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Alta Mesa Resources, Inc. STACK-Focused Investor Presentation October 2017
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Disclaimer FORWARD-LOOKING STATEMENTS The information in this presentation and the oral statements made in connection therewith include “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of present or historical fact included in this presentation, regarding Silver Run II’s proposed business combination with Alta Mesa Holdings, LP (“Alta Mesa”) and Kingfisher Midstream, LLC (“KFM”), Silver Run II’s ability to consummate the business combination, the benefits of the business combination and Silver Run II’s future financial performance following the business combination, as well as Alta Mesa’s and KFM’s strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, including any oral statements made in connection therewith, the words “could,” “should,” “will,” “may,” “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 management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Except as otherwise required by applicable law, Silver Run II, Alta Mesa and KFM 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 presentation. Silver Run II cautions 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 the control of Silver Run II, Alta Mesa and KFM, incident to the development, production, gathering and sale of oil, natural gas and natural gas liquids. These risks include, but are not limited to, commodity price volatility, low prices for oil and/or natural gas, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, processing volumes and pipeline throughput, uncertainties related to new technologies, geographical concentration of Alta Mesa’s and KFM’s 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, Alta Mesa’s and KFM’s ability to satisfy future cash obligations, restrictions in existing or future debt agreements of Alta Mesa or KFM, the timing of development expenditures, managing Alta Mesa’s and KFM’s growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects and limited control over non-operated properties and our ability to complete an initial public offering of the Kingfisher midstream business. Should one or more of the risks or uncertainties described in this presentation and the oral statements made in connection therewith occur, or should underlying assumptions prove incorrect, Silver Run II’s, Alta Mesa’s and KFM’s actual results and plans could differ materially from those expressed in any forward-looking statements. RESERVE INFORMATION Reserve engineering is a process of estimating underground accumulations of hydrocarbons 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 reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could impact Alta Mesa’s strategy and 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. Estimated Ultimate Recoveries, or “EURs,” refers to estimates of the sum of total gross remaining proved reserves per well as of a given date and cumulative production prior to such given date for developed wells. These quantities do not necessarily constitute or represent reserves as defined by the Securities and Exchange Commission (the “SEC”) and are not intended to be representative of anticipated future well results of all wells drilled on Alta Mesa’s STACK acreage. USE OF PROJECTIONS This presentation contains projections for Alta Mesa and KFM, including with respect to their EBITDA, net debt to EBITDA ratio and capital budget, as well as Alta Mesa’s production and KFM’s volumes, for the fiscal years 2017, 2018 and 2019. Neither Silver Run II’s nor Alta Mesa’s and KFM’s independent auditors or Alta Mesa’s independent petroleum engineering firm have audited, reviewed, compiled, or performed any procedures with respect to the projections for the purpose of their inclusion in this presentation, and accordingly, none of them expressed an opinion or provided any other form of assurance with respect thereto for the purpose of this presentation. These projections are for illustrative purposes only and should not be relied upon as being necessarily indicative of future results. In this presentation, certain of the above-mentioned projected information has been repeated (in each case, with an indication that the information is subject to the qualifications presented herein), for purposes of providing comparisons with historical data. The assumptions and estimates underlying the projected information are inherently uncertain and are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the projected information. Even if our assumptions and estimates are correct, projections are inherently uncertain due to a number of factors outside our control. Accordingly, there can be no assurance that the projected results are indicative of the future performance of Silver Run II, Alta Mesa or KFM or the combined company after completion of any business combination or that actual results will not differ materially from those presented in the projected information. Inclusion of the projected information in this presentation should not be regarded as a representation by any person that the results contained in the projected information will be achieved. USE OF NON-GAAP FINANCIAL MEASURES This presentation includes non-GAAP financial measures, including EBITDA and Adjusted EBITDAX of Alta Mesa. Please refer to the Appendix for a reconciliation of Adjusted EBITDAX to net (loss) income, the most comparable GAAP measure. Silver Run II, Alta Mesa and KFM believe EBITDA and Adjusted EBITDAX are useful because they allow Silver Run II, Alta Mesa and KFM to more effectively evaluate their operating performance and compare the results of their operations from period to period and against their peers without regard to financing methods or capital structure. The computations of EBITDA and Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. Alta Mesa excludes the items listed in the Appendix from net (loss) income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of Alta Mesa’s operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Alta Mesa’s presentation of Adjusted EBITDAX should not be construed as an inference that its results will be unaffected by unusual or non-recurring items. INDUSTRY AND MARKET DATA This presentation has been prepared by Silver Run II and includes market data and other statistical information from sources believed by Silver Run II, Alta Mesa and KFM to be reliable, including independent