releases the Sponsor Indemnitors from any and all claims for contribution, subrogation or any other recovery of any kind in respect of any of the matters described in clause (a) of this sentence for which any Sponsor Indemnitee has received indemnification or advancement from the Partnership. The Partnership further agrees

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that no advancement or payment by the Sponsor Indemnitors on behalf of any Sponsor Indemnitee with respect to any claim for which a Sponsor Indemnitee has sought indemnification from the Partnership shall affect the foregoing and that the Sponsor Indemnitors shall have a right of contribution and/or be subrogated to the extent of such advancement or payment to all of the rights of recovery of such Sponsor Indemnitee against the Partnership.

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SECURITY OWNERSHIP OFCERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the limited partnership interests in Alta Mesa beneficially owned as of the date of this prospectus by:

• all persons who, to the knowledge of our management team, beneficially own more than 5% of our outstanding limited partnership interests;

• each current director of our General Partner;

• each executive officer of our General Partner named in the Summary Compensation Table; and

• all current directors and executive officers of the General Partner as a group.

As of September 25, 2017, we had 1,000 Class A units and 900 Class B Units issued and outstanding.

Name of Beneficial Owner(1)	Number of Class A Units Beneficially Owned		Percentage of Class A Units Beneficially Owned			Number of Class B Units Beneficially Owned		Percentage of Class B Units Beneficially Owned
Certain Beneficial Owners
High Mesa Holdings, LP(2)		881		88.06	%		898		99.80	%
Riverstone VI Alta Mesa Holdings, L.P.(3)		118		11.77	%		—		—
Officers and Directors
Michael E. Ellis		—		—			—		—
Mickey Ellis		—		—			—		—
Harlan H. Chappelle		—		—			—		—
Don Dimitrievich		—		—			—		—
Michael A. McCabe		—		—			—		—
David Murrell		—		—			—		—
Homer “Gene” Cole		—		—			—		—
William W. McMullen		—		—			—		—
Mark Stoner		—		—			—		—
Directors and principal officers as a group (9) persons)		—		—			—		—

(1) Unless otherwise indicated, each of the persons listed in the table may be deemed to have sole voting and dispositive power with respect to such shares and the address for all beneficial owners in this table is at 15021 Katy Freeway, Suite 400, Houston, Texas 77094.

(2) High Mesa Holdings, GP, the general partner of High Mesa Holdings, LP (“HMH GP”), has voting and dispositive power over these shares. The board of managers of HMH GP consists of Michael Ellis, Mickey Ellis, Harlan Chappelle, Don Dimitrievich, Michael McCabe, Gene Cole, William McMullen and Mark Stoner. None of such persons individually have voting and dispositive power over these shares, and the board of managers of HMH GP acts by majority vote, or unanimous vote under certain circumstances, and thus each such person is not deemed to beneficially own the shares held by HMH GP. AM MME Holdings, LP (“AM MME”) owns 100% of the Class A interests of HMH GP, and High Mesa, Inc. owns 100% of the Class B interests of HMH GP. As a result, AM MME and High Mesa, Inc. may each be deemed to share voting and dispositive power over these shares. AM MME and High Mesa, Inc. disclaim beneficial ownership of these shares except to the extent of their respective pecuniary interest therein. Michael Ellis, our founder, chairman and chief operating officer, and his wife Mickey Ellis, one of our directors, own and control AM MME. Mr. and Mrs. Ellis also have an indirect beneficial interest and voting control over all Class A and Class B units held by High Mesa through Alta Mesa Resources, LP, Galveston Bay Resources Holdings, LP, Petro Acquisition Holdings, LP and Petro Operating Company Holdings, Inc., which are owned by Michael E. Ellis and Mickey Ellis, and own an aggregate 74.1% interest in the common stock of High Mesa. As a result, Mr. and Mrs. Ellis may be deemed to share voting and dispositive power over the

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reported shares and therefore may also be deemed to be the beneficial owner of these shares. Mr. and Mrs. Ellis disclaim beneficial ownership of these shares except to the extent of their pecuniary interest therein.

(3) Riverstone VI Alta Mesa Holdings, L.P. (“Riverstone”) is the record holder of the securities reported herein. David M. Leuschen and Pierre F. Lapeyre, Jr. are the managing directors of Riverstone Holdings LLC, which is the sole shareholder of Riverstone Energy GP VI Corp, which is the sole and managing member of Riverstone Energy GP VI, LLC (“Riverstone Energy GP”), which is the general partner of Riverstone Energy Partners VI, L.P., which is the managing member of Riverstone Energy VI Holdings GP, LLC, which is the general partner of Riverstone. Riverstone Energy GP is managed by a managing committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, James T. Hackett, Michael B. Hoffman, N. John Lancaster, Mark G. Papa and, on a rotating basis, one of E. Bartow Jones, Baran Tekkora and Robert M. Tichio. Each of Riverstone Energy VI Holdings GP, LLC, Riverstone Energy Partners VI, L.P., Riverstone Energy GP, Riverstone Energy GP VI Corp, Riverstone Holdings, LLC, Mr. Leuschen and Mr. Lapeyre may be deemed to have or share beneficial ownership of the securities held directly by Riverstone. The business address for each of the entities and individuals listed in this footnote is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 36th Floor, New York, NY 10019.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

We do not have any formal policy with respect to the review and approval of related party transactions. A “Related Party Transaction” is any transaction, arrangement or relationship where we are a participant, the Related Party (defined below) had, has or will have a direct or indirect material interest, and the aggregate amount involved is expected to exceed $120,000 in any calendar year. “Related Party” includes (a) any person who is or was (at any time during the last fiscal year) an executive officer, director or nominee for election as a director; (b) any person or group who is a beneficial owner of more than 5% of our voting securities; (c) any immediate family member of a person described in provisions (a) or (b) of this sentence; or (d) any entity in which any of the foregoing persons is employed, is a partner or has a greater than 5% beneficial ownership interest.

Ownership in Us and Our General Partner

Michael E. Ellis, our Chairman and Chief Operating Officer, and his spouse Mickey Ellis, one of our directors, indirectly own 85.06% of our Class A interests. Our General Partner is owned by (1) Alta Mesa Resources, LP, an entity owned by Michael E. Ellis and Mickey Ellis, and (2) High Mesa. Our General Partner has a 0.18% interest in us.

During 2016 and 2015 Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received no capital distributions from us.

During 2016 and 2015, High Mesa Inc. contributed $300 million and $20 million to us, respectively. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us. High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected subsequent to year end.

Founder Notes

We were founded in 1987 by Mr. Ellis and we or our subsidiaries have over time entered into promissory notes to repay Mr. Ellis for contributions of working capital and other amounts. The founder notes bear interest at 10.0% paid-in-kind, mature on December 31, 2021 and are unsecured and subordinated to all of our debt. Interest and principal are payable at maturity.

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The founder notes are subordinate to the paid in kind notes of High Mesa, Inc. The founder notes are also subordinated to the rights of HMH and Riverstone to receive distributions under our partnership agreement and subordinated to the rights of the holders of Series B preferred stock of High Mesa, Inc. to receive payments. Our founder shall convert the founder notes into equity interests in HMH immediately prior to the business combination. The aggregate amount payable under the founder notes was $27.0 million and $25.7 million at December 31, 2016 and December 31, 2015, respectively. During the years ended December 31, 2016, 2015 and 2014, no amounts were paid in principal or interest. Interest on the founder notes payable is not compounded and amounted to $1.2 million in each of the years ended December 31, 2016, 2015 and 2014. Such amounts have been added to the balance of the founder notes.

Land Consulting Services

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2016, 2015 and 2014, were approximately $146,000, $133,000 and $150,000. The contract may be terminated by either party without penalty upon 30 days’ notice.

Employee and Distribution

David McClure, our Vice President of Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $425,000, $275,000, and $450,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other Vice Presidents whose duties include field oversight.

David Pepper, one of our landmen, and the cousin of our Vice President of Land and Business Development David Murrell, received total compensation of $180,000, $146,000, and $260,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other landman whose duties include field oversight.

Midstream Asset Sale and Land Purchase

On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to Northwest Gas Processing, LLC (“NWGP”) for $25.5 million cash and short-term note receivable of $8.5 million, while recording no gain or loss on the sale at December 31, 2014. The $8.5 million note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019. Immediately after the consummation of the transaction, NWGP’s obligation under the $8.5 million promissory note was transferred to High Mesa Services, LLC, a subsidiary of High Mesa. On December 31, 2015, we repurchased a small portion of land originally sold to NWGP at cost of $0.7 million.

NWGP Services Agreement

We are party to a services agreement dated January 1, 2016 with NWGP. Pursuant to the agreement, we agree to provide administrative and management services to NWGP relating to the midstream assets we sold to NWGP on December 31, 2014. During the year ended December 31, 2016 NWGP was billed for management services provided in the amount of approximately $0.1 million. High Mesa owns a controlling interest in NWGP.

Joint Development Agreement

Our wholly-owned subsidiary Oklahoma Energy entered into a joint development agreement, dated January 13, 2016, with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations in

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Kingfisher County, Oklahoma. Our General Partner’s directors Mark Stoner and William W. McMullen are partners at Bayou City. The drilling program will fund the development of 80 wells, which will be developed in four tranches of 20 wells each. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells, the Contributed Wells, drilled under the joint development agreement to us. The pre-tax present value discounted at ten percent for the Contributed Wells as of the effective date of October 1, 2016 was approximately $80 million. In connection with the acquisition of the Contributed Wells, the joint development agreement was amended to exclude the Contributed Wells from the drilling program. The drilling program will fund the development of 80 additional wells in four tranches of 20 wells each. BCE has committed to fund 100% of Oklahoma Energy’s working interest share of drilling and development costs for each well in which BCE elects to participate, provided that to the extent that the total cost of drilling the wells in any tranche exceeds $64 million, Oklahoma Energy will be responsible for its and BCE’s working interest share of the drilling costs in such tranche exceeding such limit.

In exchange for the payment of drilling and completion costs, BCE will receive 80% of Oklahoma Energy’s working interest in each Joint Well, which interest will be reduced to 20% of Oklahoma Energy’s initial working interest upon BCE achieving a 15% internal rate of return in a tranche and further reduced to 12.5% of Oklahoma Energy’s initial interest upon BCE achieving a 25% internal rate of return. Upon the achievement of these return thresholds, the interest BCE relinquishes will automatically revert back to Oklahoma Energy. Following the completion of each Joint Well, BCE and Oklahoma Energy will bear their proportionate working interest share of all subsequent costs and expenses related to such Joint Well. The approximate dollar value of the amount involved in this transaction and Messrs. Stoner and McMullen’s interests in the joint development agreement depends on a number of factors outside Messrs. Stoner and McMullen’s control and are not known at this time. As of December 31, 2016, we recorded $42.5 million in advances from related party on our consolidated balance sheets, which represents net advances from BCE for their working interest share of the drilling and development cost as part of our joint development agreement.

Gathering Agreements

On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM, which was subsequently amended on February 3, 2017, effective as of December 1, 2016. High Mesa owns a minority interest in KFM. Alta Mesa also indirectly owns a minimal interest in KFM through its less than 10% ownership of AEM. We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM.

Under the Crude Oil Gathering Agreement and the Gas Gathering and Processing Agreement, Oklahoma Energy dedicates and delivers to KFM crude oil and natural gas and associated natural gas liquids produced from present and future wells located in certain lands in Kingfisher, Logan, Canadian, Blaine and Garfield Counties in Oklahoma to designated receipt points on KFM’s system for gathering and processing. The Crude Oil Gathering Agreement and Gas Gathering and Processing Agreements will remain in effect for a primary term of 15 years from the in-service date of July 1, 2016 and, after the primary term, an extended term for as long as there are wells connected to the system that continue to produce crude oil or gas in commercial (paying) quantities.

Under the Crude Oil Gathering Agreement, KFM operates a crude oil gathering system for the purpose of providing gathering services to Oklahoma Energy. KFM receives from Oklahoma Energy a fixed service fee per barrel of crude oil delivered. The fixed service fee consists of a fee for providing gathering services and is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the crude oil gathering system.

Under the Gas Gathering and Processing Agreement, KFM operates a gas gathering and processing system for the purpose of providing gathering and processing services to Oklahoma Energy. KFM provides gathering and processing services for a fixed fee. The fixed service fee consists of (i) a gathering fee assessed on the

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volume of gas allocated to the central receipt point, (ii) a processing fee assessed on the volume of gas allocated to the central receipt point, (iii) a dehydration fee assessed on the volume of gas allocated to the central receipt point, (iv) a compression fee for each stage of compression for any volume of gas allocated to the central receipt point and (v) a facility fee for the first four years of the agreement, at which time the facility fee is removed. Beginning in January 2021, each fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the gas gathering and processing system. Under the Gas Gathering and Processing Agreement, we have secured firm processing rights of 260 MMcf/d at the expanding KFM plant.

The aggregate amounts paid under the Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement will depend on the volumes produced and gathered pursuant to these agreements. Under such agreements, the fees for the year ended December 31, 2016 were $7.5 million. These fees are recorded as marketing and transportation expense in the consolidated statements of operations. As of December 31, 2016, we accrued approximately $3.0 million as a reduction to the accounts receivable on the consolidated balance sheets for fees related to marketing and transportation for the KFM plant.

Subsequent to year-end, Oklahoma Energy entered into an agreement with KFM whereby we made a deposit of $10.0 million on January 13, 2017 to KFM to provide us with 100,000 Dth/d for firm transportation. The deposit will be released back to us as we utilize the marketing and transportation services in 2018.

Director Independence

Our Board of Directors consists of eight members, four of whom are non-employee directors. Because we only have debt securities registered with the SEC under the Exchange Act and because we do not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, we are not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, our Board of Directors has not made any determination as to whether the non-employee directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

DESCRIPTIONOF CERTAIN INDEBTEDNESS

Senior Secured Revolving Credit Facility

In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. On June 13, 2017, we entered into an Agreement and Amendment No. 2, the “Second Amendment”, to the credit facility which, among other things: (a) increased our borrowing base from $287.5 million to $315.0 million until the next scheduled redetermination and (b) permits us to make a one-time cash distribution of no more than $1.0 million to a limited partner. Our credit facility does not permit us to borrow funds if at the time of such borrowing, after giving pro forma effect to the application of funds from the borrowing, we have available cash in our deposit accounts in excess of $25 million. Our credit facility also does not permit us to borrow funds if at the time of such borrowing we are not in pro forma compliance with our financial covenants.

As of June 30, 2017, we have borrowed $195.7 million under the credit facility and have $5.3 million of outstanding letters of credit reimbursement obligations.

Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest, payable quarterly. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the rate appearing on the Reuters Reference LIBOR01 page as the London Interbank

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Offered Rate (“LIBOR”), for deposits in dollars at 11:00 a.m. (London, England time) for one, three, or six months plus an applicable margin ranging from 275 to 375 basis points if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 300 to 400 basis points if our leverage ratio exceeds 3.25 to 1.00. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus an applicable margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00.

On September 25, 2017, our outstanding borrowing under the credit facility was $111.1 million, letters of credit totaling $5.3 million were outstanding, and the available unused capacity of the borrowing base was $198.6 million. Availability under the credit facility is subject to a borrowing base, as well as financial covenants. The next scheduled redetermination of our borrowing base is in November 2017. Our borrowing base may be reduced in connection with the next redetermination of our borrowing base. The amounts outstanding under our credit facility are secured by first priority liens on substantially all of our oil and natural gas properties and associated assets and all of the stock of our material operating subsidiaries that are guarantors of our credit facility. If an event of default occurs under our credit facility, the administrative agent will have the right to proceed against the pledged capital stock and take control of substantially all of our and our material operating subsidiaries that are guarantors’ assets.

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. Our credit facility permits us to make distributions in any fiscal quarter so long as the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, no event of default exists, before and after giving effect to such distribution, our pro forma leverage ratio is less than 3.00 to 1.00 and before and after giving effect to such distribution the unused commitment amounts available under our credit facility is at least 20% of the commitments in effect.

Our credit facility also requires us to maintain the following two financial ratios:

• a modified current ratio, tested quarterly, of our consolidated current assets to our consolidated current liabilities of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

• a leverage ratio, tested quarterly, commencing with the fiscal quarter ended December 31, 2016, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated EBITDAX over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0.

We were in compliance with all of our covenants at June 30, 2017 and we expect to maintain compliance.

The terms of the credit facility also restrict our ability to make distributions and investments. As of June 30, 2017, the covenants of our credit facility prohibit us from making any distributions, except for the $1.0 million one-time distribution to a limited partner.

Founder Notes

We were founded in 1987 by Mr. Ellis and we or our subsidiaries have over time entered into promissory notes to repay Mr. Ellis for contributions of working capital and other amounts. The founder notes bear interest at 10.0% paid-in-kind, mature on December 31, 2021 and are unsecured and subordinated to all of our debt. Interest and principal are payable at maturity.

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The founder notes are subordinate to the paid in kind notes of High Mesa, Inc. The founder notes are also subordinated to the rights of HMH and Riverstone to receive distributions under our partnership agreement and subordinated to the rights of the holders of Series B preferred stock of High Mesa, Inc. to receive payments. Our founder shall convert the founder notes into equity interests in HMH immediately prior to the business combination. The aggregate amount payable under the founder notes was $27.0 million and $25.7 million at December 31, 2016 and December 31, 2015, respectively. During the years ended December 31, 2016, 2015 and 2014, no amounts were paid in principal or interest. Interest on the founder notes payable is not compounded and amounted to $1.2 million in each of the years ended December 31, 2016, 2015 and 2014. Such amounts have been added to the balance of the founder notes.

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DESCRIPTION OF NEW NOTES

We will issue the new notes under an indenture dated as of December 8, 2016 (the “Indenture”), among the Issuers, the Subsidiary Guarantors and U.S. Bank National Association, as trustee (the “Trustee”). The terms of the new notes include those expressly set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”). Under the Indenture, the Issuers may issue an unlimited principal amount of additional notes having identical terms and conditions as the Notes (the “Additional Notes”). The Issuers will only be permitted to issue such Additional Notes in compliance with the covenant described under the subheading “— Certain Covenants — Limitation on Indebtedness and Preferred Stock”. As used in this “Description of New Notes,” except as otherwise specified, the term “Notes” means the new notes, the old notes and any additional notes that may be issued under the Indenture. All such notes will vote together as a single class for all purposes of the Indenture.

This “Description of New Notes” is intended to be a useful overview of the material provisions of the Notes and the Indenture. Since this description is only a summary, you should refer to these documents for a complete description of the obligations of the Issuers and the Subsidiary Guarantors and your rights. A copy of the Indenture has been filed as an exhibit to the registration statement of which the prospectus is a part.

You will find the definitions of capitalized terms used in this description under the heading “— Certain Definitions”. For purposes of this description, references to “the Co-Issuer” refer only to Alta Mesa Finance Services Corp., the co-issuer of the Notes, and references to “the Company”, “we”, “our” and “us” refer only to Alta Mesa Holdings, LP and not to any of its subsidiaries. The Co-Issuer and the Company are referred to jointly as the “Issuers”.

The registered holder of a new note will be treated as the owner of it for all purposes. Only registered holders of Notes will have rights under the Indenture, and all references to “holders” in this “Description of New Notes” are to registered holders of Notes.

General

The Notes

The Notes:

• will be general unsecured, senior obligations of each Issuer;

• will mature on December 15, 2024;

• will be issued initially in an aggregate principal amount of $500.0 million and in denominations of $2,000 and integral multiples of $1,000 in excess thereof;

• will be represented by one or more registered Notes in global form, but in certain circumstances may be represented by Notes in definitive form, as described in “Book-entry; Delivery and Form”;

• will rank senior in right of payment to any future Subordinated Obligations of each Issuer;

• will rank equally in right of payment to any other existing and future senior Indebtedness of each Issuer, without giving effect to collateral arrangements; and

• will be initially unconditionally guaranteed on a senior unsecured basis by each current Subsidiary of the Company (other than the Co-Issuer and the Initial Unrestricted Subsidiaries) and future Domestic Subsidiaries (other than Immaterial Subsidiaries), as described in “— Subsidiary Guarantees”;

• will effectively rank junior to all Indebtedness of any non-Guarantor Subsidiary of the Company; and

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• will effectively rank junior to any existing or future secured Indebtedness of each Issuer, including under the Senior Secured Credit Agreement, to the extent of the value of the collateral securing such Indebtedness.

The Subsidiary Guarantees

Initially, all of the Subsidiaries of the Company (other than the Co-Issuer and the Initial Unrestricted Subsidiaries) will unconditionally guarantee the Notes on a senior unsecured basis. In addition, future Domestic Subsidiaries (other than Immaterial Subsidiaries) of the Company will guarantee the Notes. See “— Certain Covenants — Future Subsidiary Guarantors”.

Each Subsidiary Guarantee of the Notes:

• will be general unsecured senior obligations of the Subsidiary Guarantor;

• will rank senior in right of payment to any future Guarantor Subordinated Obligations of the Subsidiary Guarantor;

• will rank equally in right of payment to any other existing and future senior Indebtedness of the Subsidiary Guarantor, without giving effect to collateral arrangements;

• will effectively rank junior to all existing and future secured Indebtedness of the Subsidiary Guarantor, including under the Senior Secured Credit Agreement, to the extent of the value of the collateral securing such Indebtedness; and

• will effectively rank junior to all Indebtedness of any non-guarantor Subsidiary of the Subsidiary Guarantor.

Not all of our Subsidiaries will be Subsidiary Guarantors. As of and for the year ended December 31, 2016, on a pro forma basis, our non-Guarantor Subsidiaries collectively held less than 1.0% of our consolidated total assets and generated less than 1.0% of our consolidated revenues and had no outstanding indebtedness. The Notes and Guarantees will effectively be subordinated to the claims of creditors of any non-Guarantor Subsidiaries to the extent of the value of the assets thereof.

Initially, all of the Subsidiaries of the Company (including the Co-Issuer) will be Restricted Subsidiaries except for the Initial Unrestricted Subsidiaries, but under the circumstances described below in the definition of “Unrestricted Subsidiary” under the heading “— Certain Definitions”, the Company may designate certain of its Restricted Subsidiaries as “Unrestricted Subsidiaries”. Unrestricted Subsidiaries will not guarantee the Notes and will not be subject to the restrictive covenants in the Indenture.

Interest

Interest on the Notes will:

• accrue at the rate of 7.875% per annum;

• accrue from the Issue Date or, if interest has already been paid, from the most recent interest payment date;

• be payable in cash semi-annually in arrears on June 15 and December 15;

• be payable to the holders of record on June 1 and December 1 immediately preceding the related interest payment dates; and

• be computed on the basis of a 360-day year comprised of twelve 30-day months.

The Issuers will pay interest on any overdue principal of the Notes and on any overdue installment of interest at the above rate plus 1.0%, to the extent lawful.

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Additional interest may accrue on the Notes as liquidated damages in certain circumstances pursuant to the terms of the Registration Rights Agreement, and all references to “interest” in this description include any additional interest that may be payable on the Notes.

If an interest payment date falls on a day that is not a Business Day, the interest payment to be made on such interest payment date will be made on the next succeeding Business Day with the same force and effect as if made on such interest payment date, and no additional interest will accrue as a result of such delayed payment.

Payments on the Notes; Paying Agent and Registrar

The Issuers will pay principal of, premium, if any, and interest on the Notes at the office or agency designated by us (which, if Notes are issued in certificated form, will be in the City and State of New York), except that they may, at their option, pay interest on the Notes by check mailed to holders of the Notes at their registered address as it appears in the registrar’s books. The Issuers have initially designated the Trustee to act as their paying agent and registrar at the corporate trust office of the Trustee in Houston, Texas. The Issuers may, however, change the paying agent or registrar without prior notice to the holders of the Notes, and the Company or any of its Restricted Subsidiaries may act as paying agent or registrar.

The Issuers will pay principal of, premium, if any, and interest on, Notes in global form registered in the name of Cede & Co., the nominee of The Depository Trust Company, in immediately available funds, directly to The Depository Trust Company.

Transfer and Exchange

A holder may transfer or exchange Notes in accordance with the Indenture. The registrar and the Trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of Notes. No service charge will be imposed by the Issuers, the Trustee or the registrar for any registration of transfer or exchange of Notes, but the Issuers may require a holder to pay a sum sufficient to cover any transfer tax or other governmental taxes and fees required by law or permitted by the Indenture. The Issuers are not required to transfer or exchange any Note selected for redemption. Also, the Issuers are not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

Optional Redemption

On and after December 15, 2019, the Issuers may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days’ notice, at the following redemption prices (expressed as a percentage of principal amount of the Notes), plus accrued and unpaid interest on the Notes, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve-month period beginning on December 15 of the years indicated below:

Year	Percentage
2019		105.906	%
2020		103.938	%
2021		101.969	%
2022 and thereafter		100.000	%

Prior to December 15, 2019, the Issuers may, at their option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the Notes (including Additional Notes) issued under the Indenture with

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the Net Cash Proceeds of one or more Equity Offerings at a redemption price of 107.875% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date);provided that

(1) at least 65% of the aggregate principal amount of the Notes (including Additional Notes) issued under the Indenture remains outstanding after each such redemption; and

(2) the redemption occurs within 120 days after the closing of the related Equity Offering.

In addition, the Notes may be redeemed, in whole or in part, at any time prior to December 15, 2019 at the option of the Issuers upon not less than 30 nor more than 60 days’ prior notice given to each holder of Notes as provided in the indenture, at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest to, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

“Applicable Premium” means, with respect to any Note on any applicable redemption date, the greater of:

(1) 1.0% of the principal amount of such Note; or

(2) the excess, if any, of:

(a) the present value at such redemption date of (i) the redemption price of such Note at December 15, 2019 (such redemption price being set forth in the table appearing in the first paragraph of this “Optional Redemption” section) plus (ii) all required interest payments (excluding accrued and unpaid interest to such redemption date) due on such Note through December 15, 2019, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(b) the principal amount of such Note.

“Treasury Rate” means, as of any redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) which has become publicly available at least two Business Days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to December 15, 2019;provided,however, that if the period from the redemption date to December 15, 2019 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to December 15, 2019 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used. The Company will (a) calculate the Treasury Rate as of the second Business Day preceding the applicable redemption date and (b) prior to such redemption date file with the Trustee an Officers’ Certificate setting forth the Applicable Premium and the Treasury Rate and showing the calculation of each in reasonable detail.

Selection and Notice

If the Issuers are redeeming less than all of the outstanding Notes, the Trustee will select the Notes for redemption in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed or, if the Notes are not listed, then on a pro rata basis (or, in the case of Notes issued in global form as discussed under the caption “Book-Entry; Delivery and Form”, the Trustee will select the Notes for redemption based on DTC’s method that most nearly approximates a pro rata selection), by lot or by such other method as the Trustee in its sole discretion will deem to be fair and appropriate, although no Note of $2,000 in original principal amount or less will be redeemed in part. If any Note is to be redeemed in part only, the notice

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of redemption relating to such Note will state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the partially redeemed Note. On and after the redemption date, interest will cease to accrue on Notes or the portion of them called for redemption unless we default in the payment thereof.

Mandatory Redemption; Offers to Purchase; Open Market Purchases

We are not required to make mandatory redemption payments or sinking fund payments with respect to the Notes. However, under certain circumstances, we may be required to offer to purchase Notes as described under the captions “— Change of Control” and “— Certain Covenants — Limitation on Sales of Assets and Subsidiary Stock”.

The Company and its Subsidiaries may acquire Notes by means other than a redemption or required repurchase, whether by tender offer, open market purchases, negotiated transactions or otherwise, in accordance with applicable securities laws, so long as such acquisition does not otherwise violate the terms of the Indenture. However, other existing or future agreements of the Company or its Subsidiaries may limit the ability of the Company or its Subsidiaries to purchase Notes prior to maturity.

Subsidiary Guarantees

The Subsidiary Guarantors will, jointly and severally, fully and unconditionally guarantee on a senior unsecured basis our obligations under the Notes and all obligations under the Indenture. The obligations of each of the Subsidiary Guarantors under the Subsidiary Guarantees will rank equally in right of payment with all other Indebtedness of such Subsidiary Guarantor, except to the extent such other Indebtedness is expressly subordinated in right of payment to the obligations arising under its Subsidiary Guarantee.

Although the Indenture will limit the amount of Indebtedness that the Subsidiary Guarantors may Incur, such Indebtedness may be substantial and such limitation is subject to a number of significant qualifications. Moreover, the Indenture does not impose any limitation on the Incurrence by the Subsidiary Guarantors of liabilities that are not considered Indebtedness under the Indenture. See “— Certain Covenants — Limitation on Indebtedness and Preferred Stock”.

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law, although no assurance can be given that a court would give the holder the benefit of such provision. See “Risk Factors — Risks Related to the New Notes — Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payment received from guarantors.” Any guarantees of the notes by us or our operating subsidiaries could be deemed fraudulent conveyances under certain circumstances, and a court may subordinate or void the guarantees. If a Subsidiary Guarantee were rendered voidable, it could be subordinated by a court to all other indebtedness (including guarantees and other contingent liabilities) of the applicable Subsidiary Guarantor, and, depending on the amount of such indebtedness, a Subsidiary Guarantor’s liability on its Subsidiary Guarantee could be reduced to zero. If the obligations of a Subsidiary Guarantor under its Subsidiary Guarantee were avoided, holders of Notes would have to look to the assets of any remaining Subsidiary Guarantors for payment. There can be no assurance in that event that such assets would suffice to pay the outstanding principal and interest on the Notes.

In the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of all of its Capital Stock or the sale of all or substantially all of its assets (other than by lease) and whether or not the Subsidiary Guarantor is the surviving entity in such transaction) to a Person which is not the Company or a Subsidiary of the Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if the sale or other disposition does not violate the covenants described under “— Certain Covenants — Limitation on Sales of Assets and Subsidiary Stock”.

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In addition, a Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee, (a) if the Company designates such Subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the Indenture or if such Subsidiary otherwise no longer qualifies as such, (b) upon the liquidation or dissolution of such Subsidiary Guarantor in a transaction or series of transactions that does not violate the terms of the Indenture, or (c) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the Notes as provided below under the captions “— Defeasance” and “— Satisfaction and Discharge”.