industry publications, government publications or other published independent sources. Some data is also based on the good faith estimates of Alta Mesa and KFM, which are derived from their review of internal sources as well as the independent sources described above. Although Silver Run II, Alta Mesa and KFM believe these sources are reliable, they have not independently verified the information and cannot guarantee its accuracy and completeness. TRADEMARKS AND TRADE NAMES Alta Mesa and KFM own or have rights to various trademarks, service marks and trade names that they use in connection with the operation of their respective businesses. This presentation also contains trademarks, service marks and trade names of third parties, which are the property of their respective owners. The use or display of third parties’ trademarks, service marks, trade names or products in this presentation is not intended to, and does not imply, a relationship with Silver Run II, Alta Mesa or KFM, or an endorsement or sponsorship by or of Silver Run II, Alta Mesa or KFM. Solely for convenience, the trademarks, service marks and trade names referred to in this presentation may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that Alta Mesa or KFM will not assert, to the fullest extent under applicable law, their rights or the right of the applicable licensor to these trademarks, service marks and trade names. 2
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Table of Contents I. Introduction II.Company Overview III.Our Upstream Assets IV.Our Midstream Assets V.Financial SummaryMulti-Well Pad Drilling KFM Cryogenic Processing Plant VI.Valuation and Timeline Appendix 3
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Introduction
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Creation of a Pure-Play STACK Enterprise Silver Run II has agreed to merge with Alta Mesa and Kingfisher Midstream (collectively renamed Alta Mesa Resources, Inc.), creating a world class energy company with a high-quality, integrated, and concentrated asset base in the core of the STACK oil play ⎻ Anticipated closing of transaction in Q4 2017 ⎻ Implied Firm Value of $3.8bn at $10 per share This transaction integrates premier upstream and midstream assets developed by a tenured executive team with unmatched complementary experience and track records Pro Forma Organizational Structure Alta Mesa Resources, Inc.: AMR Jim Hackett, Executive Chairman Hal Chappelle, President & CEO Finance &UpstreamKingfisherCorporate AccountingOperationsMidstreamDevelopmentLand Mike McCabeMike EllisJim HackettTim TurnerDavid Murrell Vice President and CFOFounder and COOCOOVice PresidentVice President Top 10 managers average >25 years industry experience and >12 years at Alta Mesa 5
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Silver Run II Delivering on Investment Criteria Upstream Midstream Economic significantlyCompetitively-positioned below current oil price assets that benefit from strong supply/demand fundamentals High margin core basin with low field break-evens, and extensive inventoryExpansion opportunities in rapidly growing basin Multiple stacked pays Locked-in base returns through High-quality assets with stable fee-based contracts significant unbooked resource potential Assets with return asymmetry from incremental volumes, Opportunities to improvemoderate margin exposure, costs through technology and/or organic growth projects Opportunity to expand through technology andSynergy with existing upstream portfolio acquisitions Combined upstream and midstream company allows for significant value uplift from financial optimization 6
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Pure Play STACK Company Capital efficient liquids upstream growth with value-enhancing midstream World class upstream asset with long inventory of highly economic drilling locations —Highly contiguous ~120,000 net acres with substantial infrastructure in core of STACK—Oil-weighted resource with less than $30/BBL breakeven; >80% single-well rate of return1 —~4,2002 gross primary locations; 13,000+ possible in new acreage, down-spacing and additional zones —Oil-weighted production in early well life enhances present value (first month 2-stream production at 82% oil with 57% of the type well EUR oil produced in the first five years); consistent GOR profile —Industry-leading growth; 2-year expected EBITDA CAGR of 128% Top-tier operator with substantial in-basin expertise and consistent well results —200+ horizontal STACK wells drilled across entirety of Kingfisher acreage instills confidence in type well EURs—Consistency and geographic breadth of well results affirms repeatability—Demonstrated ability to manage a large development program – average of 6 rigs running YTD 2017—Robust acquisition opportunities coupled with track record as an aggregator Highly strategic and synergistic midstream subsidiary with Kingfisher Midstream —Flow assurance de-risks production growth —Purpose built system designed to accommodate third party volumes – currently 6 contracted customers with approximately 300,000 gross dedicated acres—Strategic advantage supporting acquisition of new upstream assets—Opportunity to monetize Kingfisher Midstream through a 2018 IPO, and fund upstream capital needs through IPO proceeds, future drop downs, and GP / IDR distributions Financial strength and flexibility to execute business plan through the cycle; cash flow positive in 2019 —Team has demonstrated the discipline to survive and grow through cyclical downturns—Development plan is fully-financed 1 Osage type curves assume 17% royalty burden and $3.2mm D&C well cost. Adjusted for transportation costs paid to KFM. Excludes $1.25 / bbl oil transportation costs. Broker Consensus price deck. 7 2 Does not include additional undeveloped locations on ~20,000 net acres recently acquired in the Major County Acquisition.
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Transaction Summary Sources & Uses ($MM)Implied Firm Value ($MM)Post-Transaction Ownership3 SourcesShares Outstanding388.6KFM Legacy Owners’ Rollover Equity$1,993Owners 14% Share Price$10.00 Silver Run II Cash Investment999 1Legacy Alta Riverstone Cash Investment 2600Equity Value$3,886Mesa Owners Total Sources$3,592Less: Cash(551)37% Total Cash Sources$1,599Riverstone Plus: Debt50022% 2 UsesFirm Value$3,836 Legacy Owners’ Rollover Equity$1,993TRUELegacy Cash to KFM Owners800Transaction MultiplesSRII Owners Cash to Alta Mesa Balance Sheet & Interim Capex Funding79927% FV / 2018E EBITDA ($543MM)7.1x Total Uses$3,592 Total Cash Uses$1,599FV / 2019E EBITDA ($1,019MM)3.8x Ownership at Various Share Prices 27%27%26%26%25%24% 222222222121 141415151514 373737373940 $10.00$11.50$14.00$16.00$18.00$20.00 Legacy Alta Mesa OwnersKFM OwnersRiverstoneLegacy SRII Owners Minimal dilution to investors even when full earnout is realized at 2x transaction share price Note: Sources & Uses includes estimates of transaction fees, debt at close, and other transaction closing adjustments, and is subject to change. 1 SPAC capital net of deferred underwriting expense. 2 Reflects Riverstone and related investment vehicles, and incudes $400 million of shares of Class A Common Stock and warrants to be purchased from Silver Run II under the forward purchase agreement dated as of March 17, 2017. Does not include additional $200 million commitment from Riverstone under a forward purchase agreement entered into in connection with the proposed transaction. 3 Assumes none of legacy Silver Run II owners exercise their stockholder redemption rights and does not give effect to any shares of Class A Common Stock that may be acquired by the Alta Mesa or KFM sellers in connection with certain earn-out provisions in the applicable contribution agreements. 8
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Transaction Metrics Imply a Highly Attractive Value Opportunity Firm Value / 2018E EBITDA1 Firm Value / 2019E EBITDA1 7.4x 6.1x 6.1x 2 Mesa 3.1x Alta Alta MesaPeer MedianAlta MesaPeer Median 14.1x 11.1x 2 KFM7.3x 4.2x KFMPeer MedianKFMPeer Median Alta Mesa peer set includes MTDR, DVN, XEC, LPI, RSPP, CLR, CPE, NFX. KFM peer set includes HESM, EQM, AM, NBLX. AMR peer set includes MTDR, DVN, XEC, LPI, RSPP, CLR, CPE, NFX, HESM, EQM, AM, NBLX, AR, EQT, CNX. Excludes equity promote. 9
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Company Overview
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Alta Mesa Resources Focused on development and consolidation in the STACK Upstream MetricsContiguous Core Position in STACK Oil Window Net STACK Surface Acres~120,000 Current Production (BOE/D)~20,000 % Liquids69% Resource Potential (MMBOE)1>1,000 Breakeven Oil Price, $/BBL WTI< $30 Single-well IRR>80% CHK Gross Identified Base Locations14,196SD SDCHK CHKMRO CHK Operated STACK Hz. Wells Producing /167 / 205 Operated STACK Hz. Wells Drilled3NFXCHK 2017 YTD Average Rigs6AMR MROAMR DVNAMR Midstream MetricsDVN 60 / 3504DVNMRO Natural Gas Processing Current / YE 2017CLRDVNNFX MMCF/DNFX CLRMRO Pipelines300+ milesMRO CLRNFX Dedicated Acreage~300,000 grossDVN MRO MRO acres CLRMRO 50 MBBL with 6CLR Storage Capacityloading LACTs5Permits 180 DaysExisting KFM PlantCompressor StationKingfisher Midstream System 6 Source: Public Filings, Investor Relations. Note: All reserve figures per NYMEX strip pricing as of 12/31/2016 close; acreage as of 7/20/2017. 1 Does not include additional resource potential or undeveloped locations on ~20,000 net acres recently acquired in the Major County Acquisition. 2 Includes additional locations from downspacing in the Oswego, Meramec, Lower and Upper Osage formations as well as additional locations in the Big Lime, Cherokee, Manning, Chester, Woodford and Hunton formations. 3 Horizontal wells drilled as of 8/14/17 4 Includes 90 MMCF/D offtake processing contracted 3Q 2017. 5 Lease Automatic Custody Transfer units.11 6 Operators with 2 rigs or fewer running.
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Progressive Execution through Cycles Track record of growth in production, reserves, leasehold Net STACK Acreage ~ 120,000Alta Mesa Footprint 102,466 73,512 40,58744,506 YE 2013YE 2014YE 2015YE 2016Current Total Net Production (MBOE/D)1 22.2 13.1 8.8 4.8 1.01.7 20122013201420152016June 2017 NYMEX Proved Reserves (MMBOE)2 143.6 68.3 27.6 17.0 8.7 YE12YE13YE14YE15YE 16 Disciplined acreage aggregation focused primarily on “bolt-on” acquisitions to increase contiguous position as STACK play has emerged Production has responded to systematic de-risking, delineation, and now development of acreage Proved reserves growth reflects significant continuity of producing acreage in Osage, Meramec, and Oswego Source: Company data, Public Filings, IHS Herolds, RigData. 1 Inclusive of Net Production from Bayou City JV. 2012 and 2013 data reflects occurrence date and not accounting date LOS, due to the reasoning that occurrence date method incorporated a change in NGL accounting; whereas accounting date LOS does not. 2 Proved reserves based on NYMEX pricing. YE 2016 proved reserves as of 12/31/2016 close. 129.6 MMBOE YE 2016 proved reserves based on SEC pricing. 12
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Strong Upstream and Midstream Fundamentals High quality rock and robust rig activity Major U.S. Oil Plays – Breakeven Prices ($/BBL)1Alta Mesa Type Well IRR3 14366676103% .92% 1653132333434 . 7$$$ 0$ . 4272727 24$$$ $ 57% 82% ----73% OilAOil sin 2land A&BaBasin XYatearnes44% dBasK Mirem p-—Updipc ampa Wo lfcampmec e ssuredWattenbergWoodford STACKolfawMer Pr- XRLa ware l-4 re MesaCoreDeeDelFord W.S TACKBasin Core. WolfcaSCOOP CondenTrough$40.00/bbl / $2.50/MCF$50.00/bbl / $3.00/MCFBroker Consensus S ReevesNE AltaOvJaglGen 2.0 (59 wells) Gen 2.5 (95 wells) D KFM Acreage Dedications / Resource Allocations Breakdown5KFM Gas Inlet Volumes by Producer (MMCF/D) (‘000 of gross acres)% Alta69%52%55% Mesa(6) 175541 366639 393 193 86118 5022128239 Existing InfrastructureExpansionExisting + ExpansionAdditional Acreage2017E2018E2019E Under NegotiationAlta MesaOther Producers (Existing)Other Producers (Expansion) Source: BakerHughes, Wall Street Research. 1 Based on 15% IRR hurdle. Assumes gas price deck of 2017: $3.10/mcf; 2018: $2.99/mcf; 2019: $2.83/mcf; 2020: $2.82/mcf; thereafter: $2.83/mcf. 2 AMR breakeven price company prepared. Based on AMR 651 MBOE mean type curve. 3 Osage type curves assume 17% royalty burden and $3.2mm D&C well cost. Adjusted for transportation costs paid to KFM. Excludes $1.25 / bbl oil transportation costs. 4 Assumes Broker Consensus Price Deck (2017: $51.16/bbl / $3.16/mcf; 2018: $54.90/bbl / $3.14/mcf; 2019: $58.00/bbl / $3.05/mcf and held flat thereafter). 5 Not inclusive of producer customers’ entire gross acreage position; additional gross acreage proximate to KFM available for gathering and processing services. Includes additional acreage to come and/or under negotiation.13 6Percentage of Existing Infrastructure shown.