Change of Control

If a Change of Control occurs, unless the Issuers have previously or concurrently exercised their right to redeem all of the Notes as described under “— Optional Redemption”, each holder will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of such holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Within 30 days following any Change of Control, unless the Issuers have previously or concurrently exercised their right to redeem all of the Notes as described under “— Optional Redemption”, we will provide notice (the “Change of Control Offer”) to each holder, with a copy to the Trustee, stating:

(1) that a Change of Control has occurred and that such holder has the right to require us to purchase such holder’s Notes at a purchase price in cash equal to 101% of the principal amount of such Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date) (the “Change of Control Payment”);

(2) the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is provided) (the “Change of Control Payment Date”);

(3) that any Note not properly tendered will remain outstanding and continue to accrue interest;

(4) that unless we default in the payment of the Change of Control Payment, all Notes accepted for payment pursuant to the Change of Control Offer will cease to accrue interest on the Change of Control Payment Date;

(5) that holders electing to have any Notes purchased pursuant to a Change of Control Offer will be required to surrender such Notes, with the form entitled “Option of Holder to Elect Purchase” on the reverse of such Notes in certificated form completed, to the paying agent specified in the notice at the address specified in the notice prior to the close of business on the third Business Day preceding the Change of Control Payment Date;

(6) that holders will be entitled to withdraw their tendered Notes and their election to require us to purchase such Notes,provided that the paying agent receives, not later than the close of business on the third Business Day preceding the Change of Control Payment Date, a telegram, telex, facsimile transmission or letter setting forth the name of the holder of the Notes, the principal amount of Notes tendered for purchase, and a statement that such holder is withdrawing its tendered Notes and its election to have such Notes purchased;

(7) that if we are repurchasing a portion of the Note of any holder, the holder will be issued a new Note equal in principal amount to the unpurchased portion of the Note surrendered,provided that the unpurchased portion of the Note must be equal to a minimum principal amount of $2,000 and an integral multiple of $1,000 in excess thereof; and

(8) the procedures determined by us, consistent with the Indenture, that a holder must follow in order to have its Notes repurchased.

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On the Change of Control Payment Date, the Company will, to the extent lawful:

(1) accept for payment all Notes or portions of Notes (in a minimum principal amount of $2,000 and integral multiples of $1,000 in excess thereof) properly tendered pursuant to the Change of Control Offer and not properly withdrawn;

(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes accepted for payment; and

(3) deliver or cause to be delivered to the Trustee the Notes so accepted together with an Officers’ Certificate stating the aggregate principal amount of Notes or portions of Notes being purchased by the Company.

The paying agent will promptly mail or deliver to each holder of Notes accepted for payment the Change of Control Payment for such Notes, and the Trustee, upon delivery of a written request from the Company, will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any;provided that each such new Note will be in a minimum principal amount of $2,000 or an integral multiple of $1,000 in excess thereof.

If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest, will be paid to each Person in whose name a Note is registered at the close of business on such record date, and no further interest will be payable to holders who tender pursuant to the Change of Control Offer.

The Change of Control provisions described above will be applicable whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture will not contain provisions that permit the holders to require that the Company or any Subsidiary repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

We will not be required to make a Change of Control Offer upon a Change of Control if any other Person makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by us and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer.

A Change of Control Offer may be made in advance of a Change of Control, and conditioned upon the occurrence of a Change of Control, if a definitive agreement is in place for the Change of Control at the time of making the Change of Control Offer.

We will comply, to the extent applicable, with the requirements of Rule 14e-1 of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, we will comply with the applicable securities laws and regulations and will not be deemed to have breached our obligations under in the Indenture by virtue of our compliance with such securities laws or regulations.

Our ability to repurchase Notes pursuant to a Change of Control Offer may be limited by a number of factors. The occurrence of certain of the events that constitute a Change of Control would constitute a default under the Senior Secured Credit Agreement. In addition, certain events that may constitute a change of control under the Senior Secured Credit Agreement and cause a default under that agreement will not constitute a Change of Control under the Indenture. Future Indebtedness of the Company and its Subsidiaries may also contain prohibitions of certain events that would constitute a Change of Control or require such Indebtedness to be repaid upon a Change of Control. Moreover, the exercise by the holders of their right to require us to repurchase the Notes could cause a default under other Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company and its Restricted Subsidiaries. Finally, the

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Company’s ability to pay cash to the holders upon a repurchase may be limited by the then existing financial resources of the Company and its Restricted Subsidiaries. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

Even if sufficient funds were otherwise available, the other Indebtedness of the Company or its Restricted Subsidiaries may prohibit the Company’s repurchase of Notes before their scheduled maturity. Consequently, if the Company and its Restricted Subsidiaries are not able to prepay the Indebtedness under the Senior Secured Credit Agreement or any such other Indebtedness containing similar restrictions or obtain requisite consents, the Company will be unable to fulfill its repurchase obligations if holders of Notes exercise their repurchase rights following a Change of Control, resulting in a default under the Indenture. A default under the Indenture may result in a cross-default under the Senior Secured Credit Agreement.

The Change of Control provisions described above may deter certain mergers, tender offers and other takeover attempts involving the Company. The Change of Control purchase feature is a result of negotiations between the initial purchasers and the Company. As of the Issue Date, the Company has no present intention to engage in a transaction involving a Change of Control, although it is possible that it could decide to do so in the future. Subject to the limitations discussed below, the Company or its Subsidiaries could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of indebtedness outstanding at such time or otherwise affect our capital structure or credit ratings. Restrictions on the ability of the Company and its Restricted Subsidiaries to incur additional Indebtedness are contained in the covenants described under “— Certain Covenants — Limitation on Indebtedness and Preferred Stock” and “— Certain Covenants — Limitation on Liens”. Such restrictions in the Indenture can be waived only with the consent of the holders of a majority in principal amount of the Notes then outstanding. Except for the limitations contained in such covenants, however, the Indenture will not contain any covenants or provisions that may afford holders of the Notes protection in the event of a highly leveraged transaction.

The definition of “Change of Control” includes a disposition of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any Person. Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the assets of a Person. As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of Notes may require the Company to make an offer to repurchase the Notes as described above.

The provisions under the Indenture relative to our obligation to make an offer to repurchase the Notes as a result of a Change of Control may be waived or modified or terminated with the consent of the holders of a majority in principal amount of the Notes then outstanding (including consents obtained in connection with a tender offer or exchange offer for the Notes), but only if done prior to the occurrence of such Change of Control.

Certain Covenants

Limitation on Indebtedness and Preferred Stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, Incur any Indebtedness (including Acquired Indebtedness), and the Company will not permit any of its Restricted Subsidiaries to issue Preferred Stock;provided,however, that the Issuers and any of the Subsidiary Guarantors may Incur Indebtedness and issue Preferred Stock if on the date thereof:

(1) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.25 to 1.00, determined on a pro forma basis (including a pro forma application of proceeds); and

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(2) no Default would occur as a consequence of, and no Event of Default would be continuing following, Incurring the Indebtedness or its application.

The first paragraph of this covenant will not prohibit the Incurrence of the following:

(1) Indebtedness under one or more Credit Facilities (including the Senior Secured Credit Agreement) Incurred pursuant to this clause (1) by the Issuers or any Subsidiary Guarantor in an aggregate amount outstanding at any one time not to exceed the greatest of (i) $300.0 million, (ii) 35.0% of the Company’s Adjusted Consolidated Net Tangible Assets determined as of the date of the Incurrence of such Indebtedness after giving effect to the application of the proceeds therefrom, and (iii) the Borrowing Base at the time of incurrence;

(2) guarantees of Indebtedness Incurred in accordance with the provisions of the Indenture;provided that in the event such Indebtedness that is being guaranteed is a Subordinated Obligation or a Guarantor Subordinated Obligation, then the related guarantee shall be subordinated in right of payment to the Notes or the Subsidiary Guarantees to at least the same extent as the Indebtedness being guaranteed, as the case may be;

(3) Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any Restricted Subsidiary;provided,however, that (a)(i) if the Company is the obligor on such Indebtedness and the obligee is not a Subsidiary Guarantor, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all obligations with respect to the Notes and (ii) if a Subsidiary Guarantor is the obligor of such Indebtedness and the obligee is neither the Company nor a Subsidiary Guarantor, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all obligations of such Subsidiary Guarantor with respect to its Subsidiary Guarantee and (b)(i) any subsequent issuance or transfer of Capital Stock or any other event which results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person other than the Company or a Restricted Subsidiary of the Company shall be deemed, in each case, to constitute an Incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause;

(4) Indebtedness represented by (a) the Notes issued on the Issue Date and all Subsidiary Guarantees, (b) any Indebtedness (other than the Indebtedness described in clauses (1), (3), 4(a) and (9) of this paragraph) outstanding on the Issue Date, (c) any Exchange Notes and related Subsidiary Guarantees issued pursuant to a Registration Rights Agreement and (d) any Refinancing Indebtedness Incurred in respect of any Indebtedness described in this clause (4) or clause (5) or Incurred pursuant to the first paragraph of this covenant;

(5) Permitted Acquisition Indebtedness;

(6) Indebtedness Incurred in respect of (a) self-insurance obligations or bid, plugging and abandonment, appeal, reimbursement, performance, surety and similar bonds provided by the Company or a Restricted Subsidiary in the ordinary course of business and any guarantees or letters of credit functioning as or supporting any of such obligations or bonds and (b) obligations represented by letters of credit for the account of the Company or a Restricted Subsidiary in order to provide security for workers’ compensation claims (in the case of both clauses (a) and (b) other than for an obligation for money borrowed);

(7) Indebtedness of the Issuers or any Subsidiary Guarantor represented by Capitalized Lease Obligations (whether or not incurred pursuant to Sale/Leaseback Transactions) or other Indebtedness incurred or assumed in connection with the acquisition, construction, improvement or development of real or personal, movable or immovable, property, in each case Incurred for the purpose of financing, refinancing, renewing, defeasing or refunding all or any part of the purchase price or cost of acquisition, construction, improvement or development of property used in the business of the Company or the Subsidiary Guarantors;provided that the aggregate principal amount incurred by the Issuers or any

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Subsidiary Guarantor pursuant to this clause (7) outstanding at any time shall not exceed the greater of (x) $40.0 million and (y) 3.0% of the Company’s Adjusted Consolidated Net Tangible Assets; andprovided further that the principal amount of any Indebtedness permitted under this clause (7) did not in each case at the time of incurrence exceed the Fair Market Value, as determined in accordance with the definition of such term, of the acquired or constructed asset or improvement so financed;

(8) Indebtedness to the extent that the net proceeds thereof are promptly deposited to defease the Notes or to satisfy and discharge the Indenture;

(9) in addition to the items referred to in clauses (1) through (8) above, Indebtedness of the Company and its Restricted Subsidiaries in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (9) and then outstanding, will not exceed the greater of (a) $50.0 million, and (b) 5.0% of the Company’s Adjusted Consolidated Net Tangible Assets.

For purposes of determining compliance with, and the outstanding principal amount of any particular Indebtedness Incurred pursuant to and in compliance with, this covenant:

(1) in the event an item of that Indebtedness meets the criteria of more than one of the types of Indebtedness described in the first and second paragraphs of this covenant, the Company, in its sole discretion, will classify such item of Indebtedness on the date of Incurrence and, subject to clause (2) below may later classify, reclassify or redivide all or a portion of such item of Indebtedness,- in any manner that complies with this covenant;

(2) any Indebtedness outstanding on the date of the Indenture under the Senior Secured Credit Agreement shall be deemed Incurred on the Issue Date under clause (1) of the second paragraph of this covenant;

(3) guarantees of, or obligations in respect of letters of credit supporting, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included;

(4) the principal amount of any Disqualified Stock of the Company or a Restricted Subsidiary, or Preferred Stock of a Restricted Subsidiary, will be equal to the greater of the maximum mandatory redemption or repurchase price (including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

(5) Indebtedness permitted by this covenant need not be permitted solely by reference to one provision permitting such Indebtedness but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness; and

(6) the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP.

Accrual of interest, accrual of dividends, the amortization of debt discount or the accretion of accreted value and unrealized losses or charges in respect of Hedging Obligations (including those resulting from the application of ASC-815) will not be deemed to be an Incurrence of Indebtedness for purposes of this covenant.

The Company will not permit any of its Unrestricted Subsidiaries to Incur any Indebtedness other than Non-Recourse Debt. If at any time an Unrestricted Subsidiary becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be deemed to be Incurred by a Restricted Subsidiary as of such date (and, if such Indebtedness is not permitted to be Incurred as of such date under this “Limitation on Indebtedness and Preferred Stock” covenant, the Company shall be in Default of this covenant).

The Indenture will not treat (1) unsecured Indebtedness as subordinated or junior to secured Indebtedness merely because it is unsecured or (2) senior Indebtedness as subordinated or junior to any other senior Indebtedness merely because it has a junior priority with respect to the same collateral.

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Limitation on Restricted Payments

The Company will not, and will not permit any of its Restricted Subsidiaries, directly or indirectly, to:

(1) declare or pay any dividend or make any payment or distribution on or in respect of its Capital Stock (including any payment or distribution in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) except:

(a) dividends or distributions by the Company payable solely in Capital Stock of the Company (other than Disqualified Stock); and

(b) dividends or distributions payable to the Company or a Restricted Subsidiary and if such Restricted Subsidiary is not a Wholly Owned Subsidiary, to minority stockholders (or owners of an equivalent interest in the case of a Subsidiary that is an entity other than a corporation) so long as the Company or a Restricted Subsidiary receives at least its pro rata share of such dividend or distribution;

(2) purchase, repurchase, redeem, defease or otherwise acquire or retire for value any Capital Stock of the Company or any direct or indirect parent of the Company held by Persons other than the Company or a Wholly Owned Subsidiary;

(3) (a) purchase, repurchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Obligations or Guarantor Subordinated Obligations (other than (x) Indebtedness permitted under clause (3) of the second paragraph of the covenant described above under “— Limitation on Indebtedness and Preferred Stock” or (y) the purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations or Guarantor Subordinated Obligations purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase, redemption, defeasance or other acquisition or retirement), or (b) purchase, repurchase, redeem, defease or otherwise acquire or retire for value, or make any payment on, the Founder Notes; or

(4) make any Restricted Investment in any Person;

(any such dividend, distribution, purchase, repurchase, redemption, defeasance, other acquisition or retirement or Restricted Investment referred to in clauses (1) through (4) is referred to herein as a “Restricted Payment”), if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(a) a Default has occurred and is continuing (or would result therefrom);

(b) the Company is not able to Incur an additional $1.00 of Indebtedness pursuant to the first paragraph of the covenant described under “— Limitation on Indebtedness and Preferred Stock” after giving effect, on a pro forma basis, to such Restricted Payment; or

(c) the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made on or after October 13, 2010 (other than under clauses (1), (2), (4), (5), (6), (7), (8), (9), (10), and (11) of the next paragraph) would exceed the sum of the following:

(i) 50% of Consolidated Net Income accrued on a cumulative basis for the period (treated as one accounting period) from October 1, 2010 to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

(ii) 100% of the aggregate Net Cash Proceeds and the Fair Market Value of any Capital Stock of Persons engaged primarily in the Oil and Gas Business or assets used in the Oil and Gas Business, in each case received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or from cash capital contributions subsequent to October 13, 2010 (excluding (A) $300.0 million of such proceeds or capital contributions received by the Company in November 2016 and (B) Net Cash Proceeds received from an issuance or sale of such Capital

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Stock to (x) a Subsidiary of the Company or (y) an employee stock ownership plan, option plan or similar trust (to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination));

(iii) the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company’s balance sheet upon the conversion or exchange (other than by a Subsidiary of the Company) subsequent to October 13, 2010 of any Indebtedness of the Company or its Restricted Subsidiaries convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or the Fair Market Value of any other property (other than such Capital Stock), distributed by the Company upon such conversion or exchange), together with the net proceeds, if any, received by the Company or any of its Restricted Subsidiaries upon such conversion or exchange; and

(iv) the amount equal to the aggregate net reduction in Restricted Investments made by the Company or any of its Restricted Subsidiaries in any other Person after October 13, 2010 resulting from:

(A) repurchases, repayments or redemptions of such Restricted Investments by such Person, proceeds realized upon the sale of such Restricted Investments (other than to a Subsidiary of the Company), or repayments of loans or advances or other transfers of assets (including by way of dividend or distribution) by such Person to the Company or any Restricted Subsidiary; and

(B) the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries (valued in each case as provided in the definition of “Investment”) not to exceed, in the case of any Unrestricted Subsidiary, the amount of Investments previously made by the Company or any Restricted Subsidiary in such Unrestricted Subsidiary, which amount in each case under this clause (iv) was included in the calculation of the amount of Restricted Payments;provided,however, that no amount will be included under this clause (iv) to the extent it is already included in Consolidated Net Income.

As of September 30, 2016, after giving effect to the offering of notes, the amount available for Restricted Payments under the foregoing clause (c) would be approximately $102.0 million.

The provisions of the preceding paragraph will not prohibit:

(1) any Restricted Payment made by exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary of the Company or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination) or a substantially concurrent cash capital contribution received by the Company from the owners of its Capital Stock;provided that the Net Cash Proceeds from such sale of Capital Stock or capital contribution will be excluded from clause (c)(ii) of the preceding paragraph;

(2) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations of an Issuer or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of Refinancing Indebtedness with respect to such Subordinated Obligations or Guarantor Subordinated Obligations permitted to be Incurred pursuant to the covenant described above under “— Limitation on Indebtedness and Preferred Stock”;

(3) dividends paid or distributions made within 60 days after the date of declaration if at such date of declaration such dividend or distribution would have complied with this covenant;provided,however, that

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such dividends and distributions will be included in subsequent calculations of the amounts available for Restricted Payments pursuant to clause (4)(c) above; andprovided further, however, that for purposes of clarification, this clause (3) shall not include cash payments in lieu of the issuance of fractional shares included in clause (8) below;

(4) the repurchase or other acquisition of Capital Stock (including options, warrants, equity appreciation rights or other rights to purchase or acquire Capital Stock) of the Company held by any existing or former employees, officers or directors of the Company or the General Partner or any Restricted Subsidiary of the Company or their assigns, estates or heirs, in each case pursuant to the repurchase or other acquisition provisions under employee stock option or stock purchase plans or agreements or other agreements to compensate employees, officers or directors, in each case approved by the Company’s Board of Directors;provided that such repurchases or other acquisitions pursuant to this clause (4) will not exceed $5.0 million in the aggregate during any calendar year; and provided that the proceeds received from any such transaction will be excluded from clause (c)(ii) of the preceding paragraph;

(5) purchases, repurchases, redemptions or other acquisitions or retirements for value of Capital Stock deemed to occur upon the exercise of stock options, warrants, rights to acquire Capital Stock or other convertible securities if such Capital Stock represents a portion of the exercise or exchange price thereof, and any purchases, repurchases, redemptions or other acquisitions or retirements for value of Capital Stock made in lieu of withholding taxes in connection with any exercise or exchange of warrants, options or rights to acquire Capital Stock;

(6) the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of any Subordinated Obligation (i) at a purchase price not greater than 101% of the principal amount of such Subordinated Obligation in the event of a Change of Control in accordance with provisions similar to the covenant described under “— Change of Control” or (ii) at a purchase price not greater than 100% of the principal amount thereof in accordance with provisions similar to the covenant described under “— Limitation on Sales of Assets and Subsidiary Stock”;provided that, prior to or simultaneously with such purchase, repurchase, redemption, defeasance or other acquisition or retirement, the Company has made the Change of Control Offer or Asset Disposition Offer, as applicable, as provided in such covenant with respect to the Notes and has completed the repurchase of all Notes accepted for payment in connection with such Change of Control Offer or Asset Disposition Offer;

(7) so long as no Default has occurred and is continuing, payments or distributions to dissenting equityholders pursuant to applicable law or in connection with the settlement or other satisfaction of legal claims made pursuant to or in connection with a consolidation, merger or transfer of assets;

(8) cash payments in lieu of the issuance of fractional shares;

(9) the declaration and payment of scheduled or accrued dividends to holders of any class of or series of Disqualified Stock of the Company issued after the Issue Date in accordance with the covenant captioned “— Limitation on Indebtedness and Preferred Stock”, to the extent such dividends are included in Consolidated Interest Expense;

(10) so long as the Company is treated for U.S. federal tax purposes as a disregarded entity or partnership, Permitted Tax Distributions;

(11) dividends paid or distributions made by the Company, or purchases, repurchases, redemptions or other acquisitions or retirements for value of Capital Stock of the Company, within 60 days after October 13, 2010 from proceeds of the issuance of the Company’s 9 ⁵/₈% Senior Notes due 2018 in an aggregate amount not to exceed $50.0 million; and

(12) so long as no Default has occurred and is continuing, Restricted Payments in an amount not to exceed $25.0 million in the aggregate since the Issue Date.

The amount of all Restricted Payments (other than cash) shall be the Fair Market Value on the date of such Restricted Payment of the securities or other assets proposed to be paid, transferred or issued by the Company or

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such Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment. The Fair Market Value of any cash Restricted Payment shall be its face amount, and the Fair Market Value of any non-cash Restricted Payment shall be determined in accordance with the definition of that term. Not later than the date of making any Restricted Payment pursuant to clause (c) of the second preceding paragraph or clause (12) of the preceding paragraph, the Company shall deliver to the Trustee an Officers’ Certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by this covenant were computed and the amounts available for Restricted Payments pursuant to clause (4)(c) above after giving effect to such Restricted Payment.

In the event that a Restricted Payment meets the criteria of more than one of the exceptions described in clauses (1) through (12) above or is entitled to be made pursuant to the first paragraph above, the Company shall, in its sole discretion, classify such Restricted Payment and may later re-classify all or a portion of such Restricted Payment.

The Company will not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the last sentence of the definition of “Unrestricted Subsidiary”. For purpose of designating any Restricted Subsidiary as an Unrestricted Subsidiary, all outstanding Investments by the Company and its Restricted Subsidiaries (except to the extent repaid) in the Subsidiary so designated will be deemed to be Restricted Payments in an amount determined as set forth in the last sentence of the definition of “Investment”. Such designation will be permitted only if a Restricted Payment in such amount would be permitted at such time, whether pursuant to the first paragraph of this covenant or under clause (12) of the second paragraph of this covenant, or pursuant to the definition of “Permitted Investments”, and if such Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. Unrestricted Subsidiaries will not guarantee the Notes and will not be subject to any of the restrictive covenants set forth in the Indenture.

Limitation on Liens

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, Incur or suffer to exist any Lien (other than Permitted Liens) upon any of its property or assets (including Capital Stock of Restricted Subsidiaries), including any income or profits therefrom, whether owned on the date of the Indenture or acquired after that date, which Lien is securing any Indebtedness, unless contemporaneously with the Incurrence of such Lien effective provision is made to secure the Indebtedness due under the Notes (in the case of the Company) or any Subsidiary Guarantee of such other Restricted Subsidiary, equally and ratably with (or senior in priority to in the case of Liens with respect to Subordinated Obligations or Guarantor Subordinated Obligations, as the case may be) the Indebtedness secured by such Lien for so long as such Indebtedness is so secured.

Limitation on Restrictions on Distributions from Restricted Subsidiaries

The Company will not, and will not permit any Restricted Subsidiary (other than the Co-Issuer) to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any such Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock or pay any Indebtedness or other obligations owed to the Company or any other Restricted Subsidiary (it being understood that the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on Common Stock shall not be deemed a restriction on the ability to make distributions on Capital Stock);

(2) make any loans or advances to the Company or any other Restricted Subsidiary (it being understood that the subordination of loans or advances made to the Company or any Restricted Subsidiary to other Indebtedness Incurred by the Company or any Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances); or

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(3) sell, lease or transfer any of its property or assets to the Company or any other Restricted Subsidiary.

The preceding provisions will not prohibit:

(i) any encumbrance or restriction pursuant to or by reason of an agreement in effect at or entered into on the Issue Date, including the Indenture and the Senior Secured Credit Agreement, each as in effect on such date;

(ii) any encumbrance or restriction with respect to a Person pursuant to or by reason of an agreement relating to any Capital Stock or Indebtedness Incurred by a Person on or before the date on which such Person was acquired by the Company or another Restricted Subsidiary (other than Capital Stock or Indebtedness Incurred as consideration in, or to provide all or any portion of the funds utilized to consummate, the transaction or series of related transactions pursuant to which such Person was acquired by the Company or a Restricted Subsidiary or in contemplation of the transaction) and outstanding on such date;provided that any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

(iii) any encumbrance or restriction contained in contracts entered into in the ordinary course of business, not relating to any Indebtedness, and that do not, individually or in the aggregate, detract from the value of, or from the ability of the Company and the Restricted Subsidiaries to realize the value of, property or assets of the Company or any Restricted Subsidiary in any manner material to the Company or any Restricted Subsidiary;

(iv) any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refunding, replacement or refinancing of Indebtedness Incurred pursuant to an agreement referred to in clauses (i) and (ii) or clause (ix) of this paragraph or this clause (iv) or contained in any amendment, restatement, modification, renewal, supplemental, refunding, replacement or refinancing of an agreement referred to in clauses (i) and (ii) or clause (ix) of this paragraph or this clause (iv);provided that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement taken as a whole are no less favorable in any material respect to the holders of the Notes than the encumbrances and restrictions contained in the agreements governing the Indebtedness being refunded, replaced or refinanced;

(v) in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(a) that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in Oil and Gas Properties), license or similar contract, or the assignment or transfer of any such lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in Oil and Gas Properties), license (including licenses of intellectual property) or other contract;

(b) contained in mortgages, pledges or other security agreements permitted under the Indenture securing Indebtedness of the Company or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements;

(c) contained in any agreement creating Hedging Obligations permitted from time to time under the Indenture;

(d) pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Company or any Restricted Subsidiary;

(e) on cash or other deposits imposed by customers under contracts entered into in the ordinary course of business; or

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(f) with respect to the disposition or distribution of assets or property in operating agreements, joint venture agreements, development agreements, area of mutual interest agreements and other agreements that are customary in the Oil and Gas Business and entered into in the ordinary course of business;

(vi) any encumbrance or restriction contained in (a) purchase money obligations for property acquired in the ordinary course of business and (b) Capitalized Lease Obligations, in each case that are permitted under the Indenture and that impose encumbrances or restrictions of the nature described in clause (3) of the first paragraph of this covenant on the property or assets so acquired, and any proceeds thereof;

(vii) any encumbrance or restriction with respect to a Restricted Subsidiary (or any of its property or assets) imposed pursuant to an agreement entered into for the direct or indirect sale or other disposition of all or a portion of the Capital Stock or property or assets of such Restricted Subsidiary pending the closing of such sale or other disposition;

(viii) any encumbrance or restriction arising or existing by reason of applicable law or any applicable rule, regulation or order;

(ix) any encumbrance or restriction contained in agreements governing Indebtedness of the Company or any of its Restricted Subsidiaries permitted to be Incurred pursuant to an agreement entered into subsequent to the Issue Date in accordance with the covenant described above under the caption “— Limitation on Indebtedness and Preferred Stock”;provided that the provisions relating to such encumbrance or restriction contained in such Indebtedness, taken as a whole, are not materially less favorable to the Company taken as a whole, as determined by the Board of Directors of the Company in good faith, than the provisions contained in the Senior Secured Credit Agreement and in the Indenture as in effect on the Issue Date; and

(x) any encumbrance or restriction on cash or other deposits or net worth imposed by customers under contracts or required by insurance, surety or bonding companies, in each case entered into or incurred in the ordinary course of business.

Limitation on Sales of Assets and Subsidiary Stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any Asset Disposition unless:

(1) the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Disposition at least equal to the Fair Market Value (such Fair Market Value to be determined on the date of contractually agreeing to such Asset Disposition) of the Capital Stock or other assets subject to such Asset Disposition;

(2) at least 75% of the consideration received by the Company or such Restricted Subsidiary, as the case may be, is in the form of cash or Cash Equivalents; and

(3) except as provided in the next paragraph, an amount equal to 100% of the Net Available Cash from such Asset Disposition is applied, within 360 days from the later of the date of such Asset Disposition or the receipt of such Net Available Cash, by the Company or such Restricted Subsidiary, as the case may be:

(a) to prepay, repay, redeem or purchase Indebtedness (other than intercompany Indebtedness, Subordinated Obligations, Capital Stock or Indebtedness owed to an Affiliate of the Company);provided,however, that, in connection with any prepayment, repayment, redemption or purchase of Indebtedness pursuant to this clause (a), the Company or such Restricted Subsidiary will cause the related commitment to be permanently reduced in an amount equal to the principal amount so prepaid, repaid, redeemed or purchased; or

(b) to invest in Additional Assets or to make capital expenditures in the Oil and Gas Business;

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provided that pending the final application of any such Net Available Cash in accordance with clause (a) or clause (b) above, the Company and its Restricted Subsidiaries may temporarily reduce revolving credit Indebtedness or otherwise invest such Net Available Cash in any manner not prohibited by the Indenture.

The requirement of clause 3(b) hereof shall be deemed to be satisfied if a bona fide binding contract committing to make the acquisition referred to therein is entered into by the Company or any of its Restricted Subsidiaries with a Person other than an Affiliate of the Company within the time period specified in the preceding paragraph 3 and such Net Available Cash is subsequently applied in accordance with such contract within 180 days following the date such agreement is entered into.

Any Net Available Cash from Asset Dispositions that is not applied or invested as provided in the preceding paragraph will be deemed to constitute “Excess Proceeds”. When the aggregate amount of Excess Proceeds exceeds $20.0 million, within 10 Business Days thereof, the Company will be required to make an offer (“Asset Disposition Offer”) to all holders of Notes and, to the extent required by the terms of other Pari Passu Indebtedness, to all holders of other Pari Passu Indebtedness outstanding with similar provisions requiring the Company to make an offer to purchase such Pari Passu Indebtedness with the proceeds from any Asset Disposition (“Pari Passu Notes”), to purchase the maximum principal amount of Notes and any such Pari Passu Notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount (or, in the event such Pari Passu Indebtedness was issued with original issue discount, 100% of the accreted value thereof) of the Notes and Pari Passu Notes plus accrued and unpaid interest, if any (or in respect of such Pari Passu Notes, such lesser price, if any, as may be provided for by its terms), to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Notes, as applicable, in each case in a minimum principal amount of $2,000 and integral multiples of $1,000 in excess thereof. If the aggregate principal amount of Notes surrendered by holders thereof and other Pari Passu Notes surrendered by holders or lenders, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes to be purchased on a pro rata basis (or, in the case of Notes issued in global form as discussed under the caption “Book-Entry; Delivery and Form”, the Trustee will select the Notes for purchase based on DTC’s method that most nearly approximates a pro rata selection) on the basis of the aggregate principal amount of tendered Notes and Pari Passu Notes. To the extent that the aggregate amount of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Company and its Restricted Subsidiaries may use any remaining Excess Proceeds for general corporate purposes, subject to the other covenants contained in the Indenture. Upon completion of such Asset Disposition Offer, the amount of Excess Proceeds shall be reset at zero.

The Asset Disposition Offer will remain open for a period of 20 Business Days following its commencement, except to the extent that a longer period is required by applicable law (the “Asset Disposition Offer Period”). No later than two Business Days after the termination of the Asset Disposition Offer Period (the “Asset Disposition Purchase Date”), the Company will purchase the principal amount of Notes and Pari Passu Notes required to be purchased pursuant to this covenant (the “Asset Disposition Offer Amount”) or, if less than the Asset Disposition Offer Amount has been so validly tendered and not properly withdrawn, all Notes and Pari Passu Notes validly tendered and not properly withdrawn in response to the Asset Disposition Offer.

If the Asset Disposition Purchase Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to each Person in whose name a Note is registered at the close of business on such record date, and no further interest will be payable to holders who tender Notes pursuant to the Asset Disposition Offer.

On or before the Asset Disposition Purchase Date, the Company will, to the extent lawful, accept for payment, on a pro rata basis to the extent necessary, the Asset Disposition Offer Amount of Notes and Pari Passu Notes or portions of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to the

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Asset Disposition Offer, or if less than the Asset Disposition Offer Amount has been validly tendered and not properly withdrawn, all Notes and Pari Passu Notes so validly tendered and not properly withdrawn, in each case in a minimum principal amount of $2,000 and integral multiples of $1,000 in excess thereof. The Company will deliver to the Trustee an Officers’ Certificate stating that such Notes or portions thereof were accepted for payment by the Company in accordance with the terms of this covenant and, in addition, the Company will deliver all certificates required, if any, by the agreements governing the Pari Passu Notes. On the Asset Disposition Purchase Date, the Company or the paying agent, as the case may be, will mail or deliver to each tendering holder of Notes or holder or lender of Pari Passu Notes, as the case may be, an amount equal to the purchase price of the Notes or Pari Passu Notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Company for purchase, and the Company will promptly issue a new Note, and the Trustee, upon delivery of a written request from the Company, will authenticate and mail or deliver such new Note to such holder, in a principal amount equal to any unpurchased portion of the Note surrendered;provided that each such new Note will be in a minimum principal amount of $2,000 or an integral multiple of $1,000 in excess thereof. In addition, the Company will take any and all other actions required by the agreements governing the Pari Passu Notes. Any Note not so accepted will be promptly mailed or delivered by the Issuer to the holder thereof. The Company will publicly announce the results of the Asset Disposition Offer on the Asset Disposition Purchase Date.

The Company will comply, to the extent applicable, with the requirements of Rule 14e-1 of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to an Asset Disposition Offer. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Indenture by virtue of its compliance with such securities laws or regulations.

For the purposes of clause (2) of the first paragraph of this covenant, the following will be deemed to be cash:

(1) the assumption by the transferee of Indebtedness of the Company or Indebtedness of a Restricted Subsidiary (other than intercompany Indebtedness, Subordinated Obligations, Capital Stock or Indebtedness owed to an Affiliate of the Company) and the release of such Issuer or Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition;

(2) with respect to any Asset Disposition of oil and natural gas properties by the Company or any of its Restricted Subsidiaries where the Company or such Restricted Subsidiary retains an interest in such property, any agreement by the transferee (or an Affiliate thereof) to pay all or a portion of the costs and expenses of the Company or such Restricted Subsidiary related to the exploration, development, completion or production of such properties and activities related thereto;

(3) any Additional Assets;

(4) any Designated Non-cash Consideration received by the Company or such Restricted Subsidiary in such Asset Disposition having an aggregate Fair Market Value, taken together with all other Designated Non-cash Consideration received pursuant to this clause (4), not to exceed an amount equal to 5.0% of the Company’s Adjusted Consolidated Net Tangible Assets (determined at the time of receipt of such Designated Non-cash Consideration), with the Fair Market Value of each item of Designated Non-cash Consideration being measured at the time received and without giving effect to subsequent changes in value; and

(5) securities, notes or other obligations received by the Company or any Restricted Subsidiary from the transferee that are converted by the Company or such Restricted Subsidiary into cash within 30 days after receipt thereof.

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Limitation on Affiliate Transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, enter into, make, amend or conduct any transaction (including making a payment to, the purchase, sale, lease or exchange of any property or the rendering of any service), contract, agreement or understanding with or for the benefit of any Affiliate of the Company (an “Affiliate Transaction”) unless:

(1) the terms of such Affiliate Transaction are no less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that could reasonably be expected to be obtained in a comparable transaction at the time of such transaction in arm’s-length dealings with a Person who is not such an Affiliate, or, if in the good faith judgment of the Board of Directors of the Company, no comparable transaction is available with which to compare such Affiliate Transaction, such Affiliate Transaction is otherwise fair to the Company or the relevant Restricted Subsidiary from a financial point of view;

(2) if such Affiliate Transaction involves an aggregate consideration in excess of $20.0 million, the terms of such transaction have been approved by a majority of the members of the Board of Directors of the Company having no personal stake in such transaction, if any (and such majority determines that such Affiliate Transaction satisfies the criteria in clause (1) above); and

(3) if such Affiliate Transaction involves an aggregate consideration in excess of $50.0 million, the Board of Directors of the Company has received a written opinion from an independent investment banking, accounting, engineering or appraisal firm of nationally recognized standing that such Affiliate Transaction is fair, from a financial standpoint, to the Company or such Restricted Subsidiary or, in the case of non-financial transactions, is not less favorable to the Company or such Restricted Subsidiary than those that could reasonably be expected to be obtained in a comparable transaction at such time on an arm’s-length basis from a Person that is not an Affiliate.

The preceding paragraph will not apply to:

(1) any Restricted Payment permitted to be made pursuant to the covenant described above under “— Limitation on Restricted Payments”;

(2) any issuance of Capital Stock (other than Disqualified Stock), or other payments, awards or grants in cash, Capital Stock (other than Disqualified Stock) or otherwise pursuant to, or the funding of, any employment, consulting, service or severance agreements or other compensation arrangements, options to purchase Capital Stock (other than Disqualified Stock) of the Company, restricted stock plans, long-term incentive plans, stock appreciation rights plans, participation plans or similar employee benefits plans or insurance and indemnification arrangements provided to or for the benefit of directors, officers and employees, in each case in the ordinary course of business and approved by the Board of Directors of the Company;

(3) any merger or other transaction with an Affiliate solely for the purpose of reincorporating or reorganizing the Company or any of its Restricted Subsidiaries in another jurisdiction or creating a holding company for the Company;

(4) advances to or reimbursements of employees for moving, entertainment and travel expenses, drawing accounts and similar expenditures in the ordinary course of business of the Company or any of its Restricted Subsidiaries;

(5) any transaction between the Company and a Restricted Subsidiary or between Restricted Subsidiaries, and guarantees issued by the Company or a Restricted Subsidiary for the benefit of the Company or a Restricted Subsidiary, as the case may be, in accordance with “— Limitation on Indebtedness and Preferred Stock”;

(6) the issuance or sale of any Capital Stock (other than Disqualified Stock) of the Company to, or the receipt by the Company of any capital contribution from, the holders of its Capital Stock;

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(7) indemnities of officers, directors and employees of the Company or any of its Restricted Subsidiaries permitted by charter, bylaw or statutory provisions;

(8) the payment of reasonable compensation and fees to officers or directors of the Company or any Restricted Subsidiary;

(9) any transaction with a joint venture or similar entity (other than an Unrestricted Subsidiary) which would constitute an Affiliate Transaction solely because the Company or a Restricted Subsidiary owns, directly or indirectly, an equity interest in or otherwise controls such joint venture or similar entity;

(10) transactions between the Company or any of its Restricted Subsidiaries and any other Person, a director of which is also on the Board of Directors of the Company or any direct or indirect parent company of the Company, and such common director is the sole cause for such other Person to be deemed an Affiliate of the Company or any of its Restricted Subsidiaries; provided, however, that such director abstains from voting as a member of the Board of Directors of the Company or any direct or indirect parent company of the Company, as the case may be, on any transaction with such other Person;

(11) in the case of contracts for exploring for, producing, marketing, storing or otherwise handling Hydrocarbons, or activities or services reasonably related or ancillary thereto, or other operational contracts, any such contracts entered into in the ordinary course of business and otherwise in compliance with the terms of the Indenture (a) which are fair to the Company and its Restricted Subsidiaries, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party, in either case in the reasonable determination of the Board of Directors of the Company or the senior management thereof, and (b) with respect to which the Company has complied with clauses (2) and (3) of the preceding paragraph to the extent applicable; and

(12) the performance of obligations of the Company or any of its Restricted Subsidiaries under the terms of any agreement to which the Company or any of its Restricted Subsidiaries is a party as of or on the Issue Date that is disclosed in this prospectus under “Certain Relationships and Related Party Transactions,” as these agreements may be amended, modified, supplemented, extended or renewed from time to time;provided,however, that any future amendment, modification, supplement, extension or renewal entered into after the Issue Date will be permitted only to the extent that its terms are not materially more disadvantageous, taken as a whole, to the holders of the Notes than the terms of the agreements in effect on the Issue Date.

Provision of Financial Information

The Indenture provides that, whether or not the Company is subject to the reporting requirements of Section 13 or Section 15(d) of the Exchange Act, the Company will make available to the Trustee and the holders of the Notes without cost, by posting the same on the Company’s website or on the SEC’s EDGAR filing system as further provided below for public availability, the annual reports and the information, documents and other reports that are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a U.S. corporation that would be due after the Issue Date, within the time periods specified therein with respect to a non-accelerated filer. The Company will file a copy of each of the reports referred to in the preceding sentence with the SEC for public availability within the time periods specified in the rules and regulations applicable to such reports (unless the SEC will not accept such a filing).

This covenant will not impose any duty on the Company under the Sarbanes-Oxley Act of 2002 and the related SEC rules that would not otherwise be applicable.

For the avoidance of doubt, (a) any such reports or other information delivered pursuant to the foregoing will not be required to contain the separate financial information for Subsidiary Guarantors as contemplated by Rule 3-10 of Regulation S-X or any financial statements of unconsolidated subsidiaries or 50% or less owned persons as contemplated by Rule 3-09 of Regulation S-X or any schedules required by Regulation S-X, or in each

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case any successor provisions and (b) such information shall not be required to comply with Regulation G under the Exchange Act or Item 10(e) of Regulation S-K with respect to any non-GAAP financial measures contained therein.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the financial information required will include, to the extent material, a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in any accompanying Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

For so long as any Notes remain outstanding and constitute “restricted securities” under Rule 144, the Company will furnish to the holders of the Notes, and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Merger and Consolidation

Neither the Company nor the Co-Issuer will consolidate with or merge with or into or wind up into (whether or not it is the surviving Person), or sell, convey, transfer, lease or otherwise dispose of all or substantially all its assets in one or more related transactions to, any Person, unless:

(1) the resulting, surviving or transferee Person (the “Successor Company”) will be a corporation (in the case of either the Company or the Co-Issuer), or a partnership, trust or limited liability company (but only in the case of the Company), organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and the Successor Company (if not the Company or the Co-Issuer, as the case may be) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, in form reasonably satisfactory to the Trustee, all the obligations of the Company or the Co-Issuer, as the case may be, under the Indenture, the Notes and the applicable Registration Rights Agreement;

(2) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the Successor Company or any Subsidiary of the Successor Company as a result of such transaction as having been Incurred by the Successor Company or such Subsidiary at the time of such transaction), no Default or Event of Default shall have occurred and be continuing;

(3) the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, conveyance, lease or other disposition has been made, would, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period (a) be permitted to incur at least $1.00 of additional Indebtedness pursuant to the first paragraph of the covenant described under “— Limitation on Indebtedness and Preferred Stock”, or (b) have had a Consolidated Coverage Ratio equal to or greater than the actual Consolidated Coverage Ratio for the Company for such four-quarter period;

(4) if an Issuer is not the Successor Company in any of the transactions referred to above that involve such Issuer, each Subsidiary Guarantor (unless it is the other party to the transactions, in which case clause (1) shall apply) shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to the Successor Company’s obligations in respect of the Indenture and the Notes and that its Subsidiary Guarantee shall continue to be in effect; and

(5) the Company or the Co-Issuer, as the case may be, shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such transaction and such supplemental indenture (if any) comply with the Indenture.

For purposes of this covenant, the sale, conveyance, transfer, lease or other disposition of all or substantially all of the assets of one or more Subsidiaries of the Company, which assets, if held by the Company instead of

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such Subsidiaries, would constitute all or substantially all of the assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the assets of the Company.

The Successor Company will succeed to, and be substituted for, and may exercise every right and power of, the Company or the Co-Issuer, as the case may be, under the Indenture; and its predecessor, except in the case of a lease of all or substantially all its assets, will be released from all obligations under the Indenture Documents.

Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the assets of a Person.

Notwithstanding the preceding clause (3), (x) any Restricted Subsidiary (other than the Co-Issuer) may consolidate with, merge into or transfer all or part of its assets to the Company, and the Company may consolidate with, merge into or transfer all or part of its assets to a Subsidiary Guarantor and (y) the Company may merge with an Affiliate formed solely for the purpose of reorganizing the Company in another jurisdiction.

In addition, the Company will not permit any Subsidiary Guarantor to consolidate with or merge with or into, and will not permit the sale, conveyance, transfer, lease or other disposition of all or substantially all of the assets of any Subsidiary Guarantor to, any Person (other than the Company or another Subsidiary Guarantor) unless:

(1) either (a)

(i) the resulting, surviving or transferee Person will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and such Person (if not such Subsidiary Guarantor) will expressly assume by supplemental indenture, executed and delivered to the Trustee, in form reasonably satisfactory to the Trustee, all the obligations of the Subsidiary Guarantor under the Indenture, the Subsidiary Guarantee and the applicable Registration Rights Agreement and

(ii) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the resulting, surviving or transferee Person or any Restricted Subsidiary as a result of such transaction as having been Incurred by such Person or such Restricted Subsidiary at the time of such transaction), no Default shall have occurred and be continuing; or

(b) the transaction results in the release of the Subsidiary Guarantor from its obligations under its Subsidiary Guarantee in compliance with the conditions described in the penultimate paragraph of “— Subsidiary Guarantees”; and

(2) the Company shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such transaction and such supplemental indenture (if any) comply with the Indenture.

Future Subsidiary Guarantors

The Company will cause (a) each Domestic Subsidiary of the Company formed or acquired after the Issue Date and (b) any other Restricted Subsidiary (except the Co-Issuer) that is not already a Subsidiary Guarantor that guarantees any Indebtedness of the Company or a Subsidiary Guarantor, in each case to execute and deliver to the Trustee within 30 days a supplemental indenture (in the form specified in the Indenture) pursuant to which such Subsidiary will unconditionally guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any, and interest on the Notes on a senior basis; provided that any Restricted Subsidiary that constitutes an Immaterial Subsidiary need not become a Subsidiary Guarantor until such time as it ceases to be an Immaterial Subsidiary.

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Payments for Consent

Neither the Company nor any of its Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fees or otherwise, to any holder of any Notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the Notes unless such consideration is offered to be paid or is paid to all holders of the Notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or amendment.

Notwithstanding the foregoing, with respect to any payment of consideration for, or as an inducement to, any consent, waiver or amendment of any of the terms or provisions of the Indenture, the Notes or the Subsidiary Guarantees in connection with a tender offer or exchange offer for the Notes, the Company and any of its Restricted Subsidiaries may exclude (i) holders or Beneficial Owners of the Notes that are not “qualified institutional buyers” as defined in Rule 144A under the Securities Act, or “non-U.S. Persons” as defined in Regulation S under the Securities Act, and (ii) holders or Beneficial Owners of the Notes in any jurisdiction (other than the United States) where the inclusion of such holders or Beneficial Owners would require the Company or any such Restricted Subsidiary to comply with the registration requirements or other similar requirements under any securities laws of such jurisdiction, or the solicitation of such consent, waiver or amendment from, or the granting of such consent or waiver, or the approval of such amendment by, holders or Beneficial Owners in such jurisdiction would be unlawful, in each case as determined by the Company in its sole discretion.

Business Activities

The Company will not, and will not permit any of its Restricted Subsidiaries to, engage in any business other than the Oil and Gas Business, except to such extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

The Co-Issuer may not engage in any business not related directly or indirectly to obtaining money or arranging financing for the Company or its Restricted Subsidiaries. The Co-Issuer may not have any Subsidiary, and no Person other than the Company or any of its other Restricted Subsidiaries may own any Capital Stock of the Co-Issuer.

Events of Default

Each of the following is an Event of Default with respect to the Notes:

(1) default in any payment of interest on any Note when due, continued for 30 days;

(2) default in the payment of principal of or premium, if any, on any Note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration of acceleration or otherwise;

(3) failure by either Issuer or any Subsidiary Guarantor to comply with its obligations under “— Certain Covenants — Merger and Consolidation”;

(4) failure by either Issuer or any Subsidiary Guarantor to comply for 30 days after notice as provided below with any of its obligations under the covenant described under “— Change of Control” above or under the covenants described under “— Certain Covenants” above (in each case, other than a failure to purchase Notes which will constitute an Event of Default under clause (2) above and other than a failure to comply with “— Certain Covenants — Merger and Consolidation” which is covered by clause (3));

(5) failure by either Issuer or any Subsidiary Guarantor to comply for 60 days after notice as provided below with its other agreements contained in the Indenture;

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(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), other than Indebtedness owed to the Company or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists, or is created after the date of the Indenture, which default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (and any extensions of any grace period) (“payment default”); or

(b) results in the acceleration of such Indebtedness prior to its Stated Maturity (the “cross acceleration provision”);

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a payment default or the maturity of which has been so accelerated, aggregates $20.0 million or more;

(7) certain events of bankruptcy, insolvency or reorganization of the Company, the Co-Issuer or a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary (the “bankruptcy provisions”);

(8) failure by the Company, the Co-Issuer or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $20.0 million (to the extent not covered by insurance by a reputable and creditworthy insurer as to which the insurer has not disclaimed coverage), which judgments are not paid or discharged, and there shall be any period of 60 consecutive days following entry of such final judgment or decree during which a stay of enforcement of such final judgment or decree, by reason of pending appeal or otherwise, shall not be in effect (the “judgment default provision”); or

(9) any Subsidiary Guarantee of a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary, ceases to be in full force and effect (except as contemplated by the terms of the Indenture) or is declared null and void in a judicial proceeding or the Company or any Subsidiary Guarantor that is a Significant Subsidiary or group of Subsidiary Guarantors that, taken together (as of the latest audited consolidated financial statements of the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary, denies or disaffirms its obligations under the Indenture or its Subsidiary Guarantee.

However, a default under clauses (4) and (5) of this paragraph will not constitute an Event of Default until the Trustee or the holders of at least 25% in principal amount of the outstanding Notes notify the Issuers in writing and, in the case of a notice given by the holders, the Trustee of the default and the Issuers do not cure such default within the time specified in clauses (4) and (5) of this paragraph after receipt of such notice.

If an Event of Default (other than an Event of Default described in clause (7) above) occurs and is continuing, the Trustee by notice to Issuers, or the holders of at least 25% in principal amount of the outstanding Notes by notice to the Issuers and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, accrued and unpaid interest, if any, on all the Notes to be due and payable. If an Event of Default described in clause (7) above occurs and is continuing, the principal of, and premium, if any, and accrued and unpaid interest, if any, on all the Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding Notes may waive all past defaults (except with respect to nonpayment of principal, premium or interest) and rescind any such acceleration with respect to the Notes and its consequences

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if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the Notes that have become due solely by such declaration of acceleration, have been cured or waived.

Notwithstanding the foregoing, if an Event of Default specified in clause (6) above shall have occurred and be continuing, such Event of Default and any consequential acceleration (to the extent not in violation of any applicable law or in conflict with any judgment or decree of a court of competent jurisdiction) shall be automatically rescinded if (i) the Indebtedness that is the subject of such Event of Default has been repaid or (ii) if the default relating to such Indebtedness is waived by the holders of such Indebtedness or cured and if such Indebtedness has been accelerated, then the holders thereof have rescinded their declaration of acceleration in respect of such Indebtedness, in each case within 20 days after the declaration of acceleration with respect thereto, and (iii) any other existing Events of Default, except nonpayment of principal, premium or interest on the Notes that became due solely because of the acceleration of the Notes, have been cured or waived.

Subject to the provisions of the Indenture relating to the duties of the Trustee if an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee indemnity or security satisfactory to the Trustee against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder may pursue any remedy with respect to the Indenture or the Notes unless:

(1) such holder has previously given the Trustee notice that an Event of Default is continuing;

(2) holders of at least 25% in principal amount of the outstanding Notes have requested the Trustee to pursue the remedy;

(3) such holders have offered the Trustee security or indemnity satisfactory to the Trustee against any loss, liability or expense;

(4) the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) the holders of a majority in principal amount of the outstanding Notes have not waived such Event of Default or otherwise given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

Subject to the provisions of the Indenture, the holders of a majority in principal amount of the outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. If an Event of Default has occurred and is continuing, the Trustee will be required in the exercise of its powers to use the degree of care that a prudent person would use under the circumstances in the conduct of his own affairs. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

If a Default occurs and is continuing and is known to the Trustee, the Trustee must provide to each holder notice of the Default within 90 days after it occurs. Except in the case of a Default in the payment of principal of, premium, if any, or interest on any Note, the Trustee may withhold such notice if and so long as a committee of trust officers of the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Issuers are required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Issuers also are required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any Defaults, their status and what action the Issuers are taking or proposing to take in respect thereof.

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Amendments and Waivers

The Indenture and the Notes may be amended with the consent of the holders of a majority in principal amount of the Notes then outstanding (including consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes) and, subject to certain exceptions, any past default or compliance with any provisions of any Indenture Document may be waived with the consent of the holders of a majority in principal amount of the Notes then outstanding (including consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes). However, without the consent of each holder of an outstanding Note affected thereby, no amendment or waiver may:

(1) reduce the principal amount of Notes whose holders must consent to an amendment or waiver;

(2) reduce the stated rate of or extend the stated time for payment of interest on any Note;

(3) reduce the principal of or extend the Stated Maturity of any Note;

(4) reduce the premium payable upon the redemption of any Note as described above under “— Optional Redemption”, change the time at which any Note may be redeemed as described above under “— Optional Redemption” or make any change relative to our obligation to make an offer to repurchase the Notes as a result of a Change of Control as described above under “— Change of Control” after (but not before) the occurrence of such Change of Control;

(5) make any Note payable in money other than U.S. dollars;

(6) impair the right of any holder to receive payment of the principal of, premium, if any, and interest on such holder’s Notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder’s Notes;

(7) make any change in the amendment provisions which require each holder’s consent or in the waiver provisions;

(8) release any Subsidiary Guarantor from any of its obligations under its Subsidiary Guarantee otherwise than in accordance with the applicable provisions of the Indenture; or

(9) subordinate the Notes or any Subsidiary Guarantee in right of payment to any other Indebtedness of either Issuer or any Subsidiary Guarantor.

Notwithstanding the preceding, without the consent of any holder, the Issuers, the Subsidiary Guarantors and the Trustee may amend the Indenture and the Notes to:

(1) cure any ambiguity, omission, defect, mistake or inconsistency;

(2) provide for the assumption by a successor of the obligations of the Company, the Co-Issuer or any Subsidiary Guarantor under the Indenture;

(3) provide for uncertificated Notes in addition to or in place of certificated Notes (provided that the uncertificated Notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated Notes are described in Section 163(f)(2)(B) of the Code);

(4) add Subsidiary Guarantors (or any other guarantors) with respect to the Notes or release a Subsidiary Guarantor from its Subsidiary Guarantee and terminate such Subsidiary Guarantee;provided that the release and termination is in accordance with the applicable provisions of the Indenture;

(5) secure the Notes or Guarantees;

(6) add to the covenants of the Company, the Co-Issuer or a Subsidiary Guarantor for the benefit of the holders or surrender any right or power conferred upon the Company, the Co-Issuer or a Subsidiary Guarantor;

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(7) make any change that does not adversely affect the legal rights of any holder;provided,however, that any change to conform the Indenture to this “Description of New Notes” will not be deemed to adversely affect such legal rights;

(8) comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act; or

(9) provide for the succession of a successor Trustee,provided that the successor Trustee is otherwise qualified and eligible to act as such under the Indenture.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment under the Indenture requiring the consent of the holders becomes effective, the Company will provide to the holders a notice briefly describing such amendment. However, the failure to give such notice to all the holders, or any defect in the notice will not impair or affect the validity of the amendment.

Defeasance

The Issuers at any time may terminate all their obligations under the Notes and the Indenture (“legal defeasance”), except for certain obligations specified in the Indenture, including those respecting the defeasance trust and obligations to register the transfer or exchange of the Notes, to replace mutilated, destroyed, lost or stolen Notes and to maintain a registrar and paying agent in respect of the Notes.

The Issuers at any time may terminate their obligations described under “— Change of Control” and under the covenants described under “— Certain Covenants” (other than clauses (1), (2), (4) and (5) of “— Merger and Consolidation”), the operation of the cross default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision, the Subsidiary Guarantee provision described under “— Events of Default” above and the limitations contained in clause (3) under “— Merger and Consolidation” above (“covenant defeasance”).

If the Issuers exercise their legal defeasance or covenant defeasance option, the Subsidiary Guarantees in effect at such time will terminate.

The Issuers may exercise their legal defeasance option notwithstanding their prior exercise of their covenant defeasance option. If the Issuers exercise their legal defeasance option, payment of the Notes may not be accelerated because of an Event of Default with respect to the Notes. If the Issuers exercise their covenant defeasance option, payment of the Notes may not be accelerated because of an Event of Default specified in clause (4), (5), (6), (7) (with respect only to Significant Subsidiaries), (8) or (9) under “— Events of Default” above or because of the failure of the Company or the Co-Issuer to comply with clause (3) under “— Merger and Consolidation” above.

In order to exercise either defeasance option, an Issuer or a Subsidiary Guarantor must, among other things, irrevocably deposit in trust (the “defeasance trust”) with the Trustee money or U.S. Government Obligations for the payment of principal, premium, if any, and interest on the Notes to redemption or Stated Maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel (subject to customary exceptions and exclusions) to the effect that holders of the Notes will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable federal income tax law.

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Satisfaction and Discharge

The Indenture will be discharged and will cease to be of further effect as to all Notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the Notes and as otherwise expressly provided for in the Indenture), and all Subsidiary Guarantees will be released, when either:

(1) all Notes that have been authenticated (except lost, stolen or destroyed Notes that have been replaced or paid and Notes for whose payment money has theretofore been deposited in trust or segregated and held in trust by an Issuer and thereafter repaid to such Issuer or discharged from such trust) have been delivered to the Trustee for cancellation, or

(2) all Notes that have not been delivered to the Trustee for cancellation have become due and payable or will become due and payable within one year by reason of the giving of a notice of redemption or otherwise and an Issuer or any Subsidiary Guarantor has irrevocably deposited or caused to be irrevocably deposited with the Trustee as trust funds in trust solely for such purpose, cash in U.S. dollars in such amount as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the Notes not delivered to the Trustee for cancellation for principal and accrued interest to the date of Stated Maturity or redemption, and in each case certain other procedural requirements set forth in the Indenture are satisfied.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator, stockholder, member, partner or trustee of the Company, the Co-Issuer or any Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company, the Co-Issuer or any Subsidiary Guarantor under the Notes, the Indenture or the Subsidiary Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

The Trustee

U.S. Bank National Association will be the Trustee under the Indenture and has been appointed by the Issuers as registrar and paying agent with regard to the Notes.

The Indenture will contain certain limitations on the rights of the Trustee, should it become a creditor of an Issuer or any Subsidiary Guarantor, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions;provided,however, that if it acquires any conflicting interest (as defined in the Trust Indenture Act) while any Default exists it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as Trustee with such conflict or resign as Trustee.

Governing Law

The Indenture provides that it and the Notes will be governed by, and construed in accordance with, the laws of the State of New York.

Book-Entry, Delivery and Form

We will issue the new notes in the form of one or more global note. Global notes will be deposited with, or on behalf of, The Depository Trust Company, or DTC, and registered in the name of the DTC or its nominee.

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Beneficial interests in global notes may be held through the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”) (as indirect participants in DTC). Except as set forth below, global notes may be transferred, in whole and not in part, and only to DTC or another nominee of DTC. You may hold your beneficial interests in global notes directly through DTC if you have an account with DTC or indirectly through organizations that have accounts with DTC.

Certificated Securities

Notes in certificated registered form shall be issued to all beneficial owners in exchange for their beneficial interests in the global notes if (a) DTC notifies us that it is unwilling or unable to continue as depository for the global notes and a successor depository is not appointed by us within 90 days of such notice or (b) an event of default has occurred under the indenture and is continuing and the registrar has received a request from the depository to issue notes in certificated registered form.

Certain Definitions

Set forth below are certain defined terms used in the Indenture.

“Acquired Indebtedness” means Indebtedness (i) of a Person or any of its Subsidiaries existing at the time such Person becomes or is merged with and into a Restricted Subsidiary or (ii) assumed in connection with the acquisition of assets from such Person, in each case whether or not Incurred by such Person in connection with, or in anticipation or contemplation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to have been Incurred, with respect to clause (i) of the preceding sentence, on the date such Person becomes or is merged with and into a Restricted Subsidiary and, with respect to clause (ii) of the preceding sentence, on the date of consummation of such acquisition of assets.