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KFM is Value Accretive to Alta Mesa Vertical integration yields substantial strategic and financial benefits Rapidly Expanding G&P Complex KFM is positioned to capture volume growth from the STACK in the Heart of the STACK Acreage dedications / resource allocations of ~300,000 gross acres Total processing capacity is expected to be 350 MMCF/D in 4Q 2017, Gathering, Processing and Marketincluding 90 MMCF/D of additional offtake Access Support Production Substantial firm transport to support future growth Bundled Natural Gas Residue KFM capable of providing takeaway solutions to end-markets today Solution Enhances Marketability KFM has secured firm takeaway capacity on PEPL and OGT KFM well positioned to serve other operators; major gas pipeline Competitive Advantage inprojects recently announced by others are more costly and less timely Acquisitions Modern processing recoveries and priority residue access to premium markets should result in higher netbacks Expansion focused on the next stage of STACK development KFM’s Expansion Offers Anchored by Alta Mesa acreage Complementary, High-Growth Development Project Limited G&P infrastructure provides opportunity for KFM expansion KFM involved in negotiations with anchor customers Future opportunity to monetize KFM and fund upstream capital needs Midstream Business Can Supportthrough an MLP IPO, drop downs, and GP / IDR distributions Future Capital Needs Volumetric growth from third-party development provides upside Attractive trading multiples and GP/IDR optionality / currency 14
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Market Multiples for Midstream Higher than Upstream Alta Mesa owners to capture GP / IDR cash flow / multiple arbitrage Illustrative Value Accretion from GP StructureIllustrative Midstream Value Creation ($MM)1 Potential to continue to benefit from cash flows through retained LP, GP, and IDR ownership interest 26.5x $5,477 $4,498$979 14.1x $2,102 $2,395 7.5x Upstream MedianMidstream MedianGP MedianValue of MarginMLP MultipleMLP ValueMultiplePotential in UpstreamExpansionExpansionMidstream Value (MLP + GP) Valuation Arbitrage Likely valuation uplift (multiple arbitrage vs. traditional peer group) 30.0x27.3x 25.6xGP Median: 26.5x TDA 25.0x I EB 20.0x E14.6x15.3xMidstream Median: 14.1x 8 15.0x13.7x 1 011.0x 2Upstream Median: 7.5x / 10.0x7.8x7.8x7.2x FV5.8x 5.0x 0.0x AMGPEQGPEQMAMHESMNBLXDVNXECCLRNFX Upstream4.9x5.6x8.1x6.8x Multiple MidstreamGPUpstream 1 Illustrative KFM future value expansion assuming KFM 2019E EBITDA of $318mm.15
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Upstream Consolidation & Midstream Expansion Neighboring operators provide future upstream and midstream consolidation opportunities Recent Major/Blaine County acquisition by Alta Mesa adds catalyst of ~20,000 dedicated acreage Offset operator activity in the Western STACK reflects compelling economics driving producer interest and investment KFM has identified and plans to capitalize on this midstream opportunity and is rapidly commercializing this growth initiative KFM is in the process of securing acreage dedications and other resource allocations in the Western STACK 16
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Our Upstream Assets
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Solid Well Results De-Risk Kingfisher Acreage Representative wells across 11 townships Ke y 2 0 17 Alta Me sa We lls We llTa rge tIP 3 0(BOE/D) Aces High 1606 4- 11MHOsage823 Coleman 1706 6A- 9MHU Osage/L Meramec514 Dalwhinnie 1605 1- 31MHOsage702 Fazio 1705 1- 13MHOsage909 Hasley 1605 1- 28MHOsage549 Huntsman 1506 2- 23MHMeramec598 Macallan 1806 4- 17MHOsage643 Odie 1606 1- 12MHU Osage/L Meramec849 Peat 1606 1- 26MHOsage522 Pollard 1805 3- 2MHOsage507 Red Queen 1506 1- 1MHOsage509 Shiner 1505 1- 3MHOsage585 Speyside 1606 1- 27MHOsage997 Yellowstone 1505 4- 8MHOsage740 Key 2017 Wells LateralEUREUR/‘000IP90IP90IP90/‘000 Well Name1Length(MBOE)2 Lateral ft2 (BOE/D)% OilLateral ft Operated 1Barbara 1706 3-22MH4,81257912034682%72 2Beyer 4-6H4,45286319450575%113 3Boecher 1706 4-19MH4,83257411956072%116 4Bollenbach 1705 4-21MH4,82099420618555%38 5Bollenbach 1705 6-30MH4,7951,19825043692%91 6Brown 1706 6-27MH4,85083917331676%65 7Clark 1705 5-12MH4,65782717861585%132 8Cleveland 1805 2-26MH4,64568614845177%97 9Dixon 1505 3-16MH4,85865713532581%67 10EHU 219H4,95079016012388%25 11EHU 220H3,65167818621691%59 12EHU 235H5,30055910635789%67 13Evelyn 1706 5-18MH4,85757511862187%128 14Francis 1706 5-8MH4,85666413734969%72 15Gilbert 1706 6-21MH4,73859012540959%86 16Hawk 1906 7-13MH4,81354011221680%45 17Helen 1605 5-33MH4,62065214133177%72 18Hoskins 1705 2-9MH4,69393219950785%108 19James 1706 5-26MH4,74873815535279%74 20Lankard 1706 6-34MH4,8558471741,29158%266 21LNU 16-2H4,78887318228289%59 22LNU 49-4H4,51875616751879%115 23Mad Hatter 1506 2-34MH4,67063213529490%63 24Martin 1505 4-9MH4,79562012927864%58 25Matheson 1705 5-10MH4,76572915344879%94 26Mitchell 1806 2B-27MH4,59864614031181%68 27Oak Tree 1605 2-30MH4,74481317163469%134 28Oltmanns 1805 6-14MH4,93082216763170%128 29Oswald 1705 6-28MH4,8151,14423827866%58 30Pinehurst 1706 5-5MH5,06167213357275%113 31Redbreast 1505 4-7MH4,70965513925173%53 32Rigdon 17015 6-11MH4,82772515069782%144 33Rudd 1605 2A-5MH4,01052013048958%122 34Three Wood 1505 4-17MH4,63462913632176%69 35Todd 1706 6-4MH5,01994618859968%119 36Vadder 1805 2-12RMH4,50466914854263%120 37Wakeman 1706 6-25MH4,84292519178762%162 38Weber 1806 3-22MH4,79764613511275%23 39White Rabbit 1506 2-27MH4,81163313242891%89 Non-Operated 40Deep River 30-1MH5,586NA8932441%58 41Holiday Road 2-1H5,100NA6715385%30 42King Koopa 1606 2UMH-224,691NA8338060%81 43OOID 1OH-245,3571,45927253388%99 44Post 1706 1-30MH4,9194569346166%90 45Ruzek 1H-3X6,8724987268867%100 46Trifecta 1807 20H-14-14,34666215255592%128 Source: Alta Mesa Year-End Reserve Report. For non-Alta Mesa operated wells, IHS Enerdeq. Note: EURs based on NYMEX 2016 pricing. Does not include additional resource potential or undeveloped locations on ~20,000 net acres recently acquired in the Major County Acquisition. 1 Includes 7 wells not operated by Alta Mesa. Includes wells operated by Chaparral, GST, MRO and NFX. 2 3-Stream EUR assuming 75.4 BBL/MMCF NGL yield and 15.9% shrink. 18