“Additional Assets” means:

(1) any properties or assets (other than current assets) to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business; or

(2) the Capital Stock of a Person that is or becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary;provided,however, that such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

“Adjusted Consolidated Net Tangible Assets” of the Company means (without duplication), as of the date of determination, the remainder of:

(a) the sum of:

(i) discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated by the Company in a reserve report prepared as of the end of the Company’s most recently completed fiscal year for which audited financial statements are available, or, at the Company’s option, the most recently completed fiscal quarter for which financial statements are available, in each case which reserve report is prepared, reviewed or audited by independent petroleum engineers, as increased by, as of the date of determination, the estimated discounted future net revenues from

(A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end or quarterly reserve report, as applicable, and

(B) estimated oil and gas reserves attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and gas reserves since such year end or quarterly

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reserve report, as applicable, due to exploration, development or exploitation, production or other activities, which would, in accordance with standard industry practice, cause such revisions (including the impact to proved reserves and future net revenues from estimated development costs incurred and the accretion of discount since such period end), and decreased by, as of the date of determination, the estimated discounted future net revenues from

(C) estimated proved oil and gas reserves produced or disposed of since such year end or quarter end, as applicable, and

(D) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end or quarter end, as applicable, due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines,

in the case of clauses (A) through (D) calculated in accordance with SEC guidelines (using the prices and costs utilized in such year end or quarterly report, as applicable);provided,however, that in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be as estimated by the Company’s petroleum engineers;

(ii) the capitalized costs that are attributable to Oil and Gas Properties of the Company and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest available annual or quarterly financial statements;

(iii) the Net Working Capital of the Company and its Restricted Subsidiaries on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and

(iv) the greater of

(A) the net book value of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest annual or quarterly financial statements, and

(B) the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest quarterly or annual period for which financial statements are available;provided, that, if no such appraisal has been performed the Company shall not be required to obtain such an appraisal and only clause (iv)(A) of this definition shall apply;

minus

(b) the sum of:

(i) Minority Interests;

(ii) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest annual or quarterly balance sheet (to the extent not deducted in calculating Net Working Capital of the Company in accordance with clause (a)(iii) above of this definition);

(iii) to the extent included in (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (but utilizing prices and costs used in such year end or quarterly report, as applicable), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and

(iv) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of

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production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of the Company and its Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Company changes its method of accounting from the successful efforts method of accounting to the full cost or a similar method, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Company were still using the successful efforts method of accounting.

“Affiliate” of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, “control” when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

“Asset Disposition” means any direct or indirect sale, lease (including by means of Production Payments and Reserve Sales and a Sale/Leaseback Transaction but excluding an operating lease entered into in the ordinary course of the Oil and Gas Business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of (A) any Capital Stock of a Restricted Subsidiary (other than directors’ qualifying shares or shares required by applicable law to be held by a Person other than the Company or a Restricted Subsidiary) or (B) any other assets of the Company or any Restricted Subsidiary outside of the ordinary course of business of the Company or such Restricted Subsidiary (each referred to for the purposes of this definition as a “disposition”), in each case by the Company or any of its Restricted Subsidiaries, including any disposition by means of a merger, consolidation or similar transaction.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

(1) a disposition by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Restricted Subsidiary;

(2) a disposition of cash, Cash Equivalents or other financial assets in the ordinary course of business;

(3) a disposition of Hydrocarbons in the ordinary course of business;

(4) a disposition of damaged, unserviceable, obsolete or worn out equipment or equipment that is no longer necessary for the proper conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;

(5) transactions in accordance with the covenant described under “— Certain Covenants — Merger and Consolidation”;

(6) an issuance of Capital Stock by a Restricted Subsidiary to the Company or to a Restricted Subsidiary;

(7) the making of a Permitted Investment or a Restricted Payment (or a disposition that would constitute a Restricted Payment but for the exclusions from the definition thereof) permitted by the covenant described under “— Certain Covenants — Limitation on Restricted Payments”;

(8) an Asset Swap;

(9) dispositions of assets with a Fair Market Value of less than $10.0 million in any single transaction or series of related transactions;

(10) Permitted Liens;

(11) dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;

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(12) the licensing or sublicensing of intellectual property (including the licensing of seismic data or rights to access and use seismic data libraries);

(13) any Production Payments and Reserve Sales pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical or management services to the Company or a Restricted Subsidiary;

(14) surrender or waiver of contract rights, oil and gas leases, or the settlement, release or surrender of contract, tort or other claims of any kind; and

(15) the abandonment, assignment, farmout, lease, sublease, forfeiture or other disposition of developed or undeveloped Oil and Gas Properties in the ordinary course of business.

“Asset Swap” means any substantially contemporaneous (and in any event occurring within 180 days of each other) purchase and sale or exchange of any Oil and Gas Properties between the Company or any of its Restricted Subsidiaries and another Person;provided, that any cash received must be applied in accordance with “— Certain Covenants — Limitation on Sales of Assets and Subsidiary Stock” as if the Asset Swap were an Asset Disposition.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP;provided,however, that if such sale and leaseback transaction results in a Capitalized Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capitalized Lease Obligation”.

“Average Life” means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.

“Board of Directors” means, as to any Person that is a corporation, the board of directors of such Person or any duly authorized committee thereof or as to any Person that is not a corporation, the board of managers or such other individual or group serving a similar function. For so long as the Company is a limited partnership, the board of directors of the General Partner shall be deemed to be the Board of Directors of the Company.

“Borrowing Base” means, as of any time a determination thereof is to be made, the current maximum amount determined or re-determined by the lenders under the Senior Secured Credit Agreement as the aggregate lending value to be ascribed to the Oil and Gas Properties of the Company and its Restricted Subsidiaries against which such lenders are prepared to provide loans, letters of credit or other Indebtedness to the Company and the Restricted Subsidiaries under the Credit Agreement, using their customary practices and standards for determining conforming reserve based loans and which are generally applied by commercial bank lenders to similar borrowers with similar Oil and Gas Properties as those of the Company and its Restricted Subsidiaries, as determined semi-annually during each year and/or on such other occasions as may be provided for by the Senior Secured Credit Agreement, and which is based upon, inter alia, the review by such lenders of the hydrocarbon reserves, royalty interests and assets and liabilities of the Company and the Restricted Subsidiaries.

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“Business Day” means each day that is not a Saturday, Sunday or other day on which commercial banking institutions in New York, New York are authorized or required by law to close.

“Capital Stock” of any Person means any and all shares, units, interests, rights to purchase, warrants, options, participations or other equivalents of or interests in (however designated) the equity of such Person, including any Preferred Stock, but excluding any debt securities convertible into, or exchangeable for, such equity.

“Capitalized Lease Obligation” means an obligation that is required to be classified and accounted for as a capitalized lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation will be the capitalized amount of such obligation at the time any determination thereof is to be made as determined in accordance with GAAP, and the Stated Maturity thereof will be the date of the last payment of rent or any other amount due under such lease prior to the first date such lease may be terminated without penalty.

“Cash Equivalents” means:

(1) securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality of the United States (provided that the full faith and credit of the United States is pledged in support thereof), having maturities of not more than one year from the date of acquisition;

(2) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition and, at the time of acquisition, having one of the two highest ratings obtainable from either S&P or Moody’s;

(3) certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers’ acceptances having maturities of not more than one year from the date of acquisition thereof issued by any commercial bank the short-term deposit of which is rated at the time of acquisition thereof at least “A-2” or the equivalent thereof by S&P, or “P-2” or the equivalent thereof by Moody’s, and having combined capital and surplus in excess of $500.0 million;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;

(5) commercial paper rated at the time of acquisition thereof at least “A-2” by S&P or “P-2” by Moody’s, and in either case maturing within nine months after the date of acquisition thereof; and

(6) interests in any investment company or money market fund which invests 95% or more of its assets in instruments of the type specified in clauses (1) through (5) above.

“Change of Control” means:

(1) any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), other than a Permitted Holder, is or becomes the Beneficial Owner, directly or indirectly, of more than 50% of the total voting power of the Voting Stock of the General Partner (or, following the conversion of the Company into another form as described below, more than 50% of the total voting power of the Voting Stock of the successor entity to the Company), in each case which occurrence is followed by a Rating Decline within 90 days thereafter;

(2) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act), other than to the Company, a Restricted Subsidiary or a Permitted Holder, in each case which occurrence is followed by a Rating Decline within 90 days thereafter; or

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(3) the adoption by the members of the General Partner or the partners of the Company (or, following the conversion of the Company into another form as described below, its equity holders) of a plan or proposal for the liquidation or dissolution of the Company.

Notwithstanding the preceding, a conversion (whether by merger, statutory conversion or otherwise) of the Company from a limited partnership to a limited liability company or corporation, or an exchange of all of the outstanding partnership interests in the Company for Capital Stock in a corporation or a limited liability company, shall not constitute a Change of Control, so long as following such conversion or exchange the “persons” (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Capital Stock of the General Partner and the Company immediately prior to such transactions continue to Beneficially Own in the aggregate sufficient Capital Stock of such successor entity to elect a majority of its directors, managers, trustees or other persons serving in a similar capacity for such successor entity.

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

“Commodity Agreements” means, in respect of any Person, any forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons used, produced, processed or sold by such Person that is customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbon prices.

“Common Stock” means, with respect to any Person, any and all Capital Stock (however designated and whether voting or nonvoting) of such Person other than any Preferred Stock, whether or not outstanding on the Issue Date, and includes all series and classes of such Capital Stock.

“Consolidated Coverage Ratio” means, for any Person, as of any date of determination, the ratio of (x) the aggregate amount of Consolidated EBITDAX of such Person for the period of the most recent four consecutive fiscal quarters ending prior to the date of such determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters,provided,however, that:

(1) if the Company or any Restricted Subsidiary:

(a) has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to the Incurrence of such Indebtedness and the use of proceeds thereof as if such Indebtedness had been Incurred on the first day of such period and such proceeds had been applied as of such date (except that in making such computation, the amount of any revolving credit Indebtedness outstanding on the date of such calculation will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period during which such Indebtedness was outstanding or (ii) if such revolving credit Indebtedness was Incurred after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of Incurrence of such revolving credit Indebtedness to the date of such calculation, in each case,provided that such average daily balance shall take into account any permanent repayment of such revolving credit Indebtedness as provided in clause (b)); or

(b) has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period, including with the proceeds of such new Indebtedness, that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case other than any revolving credit Indebtedness, unless such revolving credit Indebtedness has been permanently repaid and the related commitment terminated), Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness as if such discharge had occurred on the first day of such period;

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(2) if, since the beginning of such period, the Company or any Restricted Subsidiary has made any Asset Disposition or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Disposition, the Consolidated EBITDAX for such period will be reduced by an amount equal to the Consolidated EBITDAX (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period or increased by an amount equal to the Consolidated EBITDAX (if negative) directly attributable thereto for such period and Consolidated Interest Expense for such period shall be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with or with the proceeds from such Asset Disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

(3) if, since the beginning of such period, the Company or any Restricted Subsidiary (by merger or otherwise) has made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company or a Restricted Subsidiary) or an acquisition (or has received a contribution) of assets, including any acquisition or contribution of assets occurring in connection with a transaction causing a calculation to be made under the Indenture, which constitutes all or substantially all of a Company division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition or contribution had occurred on the first day of such period; and

(4) if, since the beginning of such period, any Person (that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period) made any Asset Disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Disposition or Investment or acquisition of assets had occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined on behalf of the Company in good faith by a responsible financial or accounting officer of the Company;provided that such officer may in his or her discretion include any reasonably identifiable and factually supportable pro forma changes to Consolidated EBITDAX, including any pro forma expenses and cost reductions, that have occurred or in the judgment of such officer are reasonably expected to occur within 12 months of the date of the applicable transaction (regardless of whether such expense or cost reduction or any other operating improvements could then be reflected properly in pro forma financial statements prepared in accordance with Regulation S-X under the Securities Act or any other regulation or policy of the SEC). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness, but if the remaining term of such Interest Rate Agreement is less than 12 months, then such Interest Rate Agreement shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company or any Restricted Subsidiary, the interest rate shall be calculated by applying such optional rate chosen by the Company or such Restricted Subsidiary. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Company or the applicable Restricted Subsidiary may designate.

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“Consolidated EBITDAX” for any period means, without duplication, the Consolidated Net Income for such period, plus the following, without duplication and to the extent deducted (and not added back) in calculating such Consolidated Net Income:

(1) Consolidated Interest Expense;

(2) Consolidated Income Tax Expense;

(3) consolidated depletion and depreciation expense of the Company and its Restricted Subsidiaries;

(4) consolidated amortization expense or impairment charges of the Company and its Restricted Subsidiaries recorded in connection with the application of ASC-350 and ASC-360;

(5) other non-cash charges of the Company and its Restricted Subsidiaries (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation); and

(6) the consolidated exploration and abandonment expense of the Company and its Restricted Subsidiaries,

if applicable for such period; and less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto that were deducted (and not added back) in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that is amortized during such period and is attributable to reserves that are subject to Volumetric Production Payments, (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments and (z) other non-cash gains (excluding any non-cash gain to the extent it represents the reversal of an accrual or reserve for a potential cash item that reduced Consolidated EBITDAX in any prior period).

Notwithstanding the preceding sentence, clauses (2) through (6) relating to amounts of a Restricted Subsidiary will be added to Consolidated Net Income to compute Consolidated EBITDAX of the Company only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of the Company and, to the extent the amounts set forth in clauses (2) through (6) are in excess of those necessary to offset a net loss of such Restricted Subsidiary or if such Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or the holders of its Capital Stock.

“Consolidated Income Tax Expense” means, with respect to any period, the provision for federal, state, local and foreign taxes (including state franchise taxes) based on income of the Company and its Restricted Subsidiaries for such period as determined in accordance with GAAP, or (for any period in which the Company is a partnership) the Tax Amount for such period.

“Consolidated Interest Expense” means, for any period, the total consolidated interest expense (excluding interest income and any interest expense attributable to any Founder Note) of the Company and its Restricted Subsidiaries, whether paid or accrued, plus, to the extent not included in such interest expense and without duplication:

(1) interest expense attributable to Capitalized Lease Obligations or Attributable Debt and the interest component of any deferred payment obligations;

(2) amortization of debt discount and debt issuance cost (provided that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense);

(3) non-cash interest expense;

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(4) commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing;

(5) the interest expense on Indebtedness of another Person that is guaranteed by the Company or one of its Restricted Subsidiaries or secured by a Lien on assets of the Company or one of its Restricted Subsidiaries;

(6) cash costs associated with Interest Rate Agreements (including amortization of fees);provided,however, that if Interest Rate Agreements result in net cash benefits rather than costs, such benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;

(7) the consolidated interest expense of the Company and its Restricted Subsidiaries that was capitalized during such period; and

(8) all dividends paid or payable in cash, Cash Equivalents or Indebtedness, or accrued during such period, in each case on any series of Disqualified Stock of the Company or on Preferred Stock of its Restricted Subsidiaries payable to a party other than the Company or a Wholly Owned Subsidiary.

For the purpose of calculating the Consolidated Coverage Ratio in connection with the Incurrence of any Indebtedness described in the final paragraph of the definition of “Indebtedness”, the calculation of Consolidated Interest Expense shall include all interest expense (including any amounts described in clauses (1) through (8) above) relating to any Indebtedness of the Company or any Restricted Subsidiary described in the final paragraph of the definition of “Indebtedness”.

“Consolidated Net Income” means, for any period, the aggregate net income (loss) of the Company and its Subsidiaries determined in accordance with GAAP and before any reduction in respect of Preferred Stock dividends of such Person, less (for any period the Company is a partnership) the Tax Amount for such period;provided,however, that there will not be included (to the extent otherwise included therein) in such Consolidated Net Income:

(1) any net income (loss) of any Person (other than the Company) if such Person is not a Restricted Subsidiary, except that:

(a) subject to the limitations contained in clauses (3) and (4) below, the Company’s equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (2) below); and

(b) the Company’s equity in a net loss of any such Person for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary during such period;

(2) any net income (but not loss) of any Restricted Subsidiary if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a) subject to the limitations contained in clauses (3) and (4) below, the Company’s equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution paid to another Restricted Subsidiary, to the limitation contained in this clause); and

(b) the Company’s equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

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(3) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its Subsidiaries (including pursuant to any Sale/Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

(4) any extraordinary or nonrecurring gains or losses, together with any related provision for taxes (and, without duplication, any related Permitted Tax Distributions) on such gains or losses and all related fees and expenses;

(5) the cumulative effect of a change in accounting principles;

(6) any asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines;

(7) any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of ASC-815);

(8) income or loss attributable to discontinued operations (including operations disposed of during such period whether or not such operations were classified as discontinued);

(9) all deferred financing costs written off, and premiums paid, in connection with any early extinguishment of Indebtedness; and

(10) any non-cash compensation charge arising from any grant of stock, stock options or other equity based awards;provided that the proceeds resulting from any such grant will be excluded from clause (4)(c)(ii) of the first paragraph of the covenant described under “— Certain Covenants — Limitation on Restricted Payments”.

“Credit Facility” means, with respect to the Company or any Subsidiary Guarantor, one or more debt facilities (including, without limitation, the Senior Secured Credit Agreement), indentures, or commercial paper facilities providing for revolving credit loans, term loans, capital markets financings, private placements, receivables financing (including through the sale of receivables to lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit from banks or other institutional lenders or investors (whether accredited or non-accredited), in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced (including by means of sales of debt securities) in whole or in part from time to time (and whether or not with the original administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Senior Secured Credit Agreement or any other credit or other agreement or indenture).

“Currency Agreement” means in respect of a Person any foreign exchange contract, currency swap agreement, futures contract, option contract or other similar agreement as to which such Person is a party or a beneficiary.

“Default” means any event which is, or after notice or passage of time or both would be, an Event of Default.

“Designated Non-cash Consideration” means the Fair Market Value of non-cash consideration received by the Company or a Restricted Subsidiary in connection with an Asset Sale that is so designated as Designated Non-cash Consideration pursuant to an Officers’ Certificate setting forth the basis of such valuation, less the amount of cash or Cash Equivalents received in connection with a subsequent sale of or collection on such Designated Non-cash Consideration.

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) at the option of the holder of the Capital Stock or upon the happening of any event:

(1) matures or is mandatorily redeemable (other than redeemable only for Capital Stock of such Person which is not itself Disqualified Stock) pursuant to a sinking fund obligation or otherwise;

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(2) is convertible or exchangeable for Disqualified Stock or other Indebtedness (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or

(3) is required to be repurchased by such Person at the option of the holder of the Capital Stock in whole or in part,

in each case on or prior to the date that is 91 days after the earlier of the date (a) of the Stated Maturity of the Notes or (b) on which there are no Notes outstanding;provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so required to be repurchased at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock;provided further, that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company or any of its Restricted Subsidiaries to repurchase such Capital Stock upon the occurrence of a change of control or asset sale (each defined in a substantially identical manner to the corresponding definitions in the Indenture) shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is exchangeable) provide that (i) the Company and its Restricted Subsidiaries may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company and its Restricted Subsidiaries with the provisions of the Indenture described under the captions “— Change of Control” and “— Certain Covenants — Limitation on Sales of Assets and Subsidiary Stock” and (ii) such repurchase or redemption will be permitted solely to the extent also permitted in accordance with the provisions of the Indenture described under the caption “— Certain Covenants — Limitation on Restricted Payments”.

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary that is not a Foreign Subsidiary.

“Equity Offering” means a public or private offering for cash by the Company of its Capital Stock (other than Disqualified Stock) or any cash capital contributions received by the Company from any of its partners.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Fair Market Value” means, with respect to any asset or property, the sale value that would be obtained in an arm’s-length free market transaction between an informed and willing seller under no compulsion to sell and an informed and willing buyer under no compulsion to buy. Fair Market Value of an asset or property in excess of $20.0 million shall be determined by the Board of Directors of the Company acting in good faith, whose determination shall be conclusive and evidenced by a resolution of such Board of Directors, and any lesser Fair Market Value may be determined by an officer of the Company acting in good faith.

“Foreign Subsidiary” means any Restricted Subsidiary that is not organized under the laws of the United States of America or any state thereof or the District of Columbia and that conducts substantially all of its operations outside the United States of America.

“Founder Notes” means (a) the Second Amended and Restated Promissory Note dated March 25, 2014 made by Galveston Bay Resources, LP in favor of Michael E. Ellis in the original principal amount of $345,523.89, (b) the Second Amended and Restated Promissory Note dated March 25, 2014 made by the Company in favor of Michael E. Ellis in the original principal amount of $11,561,550.87, and (c) the Second Amended and Restated Promissory Note dated March 25, 2014 made by Petro Acquisitions, LP in favor of Michael E. Ellis in the original principal amount of $178,278.21, in each case, as in effect on the Issue Date and as they may be amended, restated or otherwise supplemented, replaced or refinanced in accordance with the Indenture.

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“GAAP” means generally accepted accounting principles in the United States of America as in effect on the Issue Date. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP.

“General Partner” means Alta Mesa Holdings GP, LLC, a Texas limited liability company, and its successors as general partner of the Company.

The term “guarantee” means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or

(2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part);

provided,however, that the term “guarantee” will not include endorsements for collection or deposit in the ordinary course of business or any obligation to the extent it is payable only in Capital Stock of the guarantor that is not Disqualified Stock. The term “guarantee” used as a verb has a corresponding meaning.

“Guarantor Subordinated Obligation” means, with respect to a Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinated in right of payment to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee pursuant to a written agreement.

“Hedging Obligations” of any Person means the obligations of such Person pursuant to any Interest Rate Agreement, Currency Agreement or Commodity Agreement.

The term “holder” means a Person in whose name a Note is registered on the registrar’s books.

“Hydrocarbons” means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Immaterial Subsidiary” means, as of any date, any Restricted Subsidiary with no Indebtedness in excess of $500,000, and whose total assets, as of the end of the most recent month for which financial statements are available, taken together with those of all other Immaterial Subsidiaries, are less than 1.0% of the Company’s Adjusted Consolidated Net Tangible Assets and whose total revenues, taken together with those of all other Immaterial Subsidiaries, for the most recent 12-month period for which financial statements are available do not exceed 1.0% of the Company’s total consolidated revenues for such period.

“Incur” means issue, create, assume, guarantee, incur or otherwise become directly or indirectly liable for, contingently or otherwise;provided,however, that any Indebtedness or Capital Stock of a Person existing at the time such Person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary; and the terms “Incurred” and “Incurrence” have meanings correlative to the foregoing.

“Indebtedness” means, with respect to any Person on any date of determination (without duplication, whether or not contingent):

(1) the principal of and premium (if any) in respect of indebtedness of such Person for borrowed money;

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(2) the principal of and premium (if any) in respect of obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3) the principal component of all obligations of such Person in respect of letters of credit, bankers’ acceptances or other similar instruments (including reimbursement obligations with respect thereto except to the extent such reimbursement obligation relates to a trade payable and except to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such obligation is satisfied within five Business Days of payment on the letter of credit);

(4) the principal component of all obligations of such Person to pay the deferred and unpaid purchase price of property, which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto to the extent such obligations would appear as liabilities upon the consolidated balance sheet of such Person in accordance with GAAP, as obligor on conditional sales of property or under any title retention agreement;

(5) Capitalized Lease Obligations or Attributable Debt of such Person;

(6) the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary of such Person, any Preferred Stock (but excluding, in each case, any accrued dividends);

(7) the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person;provided,however, that the amount of such Indebtedness will be the lesser of (a) the Fair Market Value of such asset at such date of determination and (b) the amount of such Indebtedness of such other Persons;

(8) the principal component of Indebtedness of other Persons to the extent guaranteed by such Person; and

(9) to the extent not otherwise included in this definition, net obligations of such Person under Commodity Agreements, Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time);

provided,however, that any indebtedness which has been defeased in accordance with GAAP or defeased pursuant to the deposit of cash or Cash Equivalents (in an amount sufficient to satisfy all such indebtedness obligations at maturity or redemption, as applicable, and all payments of interest and premium, if any) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, and subject to no other Liens, shall not constitute “Indebtedness”.

The amount of Indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date.

Notwithstanding the preceding, “Indebtedness” shall not include:

(1) Production Payments and Reserve Sales;

(2) any obligation of a Person in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an Oil and Gas Property;

(3) any obligations under Currency Agreements, Commodity Agreements and Interest Rate Agreements;provided that such Agreements are entered into for bona fide hedging purposes of the

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Company or its Restricted Subsidiaries (as determined in good faith by the Board of Directors or senior management of the Company, whether or not accounted for as a hedge in accordance with GAAP) and, in the case of Currency Agreements or Commodity Agreements, such Currency Agreements or Commodity Agreements are related to business transactions of the Company or its Restricted Subsidiaries entered into in the ordinary course of business and, in the case of Interest Rate Agreements, such Interest Rate Agreements substantially correspond in terms of notional amount, duration and interest rates, as applicable, to Indebtedness of the Company or its Restricted Subsidiaries Incurred without violation of the Indenture;

(4) any obligation arising from customary agreements of the Company or a Restricted Subsidiary providing for indemnification, guarantees, adjustment of purchase price, holdbacks, contingency payment obligations or similar obligations, in each case, Incurred or assumed in connection with the acquisition or disposition of any business, assets or Capital Stock of a Restricted Subsidiary,provided that such Indebtedness is not reflected on the face of the balance sheet of the Company or any Restricted Subsidiary;

(5) any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (including daylight overdrafts) drawn against insufficient funds in the ordinary course of business,provided that such Indebtedness is extinguished within five Business Days of Incurrence;

(6) in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business; and

(7) accrued expenses and trade payables and other accrued liabilities arising in the ordinary course of business that are not overdue by 90 days or more or are being contested in good faith by appropriate proceedings promptly instituted and diligently conducted.

In addition, “Indebtedness” of any Person shall include Indebtedness described in the first paragraph of this definition of “Indebtedness” whether or not it would appear as a liability on the balance sheet of such Person if:

(1) such Indebtedness is the obligation of a joint venture or partnership that is not a Restricted Subsidiary (a “Joint Venture”);

(2) such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture or otherwise liable for all or a portion of the Joint Venture’s liabilities (a “general partner”); and

(3) there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person;

and then such Indebtedness shall be included in an amount not to exceed:

(a) the lesser of (i) the net assets of the general partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b) if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is with recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount.

“Initial Unrestricted Subsidiaries” means Alta Mesa Drilling, LLC, Brayton Management GP, LLC, Brayton Management GP II, LLC, Brayton Resources, L.P., Brayton Resources II, L.P., FBB Anadarko, LLC, LEADS Resources, LLC, Louisiana Exploration & Acquisition Partnership, LLC, New Exploration Technologies Co., LLC, Orion Operating Company, LP, Sundance Acquisition, LLC, TE TMR, LLC, TMR Equipment, LLC.

“Interest Rate Agreement” means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

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“Investment” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan or other extensions of credit (including by way of guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time deposit and advances or extensions of credit to customers in the ordinary course of business) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments (excluding any interest in an oil or natural gas leasehold to the extent constituting a security under applicable law) issued by, such other Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP;provided that none of the following will be deemed to be an Investment:

(1) Hedging Obligations entered into in the ordinary course of business and in compliance with the Indenture; and

(2) endorsements of negotiable instruments and documents in the ordinary course of business.

The amount of any Investment shall not be adjusted for increases or decreases in value, write-ups, write-downs or write-offs with respect to such Investment.

For purposes of the definition of “Unrestricted Subsidiary” and the covenant described under “— Certain Covenants — Limitation on Restricted Payments”,

(1) “Investment” will include the portion (proportionate to the Company’s equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the Fair Market Value of the net assets of such Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary;provided,however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to (a) the Company’s “Investment” in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company’s equity interest in such Subsidiary) of the Fair Market Value of the net assets of such Subsidiary at the time that such Subsidiary is so redesignated a Restricted Subsidiary; and

(2) any property transferred to or from an Unrestricted Subsidiary will be valued at its Fair Market Value at the time of such transfer.

“Issue Date” means the first date on which the Notes are issued under the Indenture.

“Lien” means, with respect to any asset, any mortgage, lien (statutory or otherwise), pledge, hypothecation, charge, security interest, preference, priority or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement not intended as a security agreement.

“Minority Interest” means the percentage interest represented by any class of Capital Stock of a Restricted Subsidiary that are not owned by the Company or a Restricted Subsidiary.

“Moody’s” means Moody’s Investors Service, Inc., or any successor to the rating agency business thereof.

“Net Available Cash” from an Asset Disposition means cash payments received (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise and net proceeds from the sale or other disposition of any securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring

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Person of Indebtedness or other obligations relating to the assets that are the subject of such Asset Disposition or received in any other non-cash form) therefrom, in each case net of:

(1) all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses Incurred, and all federal, state, provincial, foreign and local taxes (or Permitted Tax Distributions in respect thereof) required to be paid or accrued as, a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;

(2) all payments made on any Hedging Obligation or other Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;

(3) all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures or to holders of royalty or similar interests as a result of such Asset Disposition;

(4) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition; and

(5) all relocation expenses incurred as a result thereof and all related severance and associated costs, expenses and charges of personnel related to assets and related operations disposed of;

provided,however, that if any consideration for an Asset Disposition (that would otherwise constitute Net Available Cash) is required to be held in escrow pending determination of whether or not a purchase price adjustment will be made, such consideration (or any portion thereof) shall become Net Available Cash only at such time as it is released to the Company or any of its Restricted Subsidiaries from escrow.

“Net Cash Proceeds”, with respect to any issuance or sale of Capital Stock or any contribution to equity capital, means the cash proceeds of such issuance, sale or contribution net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually Incurred in connection with such issuance, sale or contribution and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

“Net Working Capital” means (a) the sum of all current assets of the Company and its Restricted Subsidiaries, except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, (other than accounts receivable with respect to any non-contingent periodic settlement payments due thereunder), less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities (i) associated with asset retirement obligations relating to Oil and Gas Properties, (ii) included in Indebtedness and (iii) any current liabilities of the Company and its Restricted Subsidiaries from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, (other than accounts payable with respect to any non-contingent periodic settlement payments due thereunder), in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness of a Person:

(1) as to which neither the Company nor any Restricted Subsidiary (a) provides any guarantee or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute Indebtedness), or (b) is directly or indirectly liable (as a guarantor or otherwise);

(2) no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both)

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any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default under such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its Stated Maturity; and

(3) the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

“Officer” means the Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, Chief Accounting Officer, any Vice President, the Treasurer or the Secretary of an Issuer. Officer of any Subsidiary Guarantor has a correlative meaning, and in the case of the Company (so long as it is a limited partnership), Officer means an Officer of its General Partner.

“Officers’ Certificate” means a certificate signed by two Officers of the Company, at least one of whom shall be the Chief Executive Officer, the Chief Financial Officer or the Chief Accounting Officer of the Company.

“Oil and Gas Business” means (a) the business of exploiting, exploring for, developing, acquiring, operating, producing, processing, gathering, marketing, storing, selling, hedging, treating, swapping and transporting (but not refining) Hydrocarbons, and (b) any activity that is ancillary to or necessary or appropriate for any of the activities described in clause (a) of this definition.

“Oil and Gas Properties” means any and all rights, titles, interests and estates in and to (1) oil or gas leases or (2) other liquid or gaseous Hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, in each case including any reserved or residual interests of whatever nature.

“Opinion of Counsel” means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to an Issuer, a Subsidiary Guarantor or the Trustee.

“Pari Passu Indebtedness” means any Indebtedness of either Issuer or any Subsidiary Guarantor that ranks equally in right of payment to the Notes or the Subsidiary Guarantees, as the case may be.

“Permitted Acquisition Indebtedness” means Indebtedness (including Disqualified Stock) of the Company or any of the Restricted Subsidiaries to the extent such Indebtedness was Indebtedness:

(1) of an acquired Person prior to the date on which such Person became a Restricted Subsidiary as a result of having been acquired and not incurred in contemplation of such acquisition; or

(2) of a Person that was merged or consolidated with or into the Company or a Restricted Subsidiary that was not incurred in contemplation of such merger or consolidation,

provided that on the date such Person became a Restricted Subsidiary or the date such Person was merged or consolidated with or into the Company or a Restricted Subsidiary, as applicable, after giving pro forma effect thereto, the Restricted Subsidiary or the Company, as applicable, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Consolidated Coverage Ratio test described under “— Certain Covenants — Limitation on Indebtedness and Preferred Stock”.

“Permitted Business Investment” means any Investment made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business including through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties including:

(1) ownership interests in oil, natural gas, other Hydrocarbon and mineral properties, processing facilities, gathering systems, storage facilities or related systems or ancillary real property interests;

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(2) Investments in the form of or pursuant to operating agreements, working interests, royalty interests, mineral leases, processing agreements, farm-in agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil, natural gas, other Hydrocarbons and minerals, production sharing agreements, participation agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements, stockholder agreements and other similar agreements (including for limited liability companies) with third parties.

“Permitted Holder” means any of the following (A) (i) Michael E. Ellis, Mickey Ellis and their children, estates, heirs or lineal descendants, (ii) Harlan H. Chappelle, his spouse and his children, estates, heirs or lineal descendants (including by adoption), (iii) any trust having as its sole beneficiaries one or more of the persons listed in clauses (A)(i) or (ii) above, and (iv) any Person a majority of the Voting Stock of which is owned or controlled one or more of the Persons referred to in clauses (A)(i), (ii) or (iii); (B) HPS Investment Partners, LLC, a Delaware limited liability company and its successors and any of its Affiliates and any holder, fund or account managed or controlled by HPS Investment Partners, LLC or any Affiliate of HPS Investment Partners, LLC (other than any operating company in which it has a portfolio investment), (C) BCE-Mesa Holdings LLC, a Delaware limited liability company and its successors and any of its Affiliates, and any holder, fund or account managed or controlled by Bayou City Energy Management, LLC or any Affiliate of Bayou City Energy Management, LLC (other than any operating company in which it has a portfolio investment), and (D) any group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act or any successor provision) of which any of the forgoing are members.

“Permitted Investment” means an Investment by the Company or any Restricted Subsidiary in:

(1) the Company or a Restricted Subsidiary;

(2) another Person whose primary business is the Oil and Gas Business if as a result of such Investment such other Person becomes a Restricted Subsidiary or is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary;provided,however, that the primary business of such Restricted Subsidiary is the Oil and Gas Business;

(3) cash and Cash Equivalents;

(4) receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms;provided,however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

(5) payroll, commission, travel, relocation, expense and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;

(6) loans or advances to employees (other than executive officers or directors) made in the ordinary course of business of the Company or such Restricted Subsidiary;

(7) Capital Stock or other securities received in settlement of debts (x) created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments or (y) pursuant to any plan of reorganization or similar arrangement in a bankruptcy or insolvency proceeding;

(8) any Person as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with the covenant described under “Certain Covenants — Limitation on Sales of Assets and Subsidiary Stock”;

(9) Investments in existence on the Issue Date;

(10) Commodity Agreements, Currency Agreements, Interest Rate Agreements described in clause (3) of the penultimate paragraph of the definition of “Indebtedness”, and related Hedging Obligations;

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(11) guarantees issued in accordance with the covenant described under “— Certain Covenants —Limitation on Indebtedness and Preferred Stock”;

(12) Permitted Business Investments;

(13) any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers’ compensation, performance and other similar deposits made in the ordinary course of business by the Company or any Restricted Subsidiary;

(14) guarantees of performance or other obligations (other than Indebtedness) arising in the ordinary course of the Oil and Gas Business, including obligations under oil and natural gas exploration, development, joint operating, and related agreements and licenses, concessions or operating leases related to the Oil and Gas Business;

(15) Investments in the Notes;

(16) Investments made after the Issue Date in Unrestricted Subsidiaries in an aggregate amount outstanding at any time not to exceed $10.0 million; and

(17) Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (17), in an aggregate amount outstanding at the time of such Investment not to exceed the greater of (i) $40.0 million and (ii) 5.0 % of the Company’s Adjusted Consolidated Net Tangible Assets.

“Permitted Liens” means, with respect to any Person:

(1) Liens securing Indebtedness under a Credit Facility permitted to be Incurred under clause (1) of the second paragraph of the covenant set forth under “— Limitation on Indebtedness and Preferred Stock”;

(2) pledges or deposits by such Person under workers’ compensation laws, unemployment insurance laws, social security or old age pension laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits (which may be secured by a Lien) to secure public or statutory obligations of such Person including letters of credit and bank guarantees required or requested by the United States, any State thereof or any foreign government or any subdivision, department, agency, organization or instrumentality of any of the foregoing in connection with any contract or statute (including lessee or operator obligations under statutes, governmental regulations, contracts or instruments related to the ownership, exploration and production of oil, natural gas, other hydrocarbons and minerals on state, federal or foreign lands or waters), or deposits of cash or United States government bonds to secure indemnity performance, surety or appeal bonds or other similar bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case Incurred in the ordinary course of business;

(3) statutory and contractual Liens of landlords and Liens imposed by law, including carriers’, warehousemen’s, mechanics’, materialmen’s and repairmen’s Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings if a reserve or other appropriate provisions, if any, as shall be required by GAAP shall have been made in respect thereof;

(4) Liens for taxes, assessments or other governmental charges or claims not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings;provided that appropriate reserves, if any, required pursuant to GAAP have been made in respect thereof;

(5) Liens in favor of issuers of surety or performance bonds or bankers’ acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business;

(6) survey exceptions, encumbrances, ground leases, easements or reservations of, or rights of others for, licenses, rights of way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning, building codes or other restrictions (including minor defects or irregularities in title and similar encumbrances) as to the use of real properties or Liens incidental to the conduct of the business of such

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Person or to the ownership of its properties or assets which do not in the aggregate materially adversely affect the value of the properties or assets of such Person and its Restricted Subsidiaries, taken as a whole, or materially impair their use in the operation of the business of such Person;

(7) Liens arising from the deposit of funds or securities in trust for the purpose of decreasing or defeasing Indebtedness so long as such deposit of funds or securities and such decreasing or defeasing of Indebtedness are permitted under the covenant described under “— Certain Covenants — Limitation on Restricted Payments”;

(8) Liens arising from leases, licenses, subleases and sublicenses of any property or assets (including real property and intellectual property rights) entered into in the ordinary course of the Oil and Gas Business;

(9) prejudgment Liens and judgment Liens not giving rise to an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10) Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capitalized Lease Obligations, purchase money obligations or other payments Incurred to finance the acquisition, lease, improvement or construction of or repairs or additions to, assets or property acquired or constructed in the ordinary course of business;provided that:

(a) the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture and does not exceed the cost of the assets or property so acquired or constructed; and

(b) such Liens are created within 180 days of the later of the acquisition, lease, completion of improvements, construction, repairs or additions or commencement of full operation of the assets or property subject to such Lien and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

(11) Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution;provided that:

(a) such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

(b) such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12) Liens arising from deposits made in the ordinary course of business to secure any liability to insurance carriers;

(13) Liens existing on the Issue Date;

(14) Liens on any property or assets of a Person at the time such Person becomes a Subsidiary;provided,however, that such Liens are not created or Incurred in connection with, or in contemplation of, such other Person becoming a Subsidiary;provided further,however, that any such Lien may not extend to any other property or assets owned by the Company or any Restricted Subsidiary (other than any property or assets affixed or appurtenant thereto);

(15) Liens on any property or assets at the time the Company or any of its Subsidiaries acquired the property or assets, including any acquisition by means of a merger or consolidation with or into the Company or any of its Subsidiaries;provided,however, that such Liens are not created or Incurred in connection with, or in contemplation of, such acquisition;provided further,however, that such Liens may not extend to any other property or assets owned by the Company or any Restricted Subsidiary (other than any property or assets affixed or appurtenant thereto);

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(16) Liens securing the Notes, the Subsidiary Guarantees and any other Obligations under the Indenture;

(17) Liens securing Refinancing Indebtedness Incurred to refinance Indebtedness described under clauses (10), (13), (14), (15) or this clause (17) that was previously so secured,provided that any such Lien is limited to all or part of the same property or assets that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property or assets that is the security for a Permitted Lien hereunder;

(18) any interest or title of a lessor under any operating lease;

(19) Liens arising under farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements that are customary in the Oil and Gas Business;provided,however, in all instances that such Liens are limited to the property or assets that are the subject of the relevant agreement, program, order or contract;

(20) Liens on pipelines or pipeline facilities that arise by operation of law;

(21) Liens in favor of the Company, the Co-Issuer or any Subsidiary Guarantor; and

(22) Liens securing Indebtedness in an aggregate principal amount outstanding at any one time, added together with all other Indebtedness secured by Liens Incurred pursuant to this clause (22), not to exceed the greater of (a) $25.0 million and (b) 3.0% of the Company’s Adjusted Consolidated Net Tangible Assets.

In each case set forth above, notwithstanding any stated limitation on the property or assets that may be subject to such Lien, a Permitted Lien on a specified property or asset or group or type of properties or assets may include Liens on all improvements, additions and accessions thereto and all products and proceeds thereof (including dividends, distributions and increases in respect thereof).

“Permitted Tax Distributions” means for any calendar year or portion thereof of the Company during which it is a pass-through entity for U.S. federal income tax purposes, payments and distributions to the partners of the Company on each estimated payment date as well as each other applicable due date to enable the partners of the Company (or, if any of them are themselves a pass-through entity for US. Federal income tax purposes, their shareholders or partners) to make payments of U.S. federal and state income taxes (including estimates therefor) as a result of the operations of the Company and its Subsidiaries during the current and any previous calendar year, not to exceed an amount equal to the amount of each such partner’s (or, in the case of a pass-through entity, its shareholders’ or partners’) U.S. federal and state income tax liability resulting solely from the pass-through tax treatment of such partner’s interest in the Company and as calculated pursuant to the limited partnership agreement of the Company as in effect on the Issue Date and as it may be amended from time to time thereafter in a manner that is not, considered as a whole, materially adverse to the holders of the Notes.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company, government or any agency or political subdivision thereof or any other entity.

“Preferred Stock”, as applied to the Capital Stock of any Person, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such Person, over shares of Capital Stock of any other class of such Person.

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“Production Payments and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical or management services to the Company or a Restricted Subsidiary.

“Rating Category” means:

(1) with respect to S&P, any of the following categories: AAA, AA, A, BBB, BB, B, CCC, CC, C and D (or equivalent successor categories); and

(2) with respect to Moody’s, any of the following categories: Aaa, Aa, A, Baa, Ba, B, Caa, Ca, C and D (or equivalent successor categories).

“Rating Decline” means a decrease in the rating of the Notes by either Moody’s or S&P by one or more gradations (including gradations within Rating Categories as well as between Rating Categories). In determining whether the rating of the Notes has decreased by one or more gradations, gradations within Rating Categories, namely + or—for S&P, and 1, 2, and 3 for Moody’s, will be taken into account; for example, in the case of S&P, a rating decline either from BB+ to BB or BB- to B+ will constitute a decrease of one gradation.

“Refinancing Indebtedness” means Indebtedness that is Incurred to refund, refinance, replace, exchange, renew, repay, extend, prepay, redeem or retire (including pursuant to any defeasance or discharge mechanism) (collectively, “refinance” and the terms “refinances” and “refinanced” shall have correlative meanings) any Indebtedness (including Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary, but excluding Indebtedness of a Restricted Subsidiary (other than the Co-Issuer or a Subsidiary Guarantor) that refinances Indebtedness of the Issuers or another Subsidiary Guarantor), including Indebtedness that refinances Refinancing Indebtedness,provided,however, that:

(1) (a) if the Stated Maturity of the Indebtedness being refinanced is earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the Notes;

(2) the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;

(3) such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs required by the instruments governing such existing Indebtedness and fees and expenses Incurred in connection therewith); and

(4) if the Indebtedness being refinanced is subordinated in right of payment to the Notes or a Subsidiary Guarantee, such Refinancing Indebtedness is subordinated in right of payment to the Notes or the Subsidiary Guarantee on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being refinanced.

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“Registration Rights Agreement” means that certain registration rights agreement dated as of the Issue Date by and among the Issuers, the Subsidiary Guarantors and the initial purchasers set forth therein and, with respect to any Additional Notes, one or more substantially similar registration rights agreements among the Issuers and the other parties thereto, as any such agreement may be amended from time to time.

“Restricted Investment” means any Investment other than a Permitted Investment.

“Restricted Subsidiary” means any Subsidiary of the Company other than an Unrestricted Subsidiary.

“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., or any successor to the rating agency business thereof.

“Sale/Leaseback Transaction” means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to a Person and the Company or a Restricted Subsidiary leases it from such Person.

“SEC” means the United States Securities and Exchange Commission.

“Senior Secured Credit Agreement” means the Seventh Amended and Restated Credit Agreement dated as of November 10, 2016 among the Company, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders parties thereto from time to time, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, renewals, restatements, refundings or refinancings thereof with other revolving credit facilities with banks or other institutional lenders that replace, refund or refinance any part of the loans or commitments thereunder, including any such replacement, refunding or refinancing revolving credit facility that increases the amount borrowable thereunder or alters the maturity thereof.

“Significant Subsidiary” means any Restricted Subsidiary that would be a “Significant Subsidiary” of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC, as in effect on the Issue Date.

“Stated Maturity” means, with respect to any security, the date specified in such security as the fixed date on which the payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

“Subordinated Obligation” means any Indebtedness of either Issuer (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinated in right of payment to the Notes pursuant to a written agreement.

“Subsidiary” of any Person means (a) any corporation, association or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the Voting Stock or (b) any partnership, joint venture, limited liability company or similar entity of which more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, is, in the case of clauses (a) and (b), at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or (3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary (other than in this definition) refers to a Subsidiary of the Company.

“Subsidiary Guarantee” means, individually, any guarantee of payment of the Notes by a Subsidiary Guarantor pursuant to the terms of the Indenture and any supplemental indenture thereto, and, collectively, all such guarantees.

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“Subsidiary Guarantor” means any Subsidiary of the Company that is a guarantor of the Notes, including any Person that is required after the Issue Date to guarantee the Notes pursuant to the “Future Subsidiary Guarantors” covenant, in each case until a successor replaces such Person pursuant to the applicable provisions of the Indenture and, thereafter, means such successor;provided,however, that the Co-Issuer shall not be a Subsidiary Guarantor.

“Tax Amount” means, for any period, the combined federal, state and local income taxes, including estimated taxes, that would be payable by the Company if it were a Texas corporation filing separate tax returns with respect to its Taxable Income for such period;provided that in determining the Tax Amount, the effect thereon of any net operating loss carryforwards or other carryforwards or tax attributes, such as alternative minimum tax carryforwards, that would have arisen if the Company were a Texas corporation shall be taken into account;provided,further, that, if there is an adjustment in the amount of the Taxable Income for any period, an appropriate positive or negative adjustment shall be made in the Tax Amount, and if the Tax Amount is negative, then the Tax Amount for succeeding periods shall be reduced to take into account such negative amount until such negative amount is reduced to zero. Notwithstanding anything to the contrary, Tax Amount shall not include taxes resulting from the Company’s reorganization as, or change in the status to, a corporation for tax purposes.

“Taxable Income” means, for any period, the taxable income or loss of the Company for such period for U.S. federal income tax purposes.

“Unrestricted Subsidiary” means:

(1) any Subsidiary of the Company (other than the Co-Issuer) that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and

(2) any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if:

(1) such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary;

(2) all the Indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation, and will at all times thereafter, consist of Non-Recourse Debt;

(3) on the date of such designation, such designation and the Investment of the Company or a Restricted Subsidiary in such Subsidiary complies with “— Certain Covenants — Limitation on Restricted Payments”;

(4) such Subsidiary is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Capital Stock of such Person or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results;

(5) such Subsidiary, either alone or in the aggregate with all other Unrestricted Subsidiaries, does not operate, directly or indirectly, all or substantially all of the business of the Company and its Subsidiaries; and

(6) such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary with terms less favorable to the Company or such Restricted Subsidiary than those that might have been obtained from Persons who are not Affiliates of the Company.

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Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers’ Certificate certifying that such designation complies with the preceding conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary;provided that immediately after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and the Company could Incur at least $1.00 of additional Indebtedness under the first paragraph of the covenant described under “— Certain Covenants — Limitation on Indebtedness and Preferred Stock” on a pro forma basis taking into account such designation.

“U.S. Government Obligations” means securities that are (a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or (b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation of the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depositary receipt;provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depositary receipt.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of a Person means all classes of Capital Stock of such Person then outstanding and normally entitled to vote in the election of members of such Person’s Board of Directors.

“Wholly Owned Subsidiary” means a Restricted Subsidiary, all of the Capital Stock of which (other than directors’ qualifying shares or other shares required by applicable law to be held by a Person other than the Company or another Wholly Owned Subsidiary) is owned by the Company or another Wholly Owned Subsidiary.

189

PLAN OF DISTRIBUTION

Based on interpretations by the staff of the SEC in no-action letters issued to third parties, we believe that you may transfer new notes issued under the exchange offer in exchange for the old notes if:

• any new notes to be received by you will be acquired in the ordinary course of your business; and

• you have no arrangement or understanding with any person or entity to participate in the distribution (within the meaning of the Securities Act) of the new notes in violation of the provisions of the Securities Act.

You may not participate in the exchange offer unless:

• you are not an “affiliate,” as defined in Rule 405 under the Securities Act, of us or our subsidiary guarantors; and

• if you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired as a result of market-making or other trading activities, then you agree to deliver this prospectus (or, to the extent permitted by law, make this prospectus available to purchasers) in connection with any resale of the new notes.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver this prospectus in connection with any resale of such new notes. To date, the staff of the SEC has taken the position that broker-dealers may fulfill their prospectus delivery requirements with respect to transactions involving an exchange of securities such as this exchange offer, other than a resale of an unsold allotment from the original sale of the old notes, with this prospectus. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received for their own account in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period ending on November 27, 2017, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until such date, all dealers effecting transactions in new notes may be required to deliver this prospectus.

We are entitled under the registration rights agreements to suspend the use of this prospectus by broker-dealers if, in our good faith determination, the continued effectiveness of the registration statement and the use of this prospectus would require the public disclosure of material non-public information.

If we suspend the use of this prospectus, the period referred to above during which we have agreed to make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with certain resales, will be extended by a number of days equal to the period of the suspension and we and the Guarantor will pay additional interest, if required, pursuant to the registration rights agreements.

If you wish to new notes for your old notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer — Purpose and Effect of the Exchange Offer” and “Exchange Offer — Your Representations to Us” in this prospectus. As indicated in the letter of transmittal, you will be deemed to have made these representations by tendering your old notes in the exchange offer. In addition, if you are a broker-dealer who receives new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge, in the same manner, that you will deliver this prospectus in connection with any resale by you of such new notes.

We will not receive any proceeds from any sale of new notes by broker-dealers. New Notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions:

• in the over-the-counter market;

190

• in negotiated transactions;

• through the writing of options on the new notes; or

• a combination of such methods of resale; at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an “underwriter” within the meaning of the Securities Act. Each letter of transmittal states that by acknowledging that it will deliver and by delivering this prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. For a period of 180 days after the consummation of the exchange offer, the Company will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents as provided in the Letter of Transmittal. The Company has agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the Holders of the old notes) other than commissions or concessions of any brokers or dealers and will indemnify the Holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of certain material U.S. federal income tax considerations relating to the exchange of old notes for new notes pursuant to the exchange offer. As used in this summary, the term “notes” means the old notes and the new notes. This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations, revenue rulings, administrative interpretations and judicial decisions now in effect, all of which are subject to change possibly with retroactive effect. Except as specifically set forth herein, this summary deals only with old notes held as capital assets within the meaning of Section 1221 of the Code. This summary does not purport to address all federal income tax considerations that may be relevant to holders in light of their particular circumstances or to holders subject to special tax rules, such as banks, insurance companies or other financial institutions, dealers in securities or foreign currencies, tax-exempt investors, or persons holding the old notes as part of a hedging transaction, straddle, conversion transaction, or other integrated transaction.

We have not sought any ruling from the Internal Revenue Service (the “IRS”) or an opinion of counsel with respect to the statements made and the conclusions reached in the following summary. As such, there can be no assurance that the IRS will agree with such statements and conclusions.

All persons that exchange old notes for new notes in the exchange offer are urged to consult their own tax advisors with regard to the application of the U.S. federal income tax laws to their particular situations as well as any tax consequences arising under the laws of any state, local or foreign jurisdiction.

Consequences of the Exchange Offer

The exchange of the old notes for the new notes in the exchange offer should not be treated as an “exchange” for U.S. federal income tax purposes, because the new notes should not be considered to differ materially in kind or extent from the old notes. Accordingly, the exchange of old notes for new notes should not be a taxable event for U.S. federal income tax purposes. Moreover, the new notes should have the same tax attributes as the old notes exchanged therefor and the same tax consequences to holders as the old notes.

191

LEGAL MATTERS

The validity of the securities offered hereby will be passed upon for us by Haynes and Boone, LLP, Houston, Texas.

EXPERTS

Independent Registered Public Accounting Firm

The consolidated financial statements of Alta Mesa Holdings, LP as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016 included in this prospectus have been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report appearing herein.

Independent Petroleum Engineers

Estimates of proved reserves included in this prospectus as of December 31, 2016 using SEC guidelines were prepared or derived from estimates prepared by our Corporate Planning and Reserves department and were audited in a reserves audit by Ryder Scott, independent petroleum consultants. In addition, reserves estimates at December 31, 2016 using NYMEX pricing and Society of Petroleum Engineers-Petroleum Resource Management System guidelines were prepared or derived from estimates prepared by our Corporate Planning and Reserves department and were audited in a reserves audit by Ryder Scott, independent petroleum consultants. These reserves estimates are included in this prospectus in reliance on the authority of such firm as experts in these matters. Ryder Scott did not audit the PV-10s prepared by our Corporate Planning and Reserves department.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The terms and abbreviations defined in this section are used throughout this prospectus:

“3-D seismic”. (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional seismic data.

“Bbl”. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Bcf”. One billion cubic feet of natural gas.

“Bcfe”. One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six thousand cubic feet of natural gas.

“Basin”. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“BOE”. One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is

192

commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six Mcf of natural gas.

“Btu or British Thermal Unit”. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Completion”. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A”. Depreciation, depletion and amortization.

“Developed acreage”. The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed oil and natural gas reserves”. Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the related equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Development well”. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole”. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Dry hole costs”. Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.

“Enhanced recovery”. The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

“Exploratory well”. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

“Field”. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation”. A layer of rock which has distinct characteristics that differs from nearby rock.

“Fracing, fracture stimulation technology, hydraulic fracturing”. The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“Gross acres or gross wells”. The total acres or wells, as the case may be, in which a working interest is owned.

193

“Horizontal drilling”. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Infill wells”. Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

“Lease operating expenses”. The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

“MBbl”. One thousand barrels of crude oil, condensate or natural gas liquids.

“Mcf”. One thousand cubic feet of natural gas.

“Mcfe”. One thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six Mcf of natural gas.

“Mcfe/d”. Mcfe per day.

“MMBtu”. One million British thermal units.

“MMcf”. One million cubic feet of natural gas.

“MMcfe”. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“MMcfe/d”. MMcfe per day.

“MMBbl”. One million barrels of crude oil, condensate or natural gas liquids.

“NGLs” or “natural gas liquids.” Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX”. The New York Mercantile Exchange.

“Net Acres”. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Non-operated working interests”. The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.

“Pay”. A reservoir or portion of a reservoir that contains economically producible hydrocarbons. The overall interval in which pay sections occur is the gross pay; the smaller portions of the gross pay that meet local criteria for pay (such as a minimum porosity, permeability and hydrocarbon saturation) are net pay.

“Productive well”. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

194

“Prospect”. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

“PDNP”. Proved developed non-producing reserves.

“PDP”. Proved developed producing reserves.

“Proved reserves”. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped reserves (“PUD”)”. Proved undeveloped oil and natural gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled acreage is considered proved where adjacent undrilled portions of the reservoir can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In addition, reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty and these locations must have a development plan that calls for development within five years, unless specific circumstances justify a longer time. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Finally, reserves which can be produced through the application of improved recovery techniques, including injection, may be included upon successful testing of a pilot project in a representative area or analogous reservoir or if other evidence using reliable technology establishes the reasonable certainty of the engineering analysis. Such improved recovery techniques must be approved for development by all necessary parties and entities including governmental entities.

“PV-10”. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Our PV-10 is the same as our standardized measure for the periods presented in this prospectus.

“Recompletion”. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserve life index”. A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years.

195

“Reservoir”. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing”. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure”. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission, without giving effect to non — property related expenses such as certain general and administrative expenses, debt service or depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes. Our standardized measure is the same as our PV-10 for the periods presented in this prospectus.

“Undeveloped acreage”. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“Unit”. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Waterflood”. The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.

“Wellbore”. The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

“Working interest”. The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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INDEX TO FINANCIAL STATEMENTS

Below is an index to the financial statements and notes contained in Financial Statements and Supplementary Data.