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Alta Mesa Wells Among Top STACK Oil Producers Top Cumulative Oil Producing STACK Wells Osage/Meramec/Oswego STACK Public Operator Producing Wells (2012-2Q 2017)1Producing Wells of Selected Permian Operators (2012-2Q 2017)2 255 176194 159 158 5856 43 3429 NewfieldAlta Mesa 3Devon/FelixMarathon/PayrockContinentalCimarexChesapeake DiamondbackParsleyRSP Permian Number of Top 100 Wells in the Oil and Updip Oil Windows by Operator, Measured by 60-Day Cumulative Oil Production4 24 22 2020 14 Alta MesaMarathon/NewfieldDevon/Other PayrockFelix Source: IHS Enerdeq, Drillinginfo. Note: Publicly disclosed Alta Mesa well include those assigned to Oklahoma Energy Acquisitions LP and Hinkle Oil & Gas Inc. There are 8 Alta Mesa wells classified as Mississippian Lime in the public data but are either Osage or Meramec. 1 Based on publicly disclosed data for wells producing in Kingfisher, Blaine, Canadian, and S. Garfield counties. Excludes wells for which Woodford is primary target. 2 Midland Basin wells only. The Midland Basin consists of Andrews, Dawson, Ector, Glasscock, Howard, Martin, Midland, Reagan and Upton counties. 3 176 wells online early September 2017.19 4 Top Osage/Meramec wells (excluding Oswego and Mississippian Lime) in Updip Oil and Oil window based on 60-Day Cumulative Oil Production (BBLS) per 1,000 Ft. of Lateral.
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Low Cost Operator Peer leader in operating cost and capital efficiency Recycle Ratio1 Illustrative KFM 4.0xMargin Uplift 3.4x 3.2x3.1x 1.8x 3.7x1.7x 1.1x 0.8x CLRAMRFANGPERSPPXECNFXMRODVN SEC Future Development Cost Per Proved Undeveloped BOE ($ / BOE)2Q2 2017 LTM LOE ($ / BOE)4 $24.21 $6.86 $13.78$4.43$4.71$4.83 $4.14$4.22 $10.02$3.62$3.74 $8.53$8.77$8.89$9.37$3.00With $7.96SWD $6.33credits $2.02 $2.02 AMRXECCLRPEFANGRSPPNFXMRO3DVN 3XECNFXCLRPEAMR 5MROFANGRSPPDVN Alta MesaSTACK PeersPermian Peers Source: Recycle Ratio and SEC Future Development Cost Per Proved Undeveloped BOE from Public Filings as of 4Q 2016. Peer LOE data from SEC filings and public press releases. 1 Calculated as 4Q16 unhedged EBITDAX/BOE divided by organic F&D. Includes Q4 acquired BCE wells in calculation. Organic F&D defined as Future Development Costs / PUD volumes per SEC filings and excludes reserves added through acquisitions. 2 Calculated as future development costs divided by proved undeveloped reserves. Shown as of 12/31/2016. 3 MRO and DVN PUD F&D evaluated based on US assets only. 4 Does not include gathering & transportation. 5 LTM 6/30/2017 excluding nonrecurring expenses. Represents NE Kingfisher Hz only. 20
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STACK Development Early stages of development on de-risked Kingfisher acreage Base Case Development Concept2017 Development Plan Oswego/ Big Lime ft 1501,500’ 1,500’ ft1,500’ Meramec 450 750’ 750’750’Osage 750’ 750’ ft750’ 5501,500’ 1,500’ 750’1,500’ 750’ 750’ 750’ 750’ 750’ Alta Mesa Development Strategy Meramec/Osage – Continue to optimize lateral spacing, landing zone, and completion; transition to development mode; accelerate infrastructure investments to stay ahead of pattern development Oswego – Continue operated and non-operated development Manning – Initiate horizontal program with one well on flowback; drill 3 wells by YE 2017 Acreage – Continue bolt-on, farm-in, and pooling acquisitions New Areas / Zones – Delineate, de-risk and aggregate Blaine/Major County acreage;2017 Development Plan Wells test horizontal potential of additional zones to increase inventoryAlta Mesa Acreage 21
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Asset Value of AMR’s STACK Position ~$6B PV-10 Value in Identified Gross Locations before downspacing 753 Alta Mesa’s ~4,200 Identified Gross Drilling2,214 Locations are the primary436 focus of the near-term872 174 484 development plan488 2,24213,659 516 1,284 4848,238 3,7124,196 Meramec/OsageOswegoCurrent IdentifiedKingfisherKingfisher Current IdentifiedAdditionalMajor/BlaineMajor/BlaineOther AdditionalTotal Potential (12 WPS)(2 WPS)TargetedDownspacing Downspacing to and DownspacingFormations -Meramec/Osage Meramec/OsageFormationsLocations Locationsto 20 WPS 227 WPS 3 LocationsCurrent TestingPrimary LocationsDownspacing Locations Osage/MeramecOswegoBig LimeManningHuntonWoodfordOther4 NAV from Identified Drilling Locations ($MM) $1,564$5,752 $3,826$199$54($307) $417 Implied PV-10 Upside Area of FocusValue ($MM) Manning 1$484 2 Kingfisher Downspacingto 20 WPS1,233 3 Kingfisher Downspacingto 27 WPS1,294 Major/Blaine Meramec/Osage Primary Locations 1597 Major/Blaine Meramec/Osage Downspacing1251 5 Upside KFM Margin Uplift1,398 Big LimeUnspecified HuntonUnspecified WoodfordUnspecified CherokeeUnspecified ChesterUnspecified Total Upside Potential$5,258 Total Asset Value$11,010 PDPMeramec/OsageOswegoDrillCoKFM Margin UpliftNet Debt andBase Case Net OtherAsset Value Adjustments6 Note: PV-10 figures as of 7/1/2017. Reflects Generation 2.0 Type Curve. Assumes Broker Consensus Price Deck (2017: $51.16/bbl / $3.16/mcf; 2018: $54.90/bbl / $3.14/mcf; 2019: $58.00/bbl / $3.05/mcf and held flat thereafter). Adjusted for transportation costs paid to KFM; excludes $1.25 / bbl oil transportation costs (“KFM Margin Uplift”). 