	Page
Audited Financial Statements
Report of Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheets as of December 31, 2016 and 2015		F-2
Consolidated Statements of Operations for each of the Three Years in the Period Ended December 31, 2016, 2015 and 2014		F-3
Consolidated Statements of Changes in Partners’ Capital (Deficit) for each of the Three Years in the Period Ended December 31, 2016, 2015 and 2014		F-4
Consolidated Statements of Cash Flows for each of the Three Years in the Period Ended December 31, 2016, 2015 and 2014		F-5
Notes to Consolidated Financial Statements		F-6
Unaudited Financial Statements
Condensed Consolidated Balance Sheets as of June  30, 2017 and December 31, 2016		F-35
Condensed Consolidated Statements of Operations for the Three Months Ended June 30, 2017 and 2016 and for the Six Months Ended June 30, 2017 and 2016		F-36
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2017 and 2016		F-37
Notes to Condensed Consolidated Financial Statements		F-38

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Alta Mesa Holdings, LP and Subsidiaries

Houston, Texas

We have audited the accompanying consolidated balance sheets of Alta Mesa Holdings, LP and Subsidiaries (collectively, the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, partners’ capital (deficit) and cash flows for each of the three years in the period ended December 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Alta Mesa Holdings, LP and Subsidiaries at December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/S/ BDO USA, LLP

Houston, Texas

March 30, 2017

F-1

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31, 2016		December 31, 2015
	(in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	7,185	$	8,869
Short-term restricted cash		433		105
Accounts receivable, net of allowance of $889 and $1,402, respectively		37,611		27,111
Other receivables		8,061		18,526
Receivables due from affiliate		8,883		1,053
Prepaid expenses and other current assets		3,986		4,774
Derivative financial instruments		83		62,631
Total current assets		66,242		123,069
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		712,162		525,942
Other property and equipment, net		9,731		11,097
Total property and equipment, net		721,893		537,039
OTHER ASSETS
Investment in LLC — cost		9,000		9,000
Deferred financing costs, net		3,029		1,199
Notes receivable due from affiliate		9,987		9,213
Deposits and other long-term assets		2,977		1,370
Derivative financial instruments		723		41,635
Total other assets		25,716		62,417
TOTAL ASSETS	$	813,851	$	722,525
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	84,234	$	82,621
Advances from non-operators		4,058		1,381
Advances from related party		42,528		—
Asset retirement obligations		376		729
Derivative financial instruments		21,207		—
Total current liabilities		152,403		84,731
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		61,128		60,491
Long-term debt, net		529,905		717,775
Notes payable to founder		26,957		25,748
Derivative financial instruments		4,482		—
Other long-term liabilities		6,870		10,829
Total long-term liabilities		629,342		814,843
TOTAL LIABILITIES		781,745		899,574
Commitments and Contingencies (Note 12)
PARTNERS’ CAPITAL (DEFICIT)		32,106		(177,049	)
TOTAL LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)	$	813,851	$	722,525

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

F-2

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
OPERATING REVENUES AND OTHER
Oil	$	163,677		$	199,799		$	347,842
Natural gas		30,953			30,621			65,002
Natural gas liquids		15,663			10,864			18,281
Other revenues		415			682			1,003
Total operating revenues		210,708			241,966			432,128
Gain on sale of assets		3,542			67,781			87,520
Gain (loss) on derivative contracts		(40,460	)		124,141			96,559
Total operating revenues and other		173,790			433,888			616,207
OPERATING EXPENSES
Lease and plant operating expense		56,893			67,706			64,686
Marketing and transportation expense		13,326			4,030			9,134
Production and ad valorem taxes		10,750			15,131			28,214
Workover expense		4,714			6,511			8,961
Exploration expense		24,777			42,718			61,912
Depreciation, depletion, and amortization expense		92,901			143,969			141,804
Impairment expense		16,306			176,774			74,927
Accretion expense		2,174			2,076			2,198
General and administrative expense		41,758			44,454			69,198
Total operating expenses		263,599			503,369			461,034
INCOME (LOSS) FROM OPERATIONS		(89,809	)		(69,481	)		155,173
OTHER INCOME (EXPENSE)
Interest expense		(60,884	)		(62,473	)		(55,812	)
Interest income		894			723			15
Loss on extinguishment of debt		(18,151	)		—			—
Total other income (expense)		(78,141	)		(61,750	)		(55,797	)
INCOME (LOSS) BEFORE STATE INCOME TAXES		(167,950	)		(131,231	)		99,376
Provision for (benefit from) state income taxes		(29	)		562			176
NET INCOME (LOSS)	$	(167,921	)	$	(131,793	)	$	99,200

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

F-3

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)

YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014

(in thousands)

BALANCE, DECEMBER 31, 2013	$	(160,107	)
DISTRIBUTIONS		(539	)
NET INCOME		99,200
BALANCE, DECEMBER 31, 2014		(61,446	)
CONTRIBUTIONS		20,000
DISTRIBUTIONS		(3,810	)
NET LOSS		(131,793	)
BALANCE, DECEMBER 31, 2015		(177,049	)
CONTRIBUTIONS		377,076
NET LOSS		(167,921	)
BALANCE, DECEMBER 31, 2016	$	32,106

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

F-4

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(167,921	)	$	(131,793	)	$	99,200
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization expense		92,901			143,969			141,804
Impairment expense		16,306			176,774			74,927
Accretion expense		2,174			2,076			2,198
Amortization of deferred financing costs		3,905			3,392			2,885
Amortization of debt discount		468			510			510
Dry hole expense		419			22,708			30,294
Expired leases		11,158			6,526			4,319
(Gain) loss on derivative contracts		40,460			(124,141	)		(96,559	)
Settlements of derivative contracts		88,689			106,949			9,493
Loss on extinguishment of debt		18,151			—			—
Interest converted into debt		1,209			1,208			1,209
Interest on notes receivable due from affiliate		(774	)		(713	)		—
Gain on sale of assets		(3,542	)		(67,781	)		(87,520	)
Changes in assets and liabilities:
Restricted cash unrelated to property divestiture		(328	)		—			(106	)
Accounts receivable		(10,500	)		16,470			(95	)
Other receivables		10,465			(10,288	)		(5,686	)
Receivables due from affiliate		45			(1,725	)		—
Prepaid expenses and other non-current assets		(819	)		(2,269	)		7,251
Advances from related party		42,528			—			—
Settlement of asset retirement obligation		(2,125	)		(1,794	)		(3,942	)
Accounts payable, accrued liabilities, and other liabilities		(11,493	)		3,900			4,702
NET CASH PROVIDED BY OPERATING ACTIVITIES		131,376			143,978			184,884
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(214,061	)		(223,604	)		(366,090	)
Acquisitions		(11,527	)		(48,202	)		(18,110	)
Proceeds from sale of property		1,290			141,404			177,476
Proceeds from property divestiture classified as restricted cash		—			—			41,590
Investment in restricted cash related to property divestitures		—			24,587			(24,587	)
NET CASH USED IN INVESTING ACTIVITIES		(224,298	)		(105,815	)		(189,721	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		222,557			252,500			169,500
Repayments of long-term debt		(333,935	)		(295,020	)		(169,270	)
Repayments of senior secured term loan		(127,708	)		—			—
Repurchase of senior notes due 2018		(459,391	)		—			—
Proceeds from issuance of senior notes due 2024		500,000			—			—
Additions to deferred financing costs		(13,747	)		(4,313	)		(42	)
Capital distributions		—			(3,810	)		(539	)
Capital contributions		303,462			20,000			—
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		91,238			(30,643	)		(351	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,684	)		7,520			(5,188	)
CASH AND CASH EQUIVALENTS, beginning of period		8,869			1,349			6,537
CASH AND CASH EQUIVALENTS, end of period	$	7,185		$	8,869		$	1,349

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

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014

NOTE 1 — NATURE OF OPERATIONS

Nature of Operations. Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is an independent exploration and production company engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our principal area of operation is 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. Our operations also include other oil and natural gas interests in Texas, Louisiana and Florida.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We use accounting policies which reflect industry practices and conform to accounting principles generally accepted in the U.S. (“GAAP”). Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ capital (deficit).

Principles of Consolidation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

Use of Estimates. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquired properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.

Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.

Restricted Cash. The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2016, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute or unclaimed property for pooling orders in Oklahoma.

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Accounts Receivable. Our receivables arise primarily from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts.

Accounts receivable consisted of the following:

	As of December 31,
	2016			2015
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	25,149		$	17,865
Joint interest billings		13,344			10,162
Other		7			486
Allowance for doubtful accounts		(889	)		(1,402	)
Total accounts receivable, net	$	37,611		$	27,111

See Note 13 for further information regarding marketing arrangements with our primary marketing representative, ARM Energy Management, LLC (“AEM”) and significant concentrations. Accounts receivable from AEM arising from sales marketed on our behalf were $17.7 million and $12.6 million as of December 31, 2016 and 2015, respectively.

Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated.

Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statements of operations. Deferred financing costs related to the Company’s senior secured revolving credit facility are included in deferred financing costs, net and the deferred financing costs related to the senior unsecured notes are included in long-term debt, net, on the Company’s consolidated balance sheets.

Property and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, delay rentals, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, or “suspended” on the balance sheet pending determination of whether the well has discovered proved commercial reserves. See Note 5

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for further details. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly.

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Our evaluation of the Company’s proved properties resulted in impairment expense of $16.1 million, $172.0 million and $72.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, primarily due to lower forecasted commodity prices.

Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statements of operations. For the years ended December 31, 2016, 2015 and 2014, impairment expense of unproved properties was $0.2 million, $4.8 million, and $2.0 million, respectively.

Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2016, 2015 and 2014, respectively, the Company did not record any impairment expense related to other long-lived assets.

Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is

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the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

DD&A expense for the years ended December 31, 2016, 2015 and 2014 related to oil and natural gas properties was $90.0 million, $140.9 million, and $139.0 million, respectively.

Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2016, 2015 and 2014 was $2.9 million, $3.0 million, and $2.8 million respectively.

Investments. The Company’s investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method and we have recorded $9.0 million of Investment in LLC on the consolidated balance sheets as of December 31, 2016 and 2015. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations.

Alta Mesa is a part owner of AEM with an ownership interest of less than 10%. AEM markets our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. For additional information on AEM, see Note 13.

Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset. The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. Accretion expense is recognized as the discounted liability is accreted to its expected settlement value. Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 6 for information on fair value).

Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in gain (loss) on derivative contracts in the consolidated statement of operations. Gains or losses from the settlement of matured derivatives contracts are also included in gain (loss) on derivatives contracts in the consolidated statement of operations. Cash flows from settlements of derivative contracts are classified as operating cash flows.

Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.

Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to limited partners as a result of differences between the tax bases and financial reporting bases of assets and

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liabilities and the taxable income allocation requirements under the partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $101.5 million at December 31, 2016.

The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for (benefit from) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.

We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.

We have considered our exposure under the standard at both the federal and state tax levels. We have not recorded any liabilities for uncertain tax positions as of December 31, 2016 and 2015. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2016, 2015 or 2014.

The Company’s tax returns for the years ended December 31, 2013 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances.

Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The fair value estimate of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs. In December 2016, we issued $500 million in aggregate principal amount of our 7.875% senior unsecured notes due 2024 (the “2024 Notes”). We have estimated the fair value of the 2024 Notes payable at $520 million on December 31, 2016. Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments and details related to the 2024 Notes, refer to Note 6 — Fair Value Disclosures and Note 10 — Long-Term Debt, Net.

Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers. Its

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objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14,Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 deferred the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company has not yet selected a transition method and is currently assessing the impact on the consolidated financial statements. The Company is continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements.

In January 2016, the FASB issued ASU No. 2016-01,Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company does not plan to adopt the standard early. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment. The Company continues to evaluate the impacts of the amendments to our financial statements and accounting practices for leases.

In August 2016, the FASB issued ASU No. 2016-15,Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.

In October 2016, the FASB issued ASU No. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control. This guidance provides an amendment to the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. We have adopted this ASU and there was no current impact to our consolidated financial statements.

In November 2016, the FASB issued ASU 2016-18,Statement of Cash Flows: Restricted Cash,which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and

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interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.

In January 2017, the FASB issued ASU No. 2017-01,Clarifying the Definition of a Business,which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

NOTE 3 — SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:

	Year Ended December 31,
	2016		2015			2014
	(in thousands)
Supplemental cash flow information:
Cash paid for interest	$	74,694	$	56,579		$	51,219
Cash paid (received) for state income taxes, net of refunds		285		751			(123	)
Non-cash investing and financing activities:
Change in asset retirement obligations		2,719		487			2,643
Asset retirement obligations assumed, purchased properties		—		—			3,002
Change in accruals or liabilities for capital expenditures		12,375		(34,160	)		23,858
Divestiture of oil and gas properties		—		—			(34,000	)
Acquisition of property and land		—		2,473			—
Contribution of interests in oil and gas properties		65,740		—			—
Contribution receivable		7,875		—			—

NOTE 4 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES

2016 Activity

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

On December 31, 2016, our Class B partner, High Mesa, Inc. (“High Mesa”) purchased from BCE and contributed interests in 24 producing wells (the “Contributed Wells”) drilled under the joint development agreement to us. The Company accounted for the Contributed Wells as a business combination and therefore, recorded the contribution at their estimated contribution date fair value. High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected subsequent to year end.

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The unaudited pro forma combined financial results, had the contribution of the Contributed Wells occurred at January 1, 2016, are provided below. The Contributed Wells came online during 2016, therefore, no unaudited pro forma combined results are shown for the beginning of the comparable prior year.

	Total operating revenues and other		Net loss
	(in thousands)
	(unaudited)
Pro forma results for the combined entity for the year ended December 31, 2016	$	199,982	$	(157,230	)

This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the contribution had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

2015 Activity

Alta Mesa Eagle, LLC Divestiture

On September 30, 2015, we closed the sale of all of the membership interests (the “Membership Interests”) in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary, to EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement entered into by us, AME and EnerVest on September 16, 2015 (the “Eagle Ford divestiture”). AME owned our remaining non-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas. In connection with the Eagle Ford divestiture, we disposed of all of our remaining interests in this area. The effective date of the transaction (the “Effective Date”) is July 1, 2015.

The aggregate cash purchase price for the Membership Interests was $125.0 million subject to certain adjustments, consisting of $118.0 million (the “Base Purchase Price”), and additional contingent payments of approximately $7.0 million in the aggregate, payable to us by EnerVest by the 15th of each calendar month in which certain amounts owed to AME prior to the Effective Date have been received. The purchase and sale agreement provides for customary purchase price adjustments to the Base Purchase Price based on the Effective Date. As of December 31 2015, we received net proceeds of $122.0 million including $4.0 million of customary purchase price adjustments, and recognized a gain of approximately $67.6 million. Cash received was utilized to pay down borrowings under our senior secured revolving credit facility. As of the Effective Date, the estimated net proved reserves sold were approximately 7.8 MMBOE.

The sale of AME contributed approximately $68.9 million in pre-tax profit for the year ended December 31, 2015, which includes the $67.6 million gain on sale of asset and $118.5 million in pre-tax profit for the year ended December 31, 2014, which includes a $72.5 million gain on sale of assets for the first portion of the Eagleville divestiture, owned by AME, as described below.

Kingfisher Leasehold Acquisition

On July 6, 2015, we acquired approximately 19,000 net acres of primarily undeveloped leasehold interest in Kingfisher County, Oklahoma. The consideration for the purchase was approximately $46.2 million and was subject to customary purchase price adjustments. The effective date of the acquisition was April 1, 2015. The purchase was funded with borrowings under our senior secured revolving credit facility.

2014 Activity

Eagleville Divestiture

On March 25, 2014, we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville Divestiture”). The

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properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014. We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017. Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014. The initial cash purchase price was $173.0 million, subsequently adjusted to approximately $171.0 million for settlement adjustments. The purchase and sale agreement provides for customary adjustments to the purchase price for revenues and expenses incurred after the effective date. As of December 31, 2014, estimated net proved reserves associated with the sold portion of these properties were approximately 7.5 MMBOE. We recorded a gain on sale from the Eagleville Divestiture of $72.5 million during 2014, based on an allocation of basis between the properties sold and properties retained.

The sold portion of Eagleville field contributed approximately $11.1 million in pre-tax income in the first quarter of 2014, prior to its sale.

Hilltop Divestiture

On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary settlement adjustments. We recorded a gain on the sale of $15.9 million. As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE.

The Hilltop interests contributed approximately $7.7 million in net pre-tax income during the year ended December 31, 2014.

NOTE 5 — PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	December 31, 2016			December 31, 2015
	(in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	116,311		$	127,551
Accumulated impairment		(65	)		(2,684	)
Unproved properties, net		116,246			124,867
Proved oil and natural gas properties		1,611,249			1,345,482
Accumulated depreciation, depletion, amortization and impairment		(1,015,333	)		(944,407	)
Proved oil and natural gas properties, net		595,916			401,075
TOTAL OIL AND NATURAL GAS PROPERTIES, net		712,162			525,942
OTHER PROPERTY AND EQUIPMENT
Land		4,730			3,868
Office furniture and equipment, vehicles		19,446			18,794
Accumulated depreciation		(14,445	)		(11,565	)
OTHER PROPERTY AND EQUIPMENT, net		9,731			11,097
TOTAL PROPERTY AND EQUIPMENT, net	$	721,893		$	537,039

F-14

Capitalized Exploratory Well Costs

The following table reflects the net changes in capitalized exploratory well costs during 2016, 2015, and 2014. The table does not include amounts that were capitalized and either subsequently expensed within the same year.

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Balance, beginning of year	$	6,006		$	13,301		$	20,317
Additions to capitalized well costs pending determination of proved reserves		3,736			4,364			15,870
Reclassifications to proved properties		(7,484	)		(8,583	)		(6,593	)
Capitalized exploratory well costs charged to expense		(169	)		(3,076	)		(16,293	)
Balance, end of year	$	2,089		$	6,006		$	13,301

The ending balance in capitalized exploratory well costs includes the costs of five wells primarily in three prospects that were capitalized for periods greater than one year at December 31, 2016. We have capitalized $0.7 million and $3.0 million of exploratory well costs covering periods greater than one year at December 31, 2016 and 2015. We continue to assess and evaluate these projects.

NOTE 6 — FAIR VALUE DISCLOSURES

The Company follows ASC 820, “Fair Value Measurements and Disclosure.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.

We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (“NYMEX”) and other exchanges for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil, natural gas, and natural gas liquids derivative contracts as Level 2.

Our senior notes are carried at historical cost. We estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting date, a Level 1 classification.

Oil and natural gas properties are subject to impairment testing and potential impairment write down as described in Note 2. Oil and natural gas properties with a carrying amount of $33.9 million were written down to their fair value of $17.6 million, resulting in an impairment charge of $16.3 million for the year ended December 31, 2016. Oil and natural gas properties with a carrying amount of $499.6 million were written down to their fair value of $322.8 million, resulting in an impairment charge of $176.8 million for the year ended December 31, 2015. Oil and natural gas properties with a carrying amount of $148.4 million were written down to their fair value of $73.5 million, resulting in an impairment charge of $74.9 million for the year ended December 31, 2014. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

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New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded a total of $1.4 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2016. We recorded a total of $2.0 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2015.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2016 and 2015, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:

	Level 1		Level 2		Level 3		Total
	(in thousands)
At December 31, 2016:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	15,773		—	$	15,773
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	40,656		—	$	40,656
At December 31, 2015:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	166,106		—	$	166,106
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	61,840		—	$	61,840

The amounts above are presented on a gross basis. Presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place.

NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas, and natural gas liquids. From time to time we also utilize financial basis swap contracts, which address the price differential between the benchmark index price and the specific locational index pricing referenced in certain of our crude oil, natural gas, and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our senior secured revolving credit facility described in Note 10 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading purposes.

From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.

We have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statements of operations at each reporting date.

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability)

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account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account.

The following table summarizes the fair value (see Note 6 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:

	December 31, 2016
Balance sheet location	Gross Fair Value of Assets		Gross amounts offset against assets in the Balance Sheet			Net Fair Value of Assets presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	3,296	$	(3,213	)	$	83
Derivative financial instruments, long-term assets		12,477		(11,754	)		723
Total	$	15,773	$	(14,967	)	$	806

Balance sheet location	Gross Fair Value of Liabilities		Gross amounts offset against liabilities in the Balance Sheet			Net Fair Value of Liabilities presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	24,420	$	(3,213	)	$	21,207
Derivative financial instruments, long-term liabilities		16,236		(11,754	)		4,482
Total	$	40,656	$	(14,967	)	$	25,689

	December 31, 2015
Balance sheet location	Gross Fair Value of Assets		Gross amounts offset against assets in the Balance Sheet			Net Fair Value of Assets presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	86,000	$	(23,369	)	$	62,631
Derivative financial instruments, long-term assets		80,106		(38,471	)		41,635
Total	$	166,106	$	(61,840	)	$	104,266

Balance sheet location	Gross Fair Value of Liabilities		Gross amounts offset against liabilities in the Balance Sheet			Net Fair Value of Liabilities presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	23,369	$	(23,369	)	$	—
Derivative financial instruments, long-term liabilities		38,471		(38,471	)		—
Total	$	61,840	$	(61,840	)	$	—

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The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:

Derivatives not designated as hedging instruments under ASC 815	Year Ended December 31,
	2016			2015		2014
	(in thousands)
Gain (loss) on derivative contracts
Oil commodity contracts	$	(36,572	)	$	113,295	$	82,510
Natural gas commodity contracts		(2,410	)		10,712		14,049
Natural gas liquids commodity contracts		(1,478	)		134		—
Total gain (loss) on derivative contracts	$	(40,460	)	$	124,141	$	96,559

Other receivables include $7.8 million and $17.5 million of derivative positions settled, but not yet received as of December 31, 2016 and 2015, respectively.

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the senior secured revolving credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

We had the following open derivative contracts for crude oil at December 31, 2016:

OIL DERIVATIVE CONTRACTS

	Volume in Bbls		Weighted Average		Range
Period and Type of Contract					High		Low
2017
Price Swap Contracts		1,460,000	$	46.93	$	48.43	$	45.00
Collar Contracts
Short Call Options		2,075,000		60.46		85.00		54.40
Long Put Options		1,527,500		48.39		50.00		47.00
Short Put Options		1,527,500		37.19		40.00		35.00
2018
Collar Contracts
Short Call Options		1,825,000		60.64		60.90		60.50
Long Put Options		1,825,000		50.00		50.00		50.00
Short Put Options		1,825,000		40.00		40.00		40.00
2019
Collar Contracts
Short Call Options		1,241,000		62.90		63.00		62.75
Long Put Options		1,241,000		50.00		50.00		50.00
Short Put Options		1,241,000		37.50		37.50		37.50

F-18

We had the following open derivative contracts for natural gas at December 31, 2016:

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in MMBtu		Weighted Average		Range
Period and Type of Contract					High		Low
2017
Price Swap Contracts		450,000	$	2.47	$	2.47	$	2.47
Collar Contracts
Short Call Options		10,220,000		3.68		3.94		3.56
Long Put Options		9,320,000		3.09		3.30		3.00
Long Call Options		1,125,000		3.44		3.56		3.25
Short Put Options		9,320,000		2.56		2.70		2.50
2018
Collar Contracts
Short Call Options		6,132,000		5.34		5.53		4.00
Long Put Options		5,475,000		4.50		4.50		4.50
Short Put Options		5,475,000		4.00		4.00		4.00

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

We had the following open derivative contracts for natural gas liquids at December 31, 2016:

NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS

	Volume in Gal		Weighted Average		Range
Period and Type of Contract					High		Low
2017
Price Swap Contracts		5,371,800	$	0.46	$	0.47	$	0.45

We had the following open financial basis swap contracts for natural gas at December 31, 2016:

BASIS SWAP DERIVATIVE CONTRACTS

Volume in MMBtu		Reference Price 1 (1)	Reference Price 2 (1)	Period	Weighted Average Spread ($ per MMBtu)
	12,470,000	NYMEX Henry Hub	Tex/OKL Panhandle Eastern Pipeline	Jan ’17 —Dec ’17		$(0.24)
	5,910,000	NYMEX Henry Hub	Tex/OKL Panhandle Eastern Pipeline	Jan ’18 —Oct ’18		(0.27)

(1) Represents short swaps that fix the basis differentials between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) INSIDE FERC (“IFERC”) and NYMEX Henry Hub.

F-19

NOTE 8 — ASSET RETIREMENT OBLIGATIONS

A summary of the changes in our asset retirement obligations is included in the table below:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Balance, beginning of year	$	61,220		$	62,872		$	56,023
Liabilities incurred		1,438			1,988			1,129
Liabilities assumed with acquired producing properties		—			—			3,002
Liabilities settled		(2,125	)		(1,794	)		(3,942	)
Liabilities transferred in sales of properties		(3,036	)		(3,149	)		(1,886	)
Revisions to estimates		1,833			(773	)		6,348
Accretion expense		2,174			2,076			2,198
Balance, end of year		61,504			61,220			62,872
Less: Current portion		376			729			1,136
Long-term portion	$	61,128		$	60,491		$	61,736

The total revisions included $1.3 million related to additions to property, plant and equipment for the year ended December 31, 2016. Total revisions included $1.5 million related to reductions and $2.9 million related to additions to property, plant and equipment for the years ended December 31, 2015 and 2014, respectively.

NOTE 9 — RELATED PARTY TRANSACTIONS

We have notes payable to our founder which bear interest at 10% with a balance of $27.0 million and $25.7 million at December 31, 2016 and 2015, respectively. See Note 10 for further information.

Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received no capital distributions during the years ended December 31, 2016 and 2015 and received $516,500 of capital distributions from us during the year ended December 31, 2014, respectively.

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2016, 2015 and 2014 were approximately $146,000, $133,000 and $150,000. The contract may be terminated by either party without penalty upon 30 days’ notice.

David McClure, our Vice President of Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $425,000, $275,000 and $450,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.

David Pepper, one of our Landmen, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $180,000, $146,000 and $260,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.

On January 13, 2016, our wholly-owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “joint development agreement”), with BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City Energy Management LLC (“Bayou City”), to fund a

F-20

portion of our drilling operations and to allow us to accelerate development of our STACK acreage. As described in Note 16, William W. McMullen and Mark Stoner, partners at Bayou City, were appointed to the board of managers of Alta Mesa Holdings GP, LLC, our general partner during the third quarter of 2016. The drilling program initially called for the development of forty identified well locations, which developed in two tranches of twenty wells each. The parties subsequently agreed to add a third and fourth tranche of investment that will allow for the drilling of an additional forty wells. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us. See Notes 4 and 16 for further details. In connection with the acquisition of the Contributed Wells, the joint development agreement was amended to exclude the Contributed Wells from the drilling program. The drilling program will fund the development of 80 additional wells in four tranches of 20 wells each. As of December 31, 2016, 20 additional joint wells have been drilled or spudded leaving 60 wells to be drilled under the joint development agreement.

Under the joint development agreement, as amended on December 31, 2016, BCE has committed to fund 100% of our working interest share up to a maximum of an 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 the aggregate limit of $64 million in any tranche. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within in 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. The approximate dollar value of the amount involved in this transaction or Messrs. McMullen or Stoner’s interests in the transaction depends on a number of factors outside their control and is not known at this time. As of December 31, 2016, we recorded $42.5 million in advances from related party on our consolidated balance sheets, which represents net advances from BCE for their working interest share of the drilling and development cost as part of the joint development agreement.

During the year ended December 31, 2016, High Mesa contributed $311.3 million to us, of which $7.9 million is included in receivables due from affiliate at December 31, 2016 and the amount was collected subsequent to year-end. During the year ended December 31, 2015, High Mesa contributed $20 million to us. For additional information, see Note 16 — Partners’ Capital (Deficit). As of December 31, 2016 and 2015, approximately $0.9 million and $1.1 million, respectively, were due from High Mesa for reimbursement of expenses which is recorded in the receivables due from affiliates on the consolidated balance sheets.

On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate, Northwest Gas Processing, LLC (“NWGP”), which is a subsidiary of High Mesa. We recorded $25.5 million in other receivables and $8.5 million in long-term notes receivable, while recording no gain or loss on the sale at December 31, 2014. On January 2, 2015, the receivable of $25.5 million was paid in full. The $8.5 million long-term note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019. Immediately after the consummation of the transaction, NWGP’s obligation under the $8.5 million promissory note was transferred to High Mesa Services, LLC, a subsidiary of High Mesa. The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve. Interest income on the note receivable from our affiliate amounted to $0.8 million and $0.7 million during the years ended December 31, 2016 and 2015, respectively. Such amounts have been added to the balance of the note receivable. On December 31, 2015, we repurchased land originally sold to NWGP at cost of $0.7 million.

We are party to a services agreement dated January 1, 2016 with NWGP. Pursuant to the agreement, we agree to provide administrative and management services to NWGP relating to the midstream assets we sold to NWGP on December 31, 2014. During the year ended December 31, 2016, NWGP was billed for management services provided in the amount of approximately $0.1 million.

F-21

On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM, which was subsequently amended and restated on February 3, 2017, effective as of December 1, 2016. High Mesa owns a minority interest in KFM. Alta Mesa also indirectly owns a minimal interest in KFM through its less than 10% ownership of AEM. We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM for gathering and processing.

Under the Crude Oil Gathering Agreement and the Gas Gathering and Processing Agreement, Oklahoma Energy dedicates and delivers to KFM crude oil and natural gas and associated natural gas liquids produced from present and future wells located in certain lands in Kingfisher, Logan, Canadian, Blaine and Garfield Counties in Oklahoma to designated receipt points on KFM’s system for gathering and processing. The Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement will remain in effect for a primary term of 15 years from the in-service date of July 1, 2016 and, after the primary term, an extended term for as long as there are wells connected to the system that continue to produce crude oil or gas in commercial (paying) quantities.

Under the Crude Oil Gathering Agreement, KFM operates a crude oil gathering system for the purpose of providing gathering services to Oklahoma Energy. KFM receives from Oklahoma Energy a fixed service fee per barrel of crude oil delivered. The fixed gathering fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the crude oil gathering system.

Under the Gas Gathering and Processing Agreement, KFM operates a gas gathering and processing system for the purpose of providing gathering and processing services to Oklahoma Energy. KFM provides gathering and processing services for a fixed fee. The fixed service fee consists of (i) a gathering fee assessed on the volume of gas allocated to the central receipt point, (ii) a processing fee assessed on the volume of gas allocated to the central receipt point, (iii) a dehydration fee assessed on the volume of gas allocated to the central receipt point, (iv) a compression fee for each stage of compression for any volume of gas allocated to the central receipt point and (v) a facility fee for the first four years of the agreement, at which time the facility fee is removed. Beginning in January 2021, each fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the gas gathering and processing system. Under the Gas Gathering and Processing Agreement, we have secured firm processing rights of 260 MMcf/d at the expanding KFM plant.

The aggregate amounts paid under the Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement depends on the volumes produced and gathered pursuant to these agreements. Under such agreements, the fees for the year ended December 31, 2016 were $7.5 million. The plant commenced operations in the second quarter of 2016. These fees are recorded as marketing and transportation expense in the consolidated statements of operations. As of December 31, 2016, we accrued approximately $3.0 million as a reduction of accounts receivable on the consolidated balance sheets for fees related to marketing and transportation for the KFM plant. Subsequent to year-end, Oklahoma Energy entered into an agreement with KFM whereby the Company made a deposit of $10.0 million on January 13, 2017 to KFM to provide us with 100,000 Dth/day for firm transportation. The deposit will be released back to us as we utilize the marketing and transportation services in 2018.

F-22

NOTE 10 — LONG TERM DEBT, NET

Long-term debt, net consists of the following:

	December 31, 2016			December 31, 2015
	(in thousands)
Senior secured revolving credit facility	$	40,622		$	152,000
Senior secured term loan		—			125,000
9.625% senior unsecured notes due 2018		—			448,598
7.875% senior unsecured notes due 2024		500,000			—
Unamortized deferred financing costs		(10,717	)		(7,823	)
Total long-term debt, net	$	529,905		$	717,775
Notes payable to founder	$	26,957		$	25,748

Senior Secured Revolving Credit Facility. In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. The amended and restated credit facility, among other things, (i) reaffirms the existing borrowing base amount of $300 million through the new redetermination of the borrowing base, (ii) increases the maximum credit amount from $500 million to $750 million, subject to borrowing base limit (iii) extends the maturity of the credit facility to November 10, 2020 with the completion of a refinancing of the 2018 Notes (as described below), (iv) increases our pricing grid by 25 to 50 basis points (depending on our leverage ratio), and (v) increases our mortgage requirement from 85% of the value of our proven reserves to 90%. Our borrowing base was reduced to $287.5 million from $300 million following the issuance of the 2024 Notes, as described below.

As of December 31, 2016, the Company had $40.6 million outstanding with $239.3 million of available borrowing capacity under the credit facility. The principal amount is payable at maturity. The credit facility borrowing base is redetermined semi-annually, on or about May 1 and November 1 of each year. The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association. The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00. The reference rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00. The weighted average and effective interest rate on outstanding borrowings was 4.00% as of December 31, 2016 and 2.89% as of December 31, 2015. The letters of credit outstanding as of December 31, 2016 and 2015 were $7.6 million and $65,000, respectively.

The credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment

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amounts available under the credit facility are at least 20% of the commitments in effect. As of December 31, 2016, the covenants of the Company’s credit facility prohibit it from making any distributions.