1 Assumes ~$1.0mm average PV-10/Mississippian well and ~$0.6mm average PV-10/infill well based on current drill program. Major/Blaine value assumes 8 Mississippian base WPS, 4 Mississippian infill WPS, and 2 WPS in additional formations. 2 Low Risk downspacing of Meramec/Osage to 16 WPS (1,284 locations) and Oswego to 4 WPS (516 locations). 3 Additional downspacing of Meramec/Osage to 23 WPS (2,242 locations). 4 Other Formations include Cherokee and Chester. 5 KFM Margin uplift applied proportionately to Manning and Major/Blaine county development based on relative KFM Margin impact to base development and downspacing development opportunity. 6 Adjusts Assumes for net debt, hedges, pipeline, facilities and other capex, and G&A. Assumes 2018E Upstream G&A capitalized at 7.5x. Assumes pro forma net debt at transaction close based on Alta Mesa Q2 2017 revolver balance outstanding.22
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Our Midstream Assets
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Kingfisher Midstream Overview Acreage Dedications KFM Overview ·Current natural gas processing of 60 MMCF/D Cushing ~60 mi.– Year end processing capacity of 350 MMCF/D includes 90 MMCF/D offtake processing put in place during 3Q17 and completion of 200 MMCF/D cryo plant in 4Q17 ·300+ miles of pipelines, with another 68 miles under construction ·~300,000 gross dedicated acreage from Alta Mesa and third parties ·50 MBBL of storage capacity with 6 loading LACTs ·3 NGL bullet tanks: 90,000 gallon capacity ·1,200 BBL/D condensate stabilizer ·54 central delivery point receipt producer connections serve 188 units ·Over 7,000 gross locations associated with customers KFM EBITDA Estimates ($MM) $318 $184$63 $44 $42$255 $38$4$141 2017E2018E2019E Existing InfrastructureExpansion Alta Mesa & Third Party Average Throughput (MMCF/D) 639 393207 146193 8613118 5022128239 2017E2018E2019E Alta MesaThird Party (Existing)Third Party (Expansion) Alta Mesa & Third Party Year End Rig Count 32.533.5 22.59.09.0 6.012.512.5 9.5 7.011.012.0 2017E2018E2019E Alta MesaThird Party (Existing)Third Party (Expansion) 24
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Strong Producer Commercial Commitments Customer Acreage Positions Contracted Customers 14 year remaining term on fixed-fee natural gas and crude agreement 9 year remaining term on fixed-fee natural gas agreement 9 year remaining term on fixed-fee and POP natural gas agreement Life of Lease – fixed-fee natural gas agreement 10 year remaining term on fixed-fee and POP natural gas agreement 15 year remaining term on fixed-fee natural gas agreement Above represents committed acreage to KFM as well as gross acres surrounding existing agreements.25
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KFM Will be Uniquely Positioned MLP strongly supported by Alta Mesa organic production 1 Only Pure-Play STACK E&P Sponsored MLP 2AMR Leads Peer Group on Production Growth E&Ps with Public Midstream Affiliates2017E – 2019E Debt- Adjusted Production Growth per Share 82% Bakken Appalachian Basin 37% DJ Basin31% STACK Anadarko 18%16%14%13%13% PermianBarnett10% Eagle FordAMRCPERSPP CLRXECNFXMTDRDVNLPI 3…And is Well Capitalized4Driving Superior EBITDA Growth Net Debt / 2018E EBITDAConsolidated 2017E – 2019E EBITDA CAGR 2.4x2.5x 128% 1.9x 0.8x 40% 33% 20%19% NM AMR + KFMEQTHESNBLARAMR+KFMEQTARHESNBL Integrated Upstream/Midstream Peers PDP value adjusted at $15,000 / BOE/D. Alta Mesa PDP value assumes Broker Consensus Price Deck (2017: $51.16/bbl / $3.16/mcf; 2018: $54.90/bbl / $3.14/mcf; 2019: $58.00/bbl / $3.05/mcf and held flat thereafter). Excluding the Major County acreage, our adjusted $ / net acre is $17,158 / acre. 26
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Financial Summary
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Financial Strategy & Pro Forma Financial Impacts Financial Strategy Visible path to positive free cash flow with fully-financed development plan Significant Near-term production growth further de-risked Financialby KFM takeaway capacity Flexibility Pro forma for this transaction, financial flexibility in place to pursue opportunistic acquisitions with a goal toward consolidation of the STACK region Maintain conservative credit metrics of < 2.0x Maintainleverage through the cycle Conservative Preserve an optimal debt maturity profile Balance Sheet Maintain simplified balance sheet Prudent capital budget focused on securing leasehold and developing existing acreage Protect Cash Ensure capital budget is flexible to future Flowchanges in commodities and/or service costs Continued rolling hedge strategy to protect revenues and support development program ~50% and ~13% oil hedged in 2018 and 2019 respectively, and ~22% gas hedged in 2018 Capitalization at Announcement Current ($ in millions, unless specified)Alta MesaKFMAdjustmentsPro Forma Cash and Cash Equivalents$5$28$5171$551 Revolving Credit Facility269 2$0(269) 20 7.875% Senior Notes due 20245005003 Total Debt$769$0($269)$500 Net Debt763(51) Financial and Operating Statistics 2017E EBITDA$155$42$197 2018E EBITDA358184543 2019E EBITDA7013181,019 Credit Metrics Net Debt / 2017E EBITDANM 2018E EBITDANM 2019E EBITDANM Liquidity Expected Borrow ing Base$315$200$515 Less: Amount Draw n269(269)0 Expected Borrow ing Base Availability$46$515 Plus: Cash and Cash Equivalents5551 Liquidity$52$1,066 1 Cash to balance sheet includes funding for interim cash needs until closing and anticipated transaction adjustmentsof $13mm. 2 Current revolving credit facility balance as of 8/10/2017 does not include approximately $5mm of letters of credit. 3 Change of control not triggered for 2024 Senior Notes upon execution of transaction.28