The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0, commencing with the fiscal quarter ending December 31, 2016.

As of December 31, 2016, we were in compliance with all covenants under the credit facility.

Senior Secured Term Loan. On June 2, 2015, we entered into a second lien senior secured term loan agreement (the “term loan facility”) with Morgan Stanley Energy Capital Inc., as administrative agent, and the lenders party thereto, pursuant to which we borrowed $125 million. In October 2016, High Mesa contributed $300 million to us from the investment by Bayou City, as described in Note 16. We used a portion of the contribution to repay all amounts outstanding under the term loan facility of $127.7 million, which includes accrued interest and a $2.5 million prepayment premium for repaying all amounts owed under the term loan facility prior to maturity date.

For the year ended December 31, 2016, the Company recognized a loss of $4.7 million, which included unamortized deferred financing cost write-offs of $2.0 million, and are reflected in loss on extinguishment of debt in the consolidated statements of operations.

Senior Unsecured Notes. On December 8, 2016, the Company and our wholly owned subsidiary Alta Mesa Finances Services Corp. (collectively, the “Issuers”) issued $500.0 million in aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024 at par, the 2024 Notes, which resulted in aggregate net proceeds to the Company of $491.3 million, after deducting commission offering expenses. The Company used the proceeds from the issuance of the 2024 Notes to fund the repurchase of the 2018 Notes pursuant to a tender offer and the redemption of any of the 2018 Notes that remained outstanding after consummation of the tender offer. The remainder of the proceeds were used to repay a portion of our indebtedness under our credit facility.

The 2024 Notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2024 Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, the Company may, on any one or more occasions, redeem all or part of the 2024 Notes for cash at a redemption price equal to 100% of their principal amount of the 2024 Notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the 2024 Notes may require the Company to repurchase all or a portion of the 2024 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2024 Notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, the Company may redeem the 2024 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.

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The 2024 Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of the Company’s existing and future senior indebtedness; senior in right of payment to all of the Company’s existing and future indebtedness that is expressly subordinated to the 2024 Notes or the respective guarantees; effectively subordinated to all of the Company’s existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Company’s credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of the Company’s subsidiaries that do not guarantee the 2024 Notes.

The 2024 Notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change the Company’s line of business. As of December 31, 2016, the covenants of the Company’s senior secured revolving credit facility prohibit it from making any distributions.

Under the terms of the indenture for the 2024 Notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase.

Repurchase and Redemption of 9.625% Senior Unsecured Notes due 2018

On November 30, 2016 we commenced a tender offer for any and all outstanding 2018 Notes. The tender offer expired on December 7, 2016 and on December 8, 2016, we made payment of the aggregate principal amount of the 2018 Notes validly tendered. In connection therewith, on December 8, 2016, the Company caused to be deposited, with Wells Fargo Bank, National Association, the Trustee for the 2018 Notes (the “Trustee”), funds sufficient to redeem any 2018 Notes remained outstanding on December 8, 2016. On December 20, 2016, the Trustee executed a satisfaction and discharge (the “Satisfaction and Discharge”) of the indenture relating to the 2018 Notes. The Satisfaction and Discharge, among other things, discharged the indenture and the obligations of the Company thereunder. As a result of the tender offer and redemption, the Company repurchased and redeemed its $450 million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees, for the year ended December 31, 2016.

For the year ended December 31, 2016, the Company recognized a loss of $13.5 million, which includes unamortized discount write-off of $0.9 million, unamortized deferred financing costs write-off of $3.2 million, tender premium of $2.5 million and accrued interest of $6.9 million, which is all reflected in loss on extinguishment of debt in the consolidated statements of operations.

Notes Payable to Founder. We have notes payable to our founder which bear simple interest at 10% with a balance of $27.0 million and $25.7 million at December 31, 2016 and 2015, respectively. The maturity date was extended on March 25, 2014, from December 31, 2018 to December 31, 2021. Interest and principal are payable at maturity. Our founder may convert the notes into shares of our Class B partner’s, High Mesa, common stock upon certain conditions in the event of an initial public offering of High Mesa.

These founder notes are unsecured and are subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 16, the founder notes were amended and restated to subordinate them to the paid in kind notes of our Class B partner. The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our partnership agreement, as amended, and subordinated to the rights of the holders of Series B preferred stock to receive payments.

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Interest on the notes payable to our founder amounted to $1.2 million during each of the years ended December 31, 2016, 2015 and 2014. Such amounts have been added to the balance of the founder notes.

Deferred financing costs. As of December 31, 2016, the Company had $13.7 million of deferred financing costs related to the credit facility and the 2024 Notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $10.7 million related to the 2024 Notes are included in long-term debt on the consolidated balance sheets as of December 31, 2016. Deferred financing costs of $3.0 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at December 31, 2016. Amortization of deferred financing costs recorded for the years ended December 31, 2016, 2015 and 2014 was $3.9 million, $3.4 million and $2.9 million, respectively. These costs are included in interest expense on the consolidated statements of operations. The loss on extinguishment of debt in the consolidated statements of operations included unamortized deferred financing costs write-offs of $5.1 million related to the repayment of the term loan facility and the repurchase and redemption of the 2018 Notes for the year ended December 31, 2016. No deferred financing costs were written off during the years ended December 31, 2015 and 2014.

Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized deferred financing costs, at December 31, 2016 are as follows (in thousands):

Year ending December 31,
2017	$	—
2018		—
2019		—
2020		40,622
2021		26,957
Thereafter		500,000
	$	567,579

The credit facility and the 2024 Notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.

At December 31, 2016, we were in compliance with the covenants of our debt agreements.

NOTE 11 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following provides the detail of accounts payable and accrued liabilities:

	December 31, 2016		December 31, 2015
	(in thousands)
Capital expenditures	$	15,155	$	10,780
Revenues and royalties payable		12,187		5,082
Operating expenses/taxes		17,499		17,955
Interest		2,627		9,919
Compensation		5,302		5,434
Derivatives settlement payable		1,126		11,149
Other		1,164		1,201
Total accrued liabilities		55,060		61,520
Accounts payable		29,174		21,101
Accounts payable and accrued liabilities	$	84,234	$	82,621

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NOTE 12 — COMMITMENTS AND CONTINGENCIES

Contingencies

Environmental claims: Various landowners have sued the Company and/or our wholly owned subsidiaries, in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our consolidated financial statements at December 31, 2016.

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. Management revised the estimated liability for groundwater contamination in Florida based on our reassessment of our remediation costs and plan, which is pending approval by the State of Florida. As of December 31, 2016, our revised estimated remediation liability was approximately $0.1 million. As of December 31, 2015, we had estimated a liability of $1.3 million, based on our undiscounted engineering estimates. The obligations are included in accounts payable and accrued liabilities at December 31, 2016 and other long-term liabilities at December 31, 2015 in the accompanying consolidated balance sheets.

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

Litigation:On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our wholly-owned subsidiary, which we acquired in 2010), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish. Plaintiffs claim they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located. Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. We have been defending this ongoing case and investigating the scope of the Plaintiffs’ alleged damage. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. As of December 31, 2016, we have accrued approximately $4.0 million ($0.8 million in current liabilities and $3.2 million in other long-term liabilities) in connection with the settlement. The settlement requires payment over the term of six years.

Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

We have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.

Performance appreciation rights: In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The

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Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants are granted Performance Appreciation Rights (“PARs”) with a stipulated initial designated value (“SIDV”). The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value and the designated value of the PAR on the payment valuation date. The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally can be construed in accordance with the meaning of the term “change in control event”) or as selected by the participant, but no earlier than five years from the end of the year of the grant. Both the initial stipulated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event. After any payment valuation date, regardless of payment or none, vested PARs expire. During 2016, we granted 360,000 PARs and terminated 26,200 PARs with a SIDV of $40, resulting in 575,300 PARs issued at a weighted average value of $36.78. Subsequent to year end, 306,300 PARs were granted with a SIDV of $40 and 500 PARs with a SIDV of $40 were terminated, resulting in 881,100 PARs issued at a weighted average value of $37.90. We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan. We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote. Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2016 or 2015.

Commitments

Office and Equipment Leases: We lease office space, as well as certain field equipment such as compressors, under long-term operating lease agreements. The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease. Equipment leases are generally for four years or less. Total rent expense, net of sublease income, including office space and compressors, for the years ended December 31, 2016, 2015, and 2014 amounted to approximately $5.7 million, $4.8 million, and $5.7 million, respectively.

At December 31, 2016, the future minimum base rentals for non-cancelable operating leases are as follows:

Year Ending December 31,	Amount (1) (in thousands)
2017	$	3,956
2018		1,453
2019		1,545
2020		1,593
2021		1,620
Thereafter		1,207
	$	11,374

(1) These amounts include long-term lease payments for office space and compressors, net of sublease income. The Company expects to receive $0.2 million of total sublease income through 2019.

Additionally, at December 31, 2016, the Company had posted bonds in the aggregate amount of $24.0 million, primarily to cover future abandonment costs.

NOTE 13 — SIGNIFICANT CONCENTRATIONS

We sell our oil and natural gas primarily through a marketing contract with AEM. AEM is our marketing agent and acts on our behalf to market our oil and natural gas to any purchasers identified by AEM. We are a part owner of AEM with an ownership interest of less than 10%. AEM markets our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with

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differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. The fee charged to us by AEM for marketing is recorded as a marketing and transportation expense. Our marketing agreement with AEM commenced in June 2013. This agreement will terminate in June 2018, with additional provisions for extensions beyond five years and for early termination. AEM marketed majority of our production from operated fields between 2014 and 2016. Production from non-operated fields was marketed on our behalf by the operators of those properties.

For the year ended December 31, 2016, revenues marketed by AEM were $160.7 million, or 80% of total revenue excluding hedging activities. For the year ended December 31, 2015, revenues marketed by AEM were $178.2 million, or 73.9% of total revenue excluding hedging activities. For the year ended December 31, 2014, revenues marketed by AEM were $220.9 million, or 51.1% of total revenue excluding hedging activities, and based on revenues excluding hedging activities, one major customer, Murphy Oil Corporation accounted for 10% or more of those revenues, with revenues excluding hedges of $61.2 million. We believe that the loss of any of our significant customers, or of our marketing agent AEM, would not have a material adverse effect on us because alternative purchasers are readily available.

NOTE 14 — 401(k) SAVINGS PLAN

Employees of Alta Mesa Services, LP, our wholly owned subsidiary (“Alta Mesa Services”), and Petro Operating Company, LP (“POC”) may participate in a 401(k) savings plan, whereby the employees may elect to make contributions pursuant to a salary reduction agreement. Alta Mesa Services and POC make a matching contribution equal to 100% of an employee’s salary deferral contribution up to a maximum of 5% of an employee’s salary, effective January 1, 2016. Matching contributions to the plan were approximately $1,122,000, $710,000, and $683,000 for the years ended December 31, 2016, 2015 and 2014, respectively.

NOTE 15 — SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas have been highly volatile and declined dramatically since the second half of 2014. Although oil and natural gas prices have recently begun to recover from the lows experienced since the decline in the second half of 2014, forecasted prices for both oil and natural gas remain depressed. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Continued depressed oil and natural gas prices, further 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 oil and natural gas reserves. Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 7.

NOTE 16 — PARTNERS’ CAPITAL (DEFICIT)

Our partnership agreement provides for two classes of limited partners. Class A partners include our founder and other parties. Our sole Class B partner is High Mesa.

On March 25, 2014, High Mesa completed a $350 million recapitalization with an investment from Highbridge Principal Strategies LLC (“Highbridge”). Proceeds from the investment were used in part to purchase the investment of Denham Capital Management LP in High Mesa. Our board of directors includes one member nominated by Highbridge, five members nominated by the Class A partners and two members nominated by Bayou City.

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Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for reasons of “cause,” which are defined in the partnership agreement. The Class B partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.

On August 31, 2016, our Class B partner completed the sale of preferred stock to BCE-MESA Holdings LLC (“BCE-MESA”), a fund managed by Bayou City. In connection with the sale of preferred stock, our General Partner, Class B partner, and all of our Class A partners entered into a Fourth Amended and Restated Limited Partnership Agreement (the “Amended Partnership Agreement”). The Amended Partnership Agreement provides, among other things, for certain drag-along rights, including the mandatory contribution to the Class B partner by the Class A partners of their remaining Class A units upon an initial public offering.

In addition, on August 31, 2016, the owners of our General Partner entered into a Third Amended and Restated Limited Liability Company Agreement, which was amended to provide that the number of members of the board of managers of our General Partner be increased to match the number of members of the board of directors of our Class B partner. William W. McMullen, the founder and managing partner of Bayou City, was appointed to the board of managers of our General Partner.

On September 30, 2016, our Class B partner completed an additional sale of preferred stock to Bayou City. In connection with this investment, Mark Stoner, as a nominee of Bayou City, was appointed to the board of managers of our General Partner.

Contribution, Distribution, and Income Allocation: All distributions under the Amended Partnership Agreement shall first be made to holders of Class B units, until certain provisions are met. After such provisions are met, distributions shall then be made to holders of Class A and Class B units pursuant to the distribution formulas set forth in the Amended Partnership Agreement.

The Class B partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes.

Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the Amended Partnership Agreement. A “Liquidity Event” is defined as the first to occur, in one or a series of related transactions, of (i) a disposition of all or substantially of the assets of High Mesa and its subsidiaries to a person that is not an affiliate of High Mesa, (ii) a disposition of all the equity securities of High Mesa, or (iii) the consummation of a public offering of the common equity securities of High Mesa or any of its subsidiaries that hold all of substantially all of High Mesa’s assets on a consolidated basis, and if the public offering is of a subsidiary of High Mesa, the subsequent distribution of the public company equity securities or proceeds obtained in the public offering to the holders of equity securities of High Mesa. The Class B partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.

In connection with the final sale of preferred stock to Bayou City, our Class B partner contributed $300 million from the Bayou City investment to us. We used a portion of the contribution to repay all amounts outstanding under the term loan facility of $127.7 million, which includes accrued interest and a $2.5 million prepayment premium for repaying all amounts owed under the term loan facility prior to maturity date. The remaining funds are available to be used for general corporate purposes.

As described in Notes 4 and 9, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us on December 31, 2016. High Mesa’s equity contribution was recorded at the contribution date fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected subsequent to year end.

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During 2015, our partnership agreement was amended and restated, pursuant to which our Class B partner contributed $20 million to us, which we used to pay down amounts owed under the credit facility.

We made no distributions for the year ended December 31, 2016. For the year ended December 31, 2015, we made distributions of approximately $3.8 million to our Class B partner. For the year ended December 31, 2014, we made distributions of approximately $0.5 million to our founder as discussed in Note 9 and the partners’ share of taxes related to the sale of AME as discussed in Note 4.

NOTE 17 — SUBSIDIARY GUARANTORS

All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes and our credit facility. Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. The parent company, Alta Mesa Holdings, LP, has no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned and are not guarantors and are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to the parent company.

NOTE 18 — SUPPLEMENTAL QUARTERLY INFORMATION(Unaudited)

Results of operations by quarter for the year ended December 31, 2016 were:

	Quarter Ended
2016	March 31			June 30			Sept 30			Dec 31
	(in thousands)
Total operating revenues	$	38,167		$	53,823		$	54,532		$	64,186
Loss from operations(1)(2)		(7,967	)		(52,686	)		(8,620	)		(20,536	)
Net loss	$	(24,157	)	$	(70,327	)	$	(26,567	)	$	(46,870	)

(1) Includes $1.8 million, $11.6 million, and $2.1 million of impairment expense during the quarters ended March 31, 2016, June 30, 2016, and December 31, 2016, respectively.

(2) Includes $38.3 million and $16.5 million loss on derivative contracts during the quarters ended June 30, 2016 and December 31, 2016.

Results of operations by quarter for the year ended December 31, 2015 were:

	Quarter Ended
2015	March 31			June 30			Sept 30		Dec 31
	(in thousands)
Total operating revenues	$	60,542		$	71,755		$	61,344	$	48,325
Income (loss) from operations(3)(4)(5)		(95,077	)		(23,881	)		110,069		(60,592	)
Net income (loss)	$	(109,211	)	$	(39,509	)	$	93,079	$	(76,152	)

(3) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015.

(4) Includes $73.1 million, $8.9 million, and $90.5 million of impairment expense during the quarters ended March 31, 2015, September 30, 2015, and December 31, 2015, respectively.

(5) Includes $72.0 million gain on derivative contracts during the quarter ended September 30, 2015.

NOTE 19 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited)

The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASCTopic 932-235.

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

F-31

Estimated Quantities of Proved Reserves

The following table sets forth our net proved reserves as of December 31, 2016, 2015 and 2014, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.

	Oil (MBbls)			Gas (MMcf)			NGL’s (MBbls)			BOE (MBbls)
Total Proved Reserves:
Balance at December 31, 2013		32,517			132,265			5,735			60,296
Production		(3,770	)		(14,449	)		(537	)		(6,715	)
Purchases in place		610			327			—			665
Discoveries and extensions		13,281			28,822			4,119			22,204
Sales of reserves in place		(6,298	)		(35,857	)		(949	)		(13,223	)
Revisions of previous quantity estimates and other		(4,996	)		(7,960	)		20			(6,304	)
Balance at December 31, 2014		31,344			103,148			8,388			56,923
Production		(4,203	)		(11,900	)		(678	)		(6,865	)
Discoveries and extensions		12,981			58,129			7,763			30,432
Sales of reserves in place		(6,544	)		(8,250	)		(748	)		(8,667	)
Revisions of previous quantity estimates and other		564			14,296			3,712			6,660
Balance at December 31, 2015		34,142			155,423			18,437			78,483
Production		(4,001	)		(13,959	)		(956	)		(7,284	)
Purchases in place(1)		1,508			6,754			613			3,247
Discoveries and extensions		29,903			154,653			14,000			69,679
Sales of reserves in place		(73	)		(966	)		(10	)		(244	)
Revisions of previous quantity estimates and other		(3,680	)		14,100			(3,794	)		(5,124	)
Balance at December 31, 2016		57,799			316,005			28,290			138,757
Proved Developed Reserves:
Balance at December 31, 2014		15,182			63,334			4,028			29,765
Balance at December 31, 2015		14,942			71,752			6,958			33,859
Balance at December 31, 2016		16,832			93,361			7,977			40,371
Proved Undeveloped Reserves:
Balance at December 31, 2014		16,162			39,814			4,360			27,158
Balance at December 31, 2015		19,200			83,671			11,479			44,624
Balance at December 31, 2016		40,967			222,644			20,313			98,386

(1) Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from our Class B partner. See Note 9 — Related Party Transactions and Note 16 — Partners’ Capital (Deficit) for further details.

F-32

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

	December 31,
	2016			2015
	(in thousands)
Capitalized costs:
Proved properties	$	1,611,249		$	1,345,482
Unproved properties		116,311			127,551
Total		1,727,560			1,473,033
Accumulated depreciation, depletion, amortization and impairment		(1,015,398	)		(947,091	)
Net capitalized costs	$	712,162		$	525,942

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

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

	Year Ended December 31,
	2016		2015		2014
	(in thousands)
Costs incurred during the year:
Property acquisition costs
Unproved (1)	$	66,788	$	74,475	$	33,787
Proved (2)		68,478		2,899		7,462
Exploration		28,480		34,275		59,201
Development(3)		165,796		146,299		341,594
	$	329,542	$	257,948	$	442,044

(1) Property acquisition costs in unproved properties in 2015 include the unevaluated leasehold portion of the Kingfisher leasehold acquisition of $46.6 million.

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

(3) Includes asset retirement additions (revisions) of $1.9 million, ($0.3) million, and $4.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Standardized Measure of Discounted Future Net Cash Flows

The information that follows has been developed pursuant to ASC 932-235 and utilizes reserve and production data prepared by us. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Future cash inflows as of December 31, 2016, 2015 and 2014 were calculated using an un-weighted arithmetic average of oil and natural gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in

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consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.

The following table sets forth the components of the standardized measure of discounted future net cash flows at December 31, 2016, 2015 and 2014:

	At December 31,
	2016			2015			2014
	(in thousands)
Future cash flows	$	3,547,130		$	2,395,128		$	3,737,412
Future production costs		(1,811,683	)		(860,600	)		(991,149	)
Future development costs		(709,738	)		(403,953	)		(450,659	)
Future taxes on income		—			—			—
Future net cash flows		1,025,709			1,130,575			2,295,604
Discount to present value at 10 percent per annum		(467,101	)		(500,979	)		(877,558	)
Standardized measure of discounted future net cash flows	$	558,608		$	629,596		$	1,418,046
Base price for crude oil, per Bbl, in the above computation was:	$	42.75		$	50.28		$	94.99
Base price for natural gas, per Mcf, in the above computation was:	$	2.49		$	2.58		$	4.35

No consideration was given to the Company’s hedged transactions. The estimated realized prices for natural gas liquids using a $42.75 per Bbl benchmark and adjusted for average differentials were $15.18. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others.

Changes in Standardized Measure of Discounted Future Net Cash Flows

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

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Balance at beginning of year	$	629,596		$	1,418,046		$	1,406,274
Sales of oil and natural gas, net of production costs		(124,610	)		(147,906	)		(320,130	)
Changes in sales and transfer prices, net of production costs		(324,638	)		(823,073	)		(153,770	)
Revisions of previous quantity estimates		(35,972	)		53,101			(477,377	)
Purchases of reserves-in-place		40,611			—			21,633
Sales of reserves-in-place		2,345			(244,251	)		(107,414	)
Current year discoveries and extensions		356,631			260,078			701,820
Changes in estimated future development costs		849			4,376			2,591
Development costs incurred during the year		8,363			42,420			161,357
Accretion of discount		62,960			141,805			140,627
Net change in income taxes		—			—			—
Change in production rate (timing) and other		(57,527	)		(75,000	)		42,435
Net change		(70,988	)		(788,450	)		11,772
Balance at end of year	$	558,608		$	629,596		$	1,418,046

F-34

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2017		December 31, 2016
	(in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,279	$	7,185
Short-term restricted cash		805		433
Accounts receivable, net of allowance of $774 and $889, respectively		49,089		37,611
Other receivables		3,780		8,061
Receivables due from affiliate		1,688		8,883
Prepaid expenses and other current assets		1,899		3,986
Derivative financial instruments		15,002		83
Total current assets		77,542		66,242
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		822,498		712,162
Other property and equipment, net		9,690		9,731
Total property and equipment, net		832,188		721,893
OTHER ASSETS
Investment in LLC — cost		9,000		9,000
Deferred financing costs, net		2,299		3,029
Notes receivable due from affiliate		10,393		9,987
Deposits and other long-term assets		16,707		2,977
Derivative financial instruments		8,873		723
Total other assets		47,272		25,716
TOTAL ASSETS	$	957,002	$	813,851
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	130,225	$	84,234
Advances from non-operators		3,165		4,058
Advances from related party		—		42,528
Asset retirement obligations		1,006		376
Derivative financial instruments		—		21,207
Total current liabilities		134,396		152,403
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		60,663		61,128
Long-term debt, net		685,526		529,905
Notes payable to founder		27,556		26,957
Derivative financial instruments		—		4,482
Other long-term liabilities		7,154		6,870
Total long-term liabilities		780,899		629,342
TOTAL LIABILITIES		915,295		781,745
Commitments and Contingencies (Note 11)
PARTNERS’ CAPITAL		41,707		32,106
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	957,002	$	813,851

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

F-35

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
OPERATING REVENUES AND OTHER
Oil	$	55,071		$	43,843		$	114,416		$	75,087
Natural gas		13,136			5,796			25,821			10,487
Natural gas liquids		7,076			4,010			14,695			6,115
Other revenues		86			174			202			301
Total operating revenues		75,369			53,823			155,134			91,990
Gain on sale of assets		—			1,083			—			3,731
Gain on acquisition of oil and natural gas properties		1,626			—			1,626			—
Gain (loss) on derivative contracts		18,250			(38,293	)		48,492			(27,478	)
Total operating revenues and other		95,245			16,613			205,252			68,243
OPERATING EXPENSES
Lease and plant operating expense		16,597			13,452			34,333			30,577
Marketing and transportation expense		6,857			1,472			12,900			2,887
Production and ad valorem taxes		3,039			2,731			6,107			5,126
Workover expense		2,015			1,118			3,398			2,515
Exploration expense		6,265			3,428			14,407			6,714
Depreciation, depletion, and amortization expense		26,494			22,931			51,298			44,424
Impairment expense		27,904			11,555			29,124			13,319
Accretion expense		480			536			1,052			1,075
General and administrative expense		8,328			12,076			18,076			22,259
Total operating expenses		97,979			69,299			170,695			128,896
INCOME (LOSS) FROM OPERATIONS		(2,734	)		(52,686	)		34,557			(60,653	)
OTHER INCOME (EXPENSE)
Interest expense		(12,879	)		(17,672	)		(25,219	)		(34,067	)
Interest income		299			227			548			433
Total other income (expense)		(12,580	)		(17,445	)		(24,671	)		(33,634	)
INCOME (LOSS) BEFORE STATE INCOME TAXES		(15,314	)		(70,131	)		9,886			(94,287	)
Provision for state income taxes		—			106			285			107
NET INCOME (LOSS)	$	(15,314	)	$	(70,237	)	$	9,601		$	(94,394	)

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

F-36

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2017			2016
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	9,601		$	(94,394	)
Adjustments to reconcile net (income) loss to net cash used in operating activities:
Depreciation, depletion, and amortization expense		51,298			44,424
Impairment expense		29,124			13,319
Accretion expense		1,052			1,075
Amortization of deferred financing costs		1,456			1,965
Amortization of debt discount		—			255
Dry hole expense		888			215
Expired leases		5,922			2,435
(Gain) loss on derivative contracts		(48,492	)		27,478
Settlements of derivative contracts		254			65,991
Premium paid on derivative contracts		(520	)		—
Interest converted into debt		599			600
Interest on notes receivable due from affiliates		(406	)		(378	)
Gain on sale of assets		—			(3,731	)
Gain on acquisition of oil and natural gas properties		(1,626	)		—
Changes in assets and liabilities:
Restricted cash		(372	)		(121,935	)
Accounts receivable		(11,478	)		(6,927	)
Other receivables		4,281			14,377
Receivables due from affiliate		(680	)		(1,615	)
Prepaid expenses and other non-current assets		(11,644	)		(3,951	)
Advances from related party		(42,528	)		—
Settlement of asset retirement obligation		(977	)		(741	)
Accounts payable, accrued liabilities, and other liabilities		7,655			14,619
NET CASH USED IN OPERATING ACTIVITIES		(6,593	)		(46,919	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(151,832	)		(94,997	)
Acquisitions		(6,251	)		—
Proceeds from sale of property		—			1,358
NET CASH USED IN INVESTING ACTIVITIES		(158,083	)		(93,639	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		165,065			141,935
Repayments of long-term debt		(10,000	)		—
Additions to deferred financing costs		(170	)		(799	)
Capital contributions		7,875			—
NET CASH PROVIDED BY FINANCING ACTIVITIES		162,770			141,136
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(1,906	)		578
CASH AND CASH EQUIVALENTS, beginning of period		7,185			8,869
CASH AND CASH EQUIVALENTS, end of period	$	5,279		$	9,447

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

F-37

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent exploration and production company engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our principal area of operation is in the eastern portion of the Anadarko Basin commonly 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. Our operations also include other non-STACK oil and natural gas interests within the continental United States.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We have provided a discussion of significant accounting policies in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Annual Report”). As of June 30, 2017, our significant accounting policies are consistent with those discussed in Note 2 in the 2016 Annual Report.

Principles of Consolidation and Reporting

The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2016, which were filed with the Securities and Exchange Commission (the “SEC”) in our 2016 Annual Report.

The condensed consolidated financial statements included herein as of June 30, 2017, and for the three and six months ended June 30, 2017 and 2016, are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete financial statements. Certain reclassifications of prior period condensed consolidated financial statements have been made to conform to current reporting practices. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

Use of Estimates

The preparation of condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion, and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, state taxes, and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.

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Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09 (“ASU 2014-09”),Revenue from Contracts with Customers. The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14,Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 deferred the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are in the process of assessing our contracts and evaluating the impact on the condensed consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09 as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. We enter into lease agreements to support our operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment. We continue to evaluate the impacts of the amendments to our financial statements and accounting practices for leases. Although we are still in the process of evaluating the effect of adoptingASU 2016-02, the adoption is expected to result in an increase in the assets and liabilities recorded on our condensed consolidated balance sheet. We anticipate adoption of ASU 2016-02 effective January 1, 2019.

In August 2016, the FASB issued ASU No. 2016-15,Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments(“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our condensed consolidated statements of cash flows.

In November 2016, the FASB issued ASU 2016-18,Statement of Cash Flows: Restricted Cash(“ASU 2016-18”), which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.

In January 2017, the FASB issued ASU No. 2017-01,Clarifying the Definition of a Business,which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be

F-39

further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.

3. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:

	Six Months Ended June 30,
	2017		2016
	(in thousands)
Supplemental cash flow information:
Cash paid for interest	$	23,452	$	31,071
Cash paid for state income taxes		—		422
Non-cash investing and financing activities:
Change in asset retirement obligations		235		577
Asset retirement obligations assumed, purchased properties		89		—
Change in accruals or liabilities for capital expenditures		37,494		(4,869	)

4. ACQUISITIONS

During the second quarter of 2017, we entered into a purchase and sale agreement with an unaffiliated third party to acquire certain oil and natural gas properties in Oklahoma. The acquired oil and natural gas properties were primarily unproved leasehold in Oklahoma. We made a deposit concurrently with the execution of the purchase and sale agreement of approximately $4.6 million, which is recorded in oil and natural gas properties on our condensed consolidated balance sheet as of June 30, 2017. On July 7, 2017, we closed and funded the remaining purchase price of the acquisition for approximately $40.4 million, net of customary post-closing adjustments, with borrowings under our senior secured revolving credit facility.

In April 2017, we completed an acquisition of certain non-STACK proved oil and natural gas properties from Setanta Energy, LLC (“Setanta”) for a purchase price, net of customary purchase price adjustments, of approximately $0.9 million. We funded the acquisition with borrowings under our senior secured revolving credit facility. This purchase increases our working interest in various wells in which we already hold an interest. The acquisition was accounted for using the acquisition method under ASC 805, “Business Combinations,” which requires acquired assets and liabilities to be recorded at fair value as of the acquisition date.

F-40

A summary of the consideration paid and the allocation of the total purchase price to the assets acquired and the liabilities assumed in the Setanta acquisition based on the preliminary fair value at the acquisition date are as follows:

	(in thousands)
Summary of Consideration
Cash	$	890
Total consideration paid		890
Summary of Purchase Price Allocation
Plus: fair value of liabilities assumed
Asset retirement obligations assumed		89
Total fair value liabilities assumed		89
Less: fair value of assets acquired
Proved oil and natural gas properties		2,605
Unproved oil and natural gas properties		—
Total fair value assets acquired		2,605
Bargain Purchase Gain	$	(1,626	)

The fair value of the net assets acquired was approximately $2.6 million. As the fair value of the net assets acquired exceeded the total consideration paid, we recorded a bargain purchase gain of approximately $1.6 million. The bargain purchase gain is reflected in gain on acquisition of oil and natural gas properties on our condensed consolidated statement of operations.

In accordance with ASC 805, the following unaudited pro forma results of operations for the six months ended June 30, 2017 and 2016 have been prepared to give effect to the Setanta acquisition on our condensed consolidated results of operations as if it had occurred on January 1, 2016. Therefore, the bargain purchase gain on acquisition of $1.6 million has been included in pro forma income (loss) for the six months ended June 30, 2016. The difference between the historical results of operations and the unaudited pro forma results of operations for the three months ended June 30, 2017 and 2016 was determined to be de minimus and therefore not provided.

	Total Operating		Income
	Revenues		(Loss)
	(in thousands)
Pro forma results of operations for the six months ended June 30, 2017	$	155,474	$	8,016
Pro forma results of operations for the six months ended June 30, 2016	$	92,033	$	(92,864	)

This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during this period.

On December 31, 2016, our Class B partner, High Mesa, Inc. (“High Mesa”) purchased from BCE-STACK Development LLC (“BCE”) and contributed interests in 24 producing wells (the “Contributed Wells”) drilled under the joint development agreement to us. The Company accounted for the Contributed Wells as a business combination in the prior year and the results of operations from the acquisition is reflected in the consolidated statement of operations for the three and six months ended June 30, 2017. The difference between the historical results of operations and the unaudited pro forma results of operations for the three and six months ended June 30, 2016 was determined to be de minimus and therefore not provided.

F-41

5. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	June 30, 2017			December 31, 2016
	(in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	102,922		$	116,311
Accumulated impairment of unproved properties		(18,893	)		(65	)
Unproved properties, net		84,029			116,246
Proved oil and natural gas properties		1,814,057			1,611,249
Accumulated depreciation, depletion, amortization and impairment		(1,075,588	)		(1,015,333	)
Proved oil and natural gas properties, net		738,469			595,916
TOTAL OIL AND NATURAL GAS PROPERTIES, net		822,498			712,162
OTHER PROPERTY AND EQUIPMENT
Land		5,339			4,730
Office furniture and equipment, vehicles		20,135			19,446
Accumulated depreciation		(15,784	)		(14,445	)
OTHER PROPERTY AND EQUIPMENT, net		9,690			9,731
TOTAL PROPERTY AND EQUIPMENT, net	$	832,188		$	721,893

6. FAIR VALUE DISCLOSURES

The Company follows ASC 820, “Fair Value Measurements and Disclosures.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least reliable. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.

The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs.

Our senior notes are carried at historical cost, and we estimate the fair value of the senior notes for disclosure purposes. We have estimated the fair value of our $500 million senior notes payable to be $507.5 million at June 30, 2017. This estimation is based on the most recent trading values of the senior notes at or near the reporting dates, which is a Level 1 determination. See Note 9 for information on long-term debt.

We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil, natural gas and natural gas liquids derivative contracts. Inputs to these models include observable

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inputs from the New York Mercantile Exchange (“NYMEX”) for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil, natural gas and natural gas liquids prices. We have classified the fair values of all our oil, natural gas and natural gas liquids derivative contracts as Level 2.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and natural gas properties with a carrying amount of $36.2 million were written down to their fair value of $7.1 million, resulting in an impairment charge of $29.1 million for the six months ended June 30, 2017. For the six months ended June 30, 2016, oil and natural gas properties with a carrying amount of $27.5 million were written down to their fair value of $14.2 million, resulting in an impairment charge of $13.3 million. Oil and natural gas properties with a carrying amount of $32.8 million were written down to their fair value of $4.9 million, resulting in an impairment charge of $27.9 million for the three months ended June 30, 2017. For the three months ended June 30, 2016, oil and natural gas properties with a carrying amount of $24.2 million were written down to their fair value of $12.6 million, resulting in an impairment charge of $11.6 million. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $0.7 million and $0.6 million in additions to asset retirement obligations measured at fair value during the six months ended June 30, 2017 and 2016, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2017 and December 31, 2016, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:

	Level 1		Level 2		Level 3		Total
	(in thousands)
At June 30, 2017:
Financial Assets:
Commodity derivative contracts		—	$	36,073		—	$	36,073
Financial Liabilities:
Commodity derivative contracts		—	$	12,198		—	$	12,198
At December 31, 2016:
Financial Assets:
Commodity derivative contracts		—	$	15,773		—	$	15,773
Financial Liabilities:
Commodity derivative contracts		—	$	40,656		—	$	40,656

The amounts above are presented on a gross basis. Presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 7.

7. DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas and natural gas liquids. From time to time, we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our oil, natural gas and natural gas liquids sales contracts. Substantially all of our hedging

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agreements are executed by affiliates of our lenders under the senior secured revolving credit facility described in Note 9, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, natural gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month. The contracts represent agreements between us and the counterparties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading or speculative purposes.

From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.

We have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the condensed consolidated statements of operations at each reporting date.

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the condensed consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a liability account on the condensed consolidated balance sheets. Likewise, derivative liabilities could be presented in a derivative asset account.

The following table summarizes the fair value and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:

Fair Values of Derivative Contracts:

	June 30, 2017
Balance sheet location	Gross Fair Value of Assets		Gross amounts offset against assets in the Balance Sheet			Net Fair Value of Assets presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	19,405	$	(4,403	)	$	15,002
Derivative financial instruments,long-term assets		16,668		(7,795	)		8,873
Total	$	36,073	$	(12,198	)	$	23,875

Balance sheet location	Gross Fair Value of Liabilities		Gross amounts offset against liabilities in the Balance Sheet			Net Fair Value of Liabilities presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	4,403	$	(4,403	)	$	—
Derivative financial instruments, long-term liabilities		7,795		(7,795	)		—
Total	$	12,198	$	(12,198	)	$	—

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	December 31, 2016
Balance sheet location	Gross Fair Value of Assets		Gross amounts offset against assets in the Balance Sheet			Net Fair Value of Assets presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current assets	$	3,296	$	(3,213	)	$	83
Derivative financial instruments,long-term assets		12,477		(11,754	)		723
Total	$	15,773	$	(14,967	)	$	806

Balance sheet location	Gross Fair Value of Liabilities		Gross amounts offset against liabilities in the Balance Sheet			Net Fair Value of Liabilities presented in the Balance Sheet
	(in thousands)
Derivative financial instruments, current liabilities	$	24,420	$	(3,213	)	$	21,207
Derivative financial instruments, long-term liabilities		16,236		(11,754	)		4,482
Total	$	40,656	$	(14,967	)	$	25,689

The following table summarizes the effect of our derivative instruments in the condensed consolidated statements of operations:

Derivatives not designated as hedging instruments under ASC 815	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017		2016
	(in thousands)
Gain (loss) on derivative contracts
Oil commodity contracts	$	16,451		$	(31,517	)	$	42,537	$	(23,371	)
Natural gas commodity contracts		1,830			(6,584	)		5,728		(3,770	)
Natural gas liquids commodity contracts		(31	)		(192	)		227		(337	)
Total gain (loss) on derivative contracts	$	18,250		$	(38,293	)	$	48,492	$	(27,478	)

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the senior secured revolving credit facility.

If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

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We had the following open derivative contracts for crude oil at June 30, 2017:

OIL DERIVATIVE CONTRACTS

	Volume in Bbls		Weighted Average		Range
Period and Type of Contract					High		Low
2017
Price Swap Contracts		1,133,500	$	50.39	$	57.25	$	46.00
Collar Contracts
Long Call Options		92,000		85.00		85.00		85.00
Short Call Options		989,000		60.47		85.00		54.40
Long Put Options		835,000		48.40		50.00		47.00
Short Put Options		713,000		36.97		40.00		35.00
2018
Price Swap Contracts		547,500		57.22		57.25		57.20
Collar Contracts
Long Call Options		365,000		54.00		54.00		54.00
Short Call Options		2,190,000		60.87		62.00		60.50
Long Put Options		1,825,000		50.00		50.00		50.00
Short Put Options		2,190,000		40.26		42.00		40.00
2019
Collar Contracts
Short Call Options		1,241,000		62.90		63.00		62.75
Long Put Options		1,241,000		50.00		50.00		50.00
Short Put Options		1,241,000		37.50		37.50		37.50

We had the following open derivative contracts for natural gas at June 30, 2017:

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in MMBtu		Weighted Average		Range
Period and Type of Contract					High		Low
2017
Price Swap Contracts		922,500	$	3.40	$	3.40	$	3.39
Collar Contracts
Short Call Options		6,072,000		3.65		4.11		3.25
Long Put Options		5,304,500		3.14		3.60		3.00
Long Call Options		615,000		2.95		2.95		2.95
Short Put Options		5,919,500		2.59		3.00		2.50
2018
Collar Contracts
Short Call Options		6,582,000		5.26		5.53		4.00
Long Put Options		5,925,000		4.43		4.50		3.60
Short Put Options		5,925,000		3.92		4.00		3.00

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

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We had the following open derivative contracts for natural gas liquids at June 30, 2017:

NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS

	Volume in Gal		Weighted Average		Range
Period and Type of Contract					High		Low
2017
Price Swap Contracts
Short Price Swaps		3,091,200	$	0.47	$	0.47	$	0.47

We had the following open financial basis swaps at June 30, 2017:

BASIS SWAP DERIVATIVE CONTRACTS

Volume in MMBtu (1)		Reference Price 1	Reference Price 2	Period	Weighted Average Spread ($ per MMBtu)
	6,135,000	TEX/OKL Mainline (PEPL)	NYMEX Henry Hub	Jul ’17 — Dec ’17		$(0.25)
	5,910,000	TEX/OKL Mainline (PEPL)	NYMEX Henry Hub	Jan ’18 — Oct ’18		(0.27)

(1) Represents short swaps that fix the basis differentials between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) Inside FERC (“IFERC”) and NYMEX Henry Hub.

8. ASSET RETIREMENT OBLIGATIONS

A summary of the changes in asset retirement obligations is included in the table below:

	Six Months Ended June 30, 2017
	(in thousands)
Balance, beginning of year	$	61,504
Liabilities incurred		584
Liabilities assumed with acquired producing properties		89
Liabilities settled		(977	)
Revisions to estimates		(583	)
Accretion expense		1,052
Balance, June 30, 2017		61,669
Less: Current portion		1,006
Long-term portion	$	60,663

The total revisions to estimates include approximately $0.3 million related to reduction to oil and natural gas properties for the six months ended June 30, 2017.

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9. LONG-TERM DEBT, NET AND NOTES PAYABLE TO FOUNDER

Long-term debt, net and notes payable to founder consists of the following:

	June 30, 2017			December 31, 2016
	(in thousands)
Senior secured revolving credit facility	$	195,687		$	40,622
7.875% senior unsecured notes due 2024		500,000			500,000
Unamortized deferred financing costs		(10,161	)		(10,717	)
Total long-term debt, net	$	685,526		$	529,905
Notes payable to founder	$	27,556		$	26,957

Senior Secured Revolving Credit Facility. In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. On June 13, 2017, we entered into an Agreement and Amendment No. 2 (the “Second Amendment”) to the credit facility which, among other things: (a) increased our borrowing base from $287.5 million to $315.0 million until the next scheduled redetermination and (b) permits us to make a one-time cash distribution of no more than $1.0 million to a limited partner. As of June 30, 2017, we had $195.7 million outstanding with $114.0 million of available borrowing capacity under the credit facility. The letters of credit outstanding as of June 30, 2017 and December 31, 2016 were approximately $5.3 million and $7.6 million, respectively. The borrowing base is currently $315.0 million and is redetermined semi-annually in May and November of each year. The principal amount is payable on the maturity date of November 10, 2020.

The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association. The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00. The Reference Rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s Reference Rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00. The weighted average and effective interest rate on outstanding borrowings was 5.90% as of June 30, 2017 and 4.00% as of December 31, 2016.

The credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect.

The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion,

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amortization and exploration expenses (“EBITDAX”) over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0.

As of June 30, 2017, we were in compliance with all financial covenants of the credit facility.

Senior Unsecured Notes. We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) due December 15, 2024 which were issued at par by the Company and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016. Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.

The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the senior notes.

The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture governing the senior notes (the “indenture”)) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business.

Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase.

As of June 30, 2017, we were in compliance with the indentures governing the senior notes.

Notes Payable to Founder. We have notes payable to our founder (“Founder Notes”) that bear simple interest at 10% with a balance of $27.6 million and $27.0 million at June 30, 2017 and December 31, 2016, respectively.

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The maturity date was extended on March 25, 2014 from December 31, 2018 to December 31, 2021. Interest and principal are payable at maturity. Our founder shall convert the notes into shares of common stock of High Mesa upon certain conditions, in the event of a liquidity event as defined Note 13.

These Founder Notes are unsecured and subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner, the Founder Notes were amended and restated to subordinate them to the paid in kind (“PIK”) notes of our Class B partner. The Founder Notes were also subordinated to the rights of the holders of Class B units to receive distributions under our partnership agreement and subordinated to the rights of the holders of certain equity interests to receive payments.

Interest on the Founder Notes amounted to $0.6 million for each of the six months ended June 30, 2017 and 2016 and $0.3 million for each of the three months ended June 30, 2017 and 2016. Such amounts have been added to the balance of the Founder Notes.

Deferred financing costs. As of June 30, 2017, we had $12.5 million of deferred financing costs related to the credit facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $10.2 million related to the senior notes are netted with long-term debt on the condensed consolidated balance sheet as of June 30, 2017. Deferred financing costs of $2.3 million related to the credit facility are included in deferred financing costs, net on the condensed consolidated balance sheets at June 30, 2017. Amortization of deferred financing costs recorded for the six months ended June 30, 2017 and 2016 was $1.5 million and $2.0 million, respectively. Amortization of deferred financing costs recorded for each of the three months ended June 30, 2017 and 2016 was $0.5 million and $1.0 million, respectively. The amortization of these costs are included in interest expense on the condensed consolidated statements of operations.

The credit facility and the senior notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.

10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following provides the details of accounts payable and accrued liabilities:

	June 30, 2017		December 31, 2016
	(in thousands)
Capital expenditures	$	57,268	$	15,155
Revenues and royalties payable		20,559		12,187
Operating expenses/taxes		18,193		17,499
Interest		2,334		2,627
Compensation		3,208		5,302
Derivative settlement payable		208		1,126
Other		631		1,164
Total accrued liabilities		102,401		55,060
Accounts payable		27,824		29,174
Accounts payable and accrued liabilities	$	130,225	$	84,234

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11. COMMITMENTS AND CONTINGENCIES

Contingencies

Environmental claims: Various landowners have sued us in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our condensed consolidated financial statements at June 30, 2017.

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

Litigation:On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our wholly-owned subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish. Plaintiffs claimed they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located. Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. As of June 30, 2017, we have accrued approximately $3.2 million ($0.8 million in current liabilities and $2.4 million in other long-term liabilities) as the outcome of the litigation was deemed probable and estimable. The settlement requires payment over the term of six years.

On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP, our wholly-owned subsidiary (“OEA”), Alta Mesa Services, LP, our wholly-owned subsidiary (“AMS”), and the Company (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty. The suit against the AMH Parties alleges that the AMH Parties made improper deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells. The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case. In June 2017, the court administratively closed the case following mediation. Class settlement requires approval of the court after certain lengthy notice periods. We believe losses are probable in connection with this litigation; however, we have not accrued a loss contingency because we are currently unable to reasonably estimate an amount or range of loss.

Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business for which the outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

Performance appreciation rights: In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants are granted performance appreciation rights (“PARs”) with a stipulated initial designated value (“SIDV”). The PARs vest over time (as specified in each grant,

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typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the SIDV and the designated value of the PAR on the payment valuation date. The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally can be construed in accordance with the meaning of the term “change in control event”) or as selected by the participant, but no earlier than five years from the end of the year of the grant. Both the initial designated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event. After any payment valuation date, regardless of payment or none, vested PARs expire. During the first six months of 2017, we granted 308,800 new PARs with a SIDV of $40 and terminated 500 PARs with a SIDV of $40, resulting in 884,200 PARs issued at a weighted average of $37.91 as of June 30, 2017. We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan. We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote. Therefore, we have not provided any amount for this contingent liability in our condensed consolidated financial statements at June 30, 2017 or December 31, 2016.

12. SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas have been highly volatile and declined dramatically since the second half of 2014. Although oil and natural gas prices have recently begun to recover from lows experienced since such decline, forecasted prices for both oil and natural gas continue to remain depressed. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Continued depressed oil and natural gas prices, further 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 oil and natural gas reserves. Sustained low oil or natural gas prices may require us to write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil, natural gas and natural gas liquids price derivative contracts. See Note 7.

13. PARTNERS’ CAPITAL

Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in our partnership agreement. Our partnership agreement provides for two classes of limited partners. Class A partners include our founder and other parties. Our sole Class B partner is High Mesa. The Class B partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.

In connection with the sale of Series E preferred stock by our Class B partner on February 24, 2017, our General Partner, High Mesa and all of our Class A limited partners entered into a Fifth Amended and Restated Limited Partnership Agreement, and the owners of the General Partner entered into a Fourth Amended and Restated Limited Liability Company Agreement to provide for the Series E preferred stock in the distribution formula and certain other provisions of the amended agreements.

Contribution, Distribution and Income Allocation: All distributions under the partnership agreement shall first be made to holders of Class B units, until certain provisions are met. After such provisions are met, distributions shall then be made to holders of Class A and Class B units pursuant to the distribution formulas set forth in the partnership agreement.

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The Class B partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes.

Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the partnership agreement. A “Liquidity Event” is defined as the first to occur, in one or a series of related transactions, of (i) a disposition of all or substantially of the assets of High Mesa and its subsidiaries to a person that is not an affiliate of High Mesa, (ii) a disposition of all the equity securities of High Mesa, or (iii) the consummation of a public offering of the common equity securities of High Mesa or any of its subsidiaries that hold all of substantially all of High Mesa’s assets on a consolidated basis, and if the public offering is of a subsidiary of High Mesa, the subsequent distribution of the public company equity securities or proceeds obtained in the public offering to the holders of equity securities of High Mesa. The Class B partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.

On December 31, 2016, High Mesa purchased from BCE and contributed interest in 24 producing wells drilled under the joint development agreement to us. High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected during the first quarter of 2017. There were no contributions during the first half of 2016.

14. SUBSIDIARY GUARANTORS

All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes and our credit facility. Our condensed consolidated financial statements reflect the financial position of these subsidiary guarantors. The parent company, Alta Mesa Holdings, LP, has no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned and are not guarantors and are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to the parent company.

15. SUBSEQUENT EVENT

Alta Mesa Contribution Agreement. On August 16, 2017, we entered into a Contribution Agreement (the “Contribution Agreement”) with Silver Run Acquisition Corporation II, a Delaware corporation (“SRII”), High Mesa Holdings, LP, a Delaware limited partnership (the “AM Contributor”), High Mesa Holdings GP, LLC, a Texas limited liability company, our General Partner and solely for certain provisions therein, the equity owners of AM Contributor. Pursuant to the Contribution Agreement, SRII will acquire from the AM Contributor (i) all of its limited partner interest in the Company and (ii) 100% of the economic interests and 90% of the voting interests in our General Partner. In return, the AM Contributor will receive: (i) 220,000,000 common units as adjusted of SRII Opco, LP, a Delaware limited partnership and wholly owned subsidiary of SRII; (ii) $400 million in cash, which shall be contributed to us; and (iii) up to $800 million in earn-out consideration in the form of common units of SRII Opco, LP (the “Earn-out Consideration”). The Earn-out Consideration will be paid as set forth below if the 20-day volume-weighted average price (“VWAP”) of the Class A Common Stock of SRII (the “Class A Common Stock”) equals or exceeds the following prices:

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

Additionally, the AM Contributor will purchase non-economic capital stock of SRII, dedicated as Class C Common Stock (“Class C Common Stock”). The common units of SRII Opco, LP and corresponding Class C Common Stock are redeemable for Class A Common Stock beginning 180 days after the closing.

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The Contribution Agreement contains customary representations and warranties and pre-closing covenants, with the representations and warranties not survive the closing. Additionally, we have agreed to transfer to the AM Contributor prior to closing all assets and liabilities related to the non-STACK assets. The closing of the Contribution Agreement is subject to (i) the approval of the SRII stockholders, (ii) the simultaneous closing of the contribution agreement by and among SRII, KFM Holdco, LLC, Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”) and the equity owners party thereto pursuant to which SRII will acquire 100% of the outstanding membership interests in Kingfisher, (iii) a SRII Opco, LP leverage ratio of less than 1.5x, (iv) certain regulatory approvals and (v) the satisfaction or waiver of other customary closing conditions. The Contribution Agreement also contains certain customary termination rights, including if the transaction is not consummated by February 28, 2018.

Sixth Amended and Restated Agreement of Limited Partnership. On August 16, 2017, our General Partner, the AM Contributor and Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “RS Contributor”) entered into a Sixth Amended and Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”). The Amended Partnership Agreement reflects, among other things, certain changes in the ownership of the Company, and provides for certain preemptive rights, tag-along rights, and drag-along rights for the limited partners. In connection with Amended Partnership Agreement, the existing limited partners of the Company transferred their interests in the Company to the AM Contributor. The Amended Partnership Agreement also reflects the admission of the RS Contributor and the AM Contributor to the Company as limited partners, and provides for certain distribution rights for the Class A and Class B Limited Partners (as defined therein) with respect to the STACK and non-STACK assets.

The RS Contributor was admitted as a limited partner in connection with its $200 million capital contribution to us on August 17, 2017, in exchange for limited partner interests in Alta Mesa. We used all of the capital contribution to pay down our senior secured revolving credit facility.

Fifth Amended and Restated Limited Liability Company Agreement. On August 16, 2017, the owners of our General Partner entered into a Fifth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, show certain changes in the ownership of our General Partner and reflect that the holders of Class A Units (as defined therein) are entitled to 100% of the economic rights with respect to our General Partner and the holders of Class B Units (as defined therein) are entitled to 100% of the voting rights with respect to our General Partner.

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ANNEX A

LETTER OF TRANSMITTAL

ALTA MESA HOLDINGS, LP

AND

ALTA MESA FINANCE SERVICES CORP.

OFFER TO EXCHANGE

ANY AND ALL OUTSTANDING

7.875% SENIOR NOTES DUE 2024, SERIES A

THAT HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933

(CUSIP NOS. 021332AE1 & U02051AC1)

FOR

7.875% SENIOR NOTES DUE 2024, SERIES B

THAT HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933

(CUSIP NO. 021332AF8)

PURSUANT TO THE EXCHANGE OFFER AND PROSPECTUS

DATED OCTOBER 26, 2017

THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON NOVEMBER 27, 2017 (THE“EXPIRATION DATE”), UNLESS THE EXCHANGE OFFER IS EXTENDED BY THE ISSUERS.

The Exchange Agent for the Exchange Offer is U.S. Bank National Association and its contact information is as follows:

By Mail, Overnight Courier or in Person:

U.S. Bank National Association

Attn: Specialized Finance

111 Fillmore Avenue

St. Paul, MN 55107-1402

By Facsimile (for Eligible Institutions only):

(651) 466-7367

Attention: Specialized Finance

For Information or Confirmation by

Electronic Mail:

escrowexchangepayments@usbank.com

If you wish to exchange your issued and outstanding 7.875% Senior Notes due 2024, Series A (“old notes”) for an equal aggregate principal amount of 7.875% Senior Notes due 2024, Series B (“new notes”) pursuant to the exchange offer, you must validly tender (and not withdraw) old notes to the Exchange Agent prior to the Expiration Date.

We refer you to the Prospectus, dated October 26, 2017 (the“Prospectus”), of Alta Mesa Holdings, LP (the“Company”) and Alta Mesa Finance Services Corp. (the“Co-Issuer”, and together with the Company, the“Issuers”), and this Letter of Transmittal (the“Letter of Transmittal”), which together describe the Issuers’ offer (the“Exchange Offer”) to exchange their new notes that have been registered under the Securities Act of 1933, as amended (the“Securities Act”), for a like principal amount of their issued and outstanding old notes. Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

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The Issuers reserve the right, at any time or from time to time, to extend the Exchange Offer at their discretion, in which event the term “Expiration Date” shall mean the latest date to which the Exchange Offer is extended. The Issuers shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

This Letter of Transmittal is to be used by holders of the old notes. Tender of old notes is to be made according to the Automated Tender Offer Program (“ATOP”) of The Depository Trust Company (“DTC”) pursuant to the procedures set forth in the Prospectus under the caption “Exchange Offer—Procedures for Tendering.” DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent’s DTC account. DTC will then send a computer generated message known as an “agent’s message” to the Exchange Agent for its acceptance. For you to validly tender your old notes in the Exchange Offer the Exchange Agent must receive, prior to the Expiration Date, an agent’s message under the ATOP procedures that confirms that:

• DTC has received your instructions to tender your old notes; and

• you agree to be bound by the terms of this Letter of Transmittal.

BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.

Ladies and Gentlemen:

1. By tendering old notes in the Exchange Offer, you acknowledge receipt of the Prospectus and this Letter of Transmittal.

2. By tendering old notes in the Exchange Offer, you represent and warrant that you have full authority to tender the old notes described above and will, upon request, execute and deliver any additional documents deemed by the Issuers to be necessary or desirable to complete the tender of old notes.

3. You understand that the tender of the old notes pursuant to all of the procedures set forth in the Prospectus will constitute an agreement between you and the Issuers as to the terms and conditions set forth in the Prospectus.

4. By tendering old notes in the Exchange Offer, you acknowledge that the Exchange Offer is being made in reliance upon interpretations contained in no-action letters issued to third parties by the staff of the Securities and Exchange Commission (the“SEC”), including Exxon Capital Holdings Corp., SEC No-Action Letter (available April 13, 1989), Morgan Stanley & Co., Inc., SEC No-Action Letter (available June 5, 1991) and Shearman & Sterling, SEC No-Action Letter (available July 2, 1993), that the new notes issued in exchange for the old notes pursuant to the Exchange Offer may be offered for resale, resold and otherwise transferred by holders thereof without compliance with the registration and prospectus delivery provisions of the Securities Act (other than a broker-dealer who purchased old notes exchanged for such new notes directly from the Issuers to resell pursuant to Rule 144A or any other available exemption under the Securities Act and any such holder that is an “affiliate” of the Issuers within the meaning of Rule 405 under the Securities Act), provided that such new notes are acquired in the ordinary course of such holders’ business and such holders are not participating in, and have no arrangement with any other person to participate in, the distribution of such new notes.

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5. By tendering old notes in the Exchange Offer, you hereby represent and warrant that:

(a) the new notes acquired pursuant to the Exchange Offer are being obtained in the ordinary course of business of you, whether or not you are the holder;

(b) you are not engaging and do not intend to engage in the distribution of new notes within the meaning of the Securities Act;

(c) you are not an “affiliate,” as such term is defined under Rule 405 promulgated under the Securities Act, of the Issuers; and

(d) if you are a broker-dealer, that you will receive the new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities and that you acknowledge that you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

6. If you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities, you acknowledge by tendering old notes in the Exchange Offer, that you will deliver a prospectus in connection with any resale of such new notes; however, by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act.

7. If you are a broker-dealer and old notes held for your own account were not acquired as a result of market-making or other trading activities, such old notes cannot be exchanged pursuant to the Exchange Offer.

8. Any of your obligations hereunder shall be binding upon your successors, assigns, executors, administrators, trustees in bankruptcy and legal and personal representatives.

INSTRUCTIONS

FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER

1. Book-Entry Confirmations.

Any confirmation of a book-entry transfer to the Exchange Agent’s account at DTC of old notes tendered by book-entry transfer (a “Book-Entry Confirmation”), as well as Agent’s Message and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at one of its addresses set forth herein prior to 5:00 p.m., New York City time, on the Expiration Date.

2. Partial Tenders.

Tenders of old notes will be accepted only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The entire principal amount of old notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all old notes is not tendered, then old notes for the principal amount of old notes not tendered and new notes issued in exchange for any old notes accepted will be delivered to the holder via the facilities of DTC promptly after the old notes are accepted for exchange.

3. Validity of Tenders.

All questions as to the validity, form, eligibility (including time of receipt), acceptance, and withdrawal of tendered old notes will be determined by the Issuers, in their sole discretion, which determination will be final and binding. The Issuers reserve the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Issuers, be unlawful. The Issuers

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also reserve the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any old notes. The Issuers’ interpretation of the terms and conditions of the Exchange Offer (including the instructions on the Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as the Issuers shall determine. Although the Issuers intend to notify holders of defects or irregularities with respect to tenders of old notes, neither the Issuers, the Exchange Agent, nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any old notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders, unless otherwise provided in the Letter of Transmittal, promptly following the Expiration Date.

4. Waiver of Conditions.

The Issuers reserve the absolute right to waive, in whole or part, up to the expiration of the Exchange Offer, any of the conditions to the Exchange Offer set forth in the Prospectus or in this Letter of Transmittal.

5. No Conditional Tender.

No alternative, conditional, irregular or contingent tender of old notes will be accepted.

6. Request for Assistance or Additional Copies.

Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent using the contact information set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.

7. Withdrawal.

Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption “Exchange Offer — Withdrawal of Tenders.”

8. No Guarantee of Late Delivery.

There is no procedure for guarantee of late delivery in the Exchange Offer.

IMPORTANT: BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

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