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Summary Financial Projections ($ in millions unless otherwise noted) Average Net Daily Production (BOE/D)EBITDA(X)Capital Expenditures (excl. DrillCo Funds)2 $925 68,900$1,019 $63$171$785 2,003$35 $255$202$139 38,510$543$474 1,698$44$41 66,897$84 $141 20,841$701$552$611 54936,812$197 $4$358$349 20,292$38 $155 201720182019201720182019201720182019 Alta MesaDrill CoAlta MesaKFM (Existing)KFM (Expansion)Alta MesaKFM (Existing)KFM (Expansion) Free Cash FlowLiquidity3Forecast Total Wells by Year $195$948 $871239 $144207 $51$676 ($237)($233)120 ($83) ($189) ($320) ($422) 201720182019 201720182019201720182019 Avg.4 Rigs61011 Note: Assumes Broker Consensus Price Deck (2017: $51.16/bbl / $3.16/mcf; 2018: $54.90/bbl / $3.14/mcf; 2019: $58.00/bbl / $3.05/mcf and held flat thereafter). 1 Hedges as of 9/25/2017. 2 DrillCo Funds is Bayou City JV deal. 3 Assumes borrowing base increase from $515mm to $665mm in 2018 and includes funding for interim cash needs until closing and KFM revolving credit facility. Assumes combined FCF deficit of ($118) mm from current until year-end 2017.29 4 Average 2017 YTD rigs.
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Valuation and Timeline
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Upstream Valuation Benchmarking ($ in millions unless otherwise noted) Firm Value / 2018E EBITDAFirm Value / 2019E EBITDA 8.0x7.8x7.8x 7.5x7.3x7.2x 6.8x 6.3x6.3x6.2x6.2x 6.1x6.0x 5.8x 5.1x 4.6x4.4x 3.1x MTDRDVNXECLPIRSPPCLRCPEAMRNFXDVNXECLPICLRMTDRRSPPNFXCPEAMR Adjusted Firm Value / Net Acres2017E – 2019E Production CAGR $30,011 82% $22,063 $14,18043% $12,34433% 20%19%18%18%17%16% 6% GPOR / Vitruvian 1DVN / Felix 1AMR 2MRO / Payrock 1AMRCPERSPPMTDRARCNXEQTCLRNFXDVN PDP value adjusted at $15,000 / BOE/D. Alta Mesa PDP value assumes Broker Consensus Price Deck (2017: $51.16/bbl / $3.16/mcf; 2018: $54.90/bbl / $3.14/mcf; 2019: $58.00/bbl / $3.05/mcf and held flat thereafter). Excluding the Major County acreage, our adjusted $ / net acre is $17,158 / acre. 31
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Benchmarking KFM Against High Growth G&P Peers ($ in millions unless otherwise noted) Firm Value / 2018E EBITDAFirm Value / 2019E EBITDA 15.3x14.6x 13.7x 11.0x11.7x11.3x11.0x 7.3x8.0x 4.2x HESMEQMAMNBLXKFM1EQMAMHESMNBLXKFM Midstream 2017E – 2019E EBITDA CAGRConsolidated 2017E – 2019E EBITDA CAGR 175%128% 47%40% 28%33% 27%26%20%19% KFMNBLXAMHESMEQMAMR+KFMEQTARHESNBL Integrated Upstream/Midstream Peers 32
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Anticipated Transaction Timeline Date Event Late-September 2017 File preliminary proxy statement / marketing materials with the SEC October 2017 Transaction marketing Late-November 2017 Definitive Proxy mailed to shareholders of record December 2017 Anticipated closing 33
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Appendix Team
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Our Strategic Vision: Premier STACK Operator Disciplined Execution Optimize returns on existing assets through technology and continuous learning Minimize operating costs by leveraging infrastructure and operating team Delineate and develop established productive zones – Big Lime, Manning, Cherokee sands, Woodford, Hunton Develop KFM to support upstream business; capture third party revenue Expand STACK Position Focus on the accretive acquisition of high quality acreage Apply operational expertise to underperforming assets Leverage Competitive Strengths Maintain fortress balance sheet to provide flexibility and optionality Support development, acquisitions and third party business with strategic midstream operation Integrated midstream will provide continuous valuation uplift Alta Mesa Position in Expanding STACK/MERGE/SCOOP Area Note: Wells drilled map as of August 2017. 35
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Jim Hackett’s Track Record Under Mr. Hackett’s leadership as Chairman, President, and/or CEO of Anadarko from 2003 to 2013, Anadarko was transformed into one of the largest U.S. oil and gas producers, growing its market cap from approximately $12 billion to over $43 billion. Prior to Anadarko, Mr. Hackett was also a key contributor to the market outperformance of Devon Energy. Anadarko Public Market Outperformer (2003 – 2013) 300% 250% 240% 200% 150% 100% 50% 74% 0% (50%) Strategic Dec-03 Feb-05 Apr-06 Jun-07 Aug-08 Oct-09 Dec-10 Feb-12 Thought Leader Anadarko S&P 500 Index Ocean (Devon)1 Public Market Outperformer (1999 – 2003) 250% 200% 210% 150% 100% 50% 0% (17%) Benchmark for (50%) Mar-99 May-00 Aug-01 Oct-02 Dec-03 Operational Ocean (Devon)1 S&P 500 Index Excellence and Execution Created new mission for Anadarko in 2003, upgraded corporate leadership capabilities, rationalized and refocused the portfolio, improved technical and financial risk management tools and processes, and generated success through expansion into unconventional onshore and conventional offshore assets Applied leading-edge technology and processes in drilling, completions, and production Dynamic leader for years serving as President and COO of Devon Energy, Chairman, President and/or CEO of Ocean Energy, president of several midstream companies, responsible for Duke Energy and PanEnergy’s midstream and upstream businesses, and drove Anadarko’s midstream business consolidation and MLP/GP IPO – Western Gas Partners and Western Gas Resources Premier operator with some of the best production metrics in U.S. onshore, U.S. Gulf of Mexico, and offshore East Africa Source: FactSet. Note: An investment in Silver Run Acquisition Corporation II is not an investment in Anadarko or Devon. The results of Anadarko or Devon are not necessarily indicative of the future performance of Silver Run Acquisition Corporation II. 36 1 Chart displays Ocean share price performance until merger with Devon completed. Thereafter, chart shows Devon performance on a per-Ocean share basis.
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High Caliber STACK Operating Team Cohesive, tenured, scalable team producing world class results Name Position Years at AMRYears Experience Hal ChappellePresident and CEO1330+ Mike EllisFounder and Chief Operating Officer3030+ Mike McCabeVP and Chief Financial Officer1125+ Gene ColeVP and Chief Technical Officer1025+ Kevin BourqueVP, Mid Continent Operations1020+ David McClureVP, Facilities and Midstream715+ Tim TurnerVP, Corporate Development430+ Dave SmithVP, Geology, Geophysics & Exploration1830+ Ron SmithVP and Chief Accounting Officer1030+ David MurrellVP, Land1025+ Jim Hackett (former Anadarko CEO) to serve as Executive Chairman and Midstream COO Robust Capabilities, Organizational Scale, Public Company Processes to Drive Long-Term Success Operations Engineering & Geology Land Corporate / Finance & (60 Employees) Accounting (40 Contractors) (45 Employees) (25 Employees) (50 Employees) 37
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Alta Mesa Management Jim Hackett Hal Chappelle Michael McCabe Executive Chairman and COO of MidstreamPresident and Chief Executive OfficerVice President and Chief Financial Officer Jim Hackett is a Partner at Riverstone Hal Chappelle joined Alta Mesa as Michael McCabe joined Alta Mesa in and became a director of Silver Run II inPresident and CEO in 2004 and became2006 and became a director in 2014 2017a director in 2004 Raised private equity capital for Alta Prior roles include: Developed Alta Mesa into a premierMesa from Denham Capital in 2006, HPS STACK operator, building a strongInvestment Partners in 2013, and Bayou oChairman and CEO of Anadarkomanagement and technical teamCity in 2015; successfully navigated Alta Mesa through two industry cycles oPresident and COO of Devon Energy Successfully navigated Alta Mesa oChairman, President and CEO ofthrough significant industry cycles, Has over 25 years of corporate finance Ocean Energybuilding the Company’s oil assets inexperience with a focus on the energy 2009-2010 and divesting of theindustry oPresident of several midstreamcompany’s gas assets in 2014-2016 companies, as well as responsible Previous management experience for DCP Midstream and Western Over 30 years of industry experience inincludes serving as President and sole Gas Resourcesfield operations, engineering,owner of Bridge Management Group, management, trading, acquisitions andInc., a private consulting firm Director of Enterprise Products Holdings,divestitures, and field re-development Fluor Corporation, National Oilwell Mr. McCabe’s leadership experience also Varco, Sierra Oil & Gas, and Talen Previously held roles at Louisiana Land &spans senior positions with Bank of EnergyExploration, Burlington Resources,Tokyo, Bank of New England and Key Southern Company and MirantBank Former Chairman of the Board of the Federal Reserve Bank of Dallas Holds a Bachelor of Chemical Holds a B.S. in Chemistry and Physics Engineering from Auburn University andfrom Bridgewater State University, an Holds a B.S. from the University ofan M.S. in Petroleum Engineering fromM.S. in Chemical Engineering from Illinois and a MBA/MTS from Harvardthe University of TexasPurdue University, and an MBA from UniversityPace University 38
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Alta Mesa Management Michael EllisGene ColeDavid Murrell Founder and COO of Upstream OperationsVP and Chief Technical OfficerVP, Land and Business Development Michael Ellis founded Alta Mesa in 1987 after Gene Cole has served in the position of Vice David Murrell has served as Vice President, Land and beginning his career with AmocoPresident and Chief Technical Officer since 2015Business Development since 2006 and became a director in 2015 Served as Chairman and COO as well as Vice Over 25 years of experience in Gulf Coast leasing, President of Engineering and has over 30 years of Over 25 years of extensive domestic andexploration and development programs, contract experience in management, engineering,international oilfield experience in management, wellmanagement and acquisitions and divestitures exploration, and acquisitions and divestiturescompletions, well stimulation design and execution Created a structured land management system for Built Alta Mesa’s asset base by starting with small Started his career with Schlumberger Dowell as aAlta Mesa and built a team of lease analysts, earn-in exploitation projects, then growing withfield engineer and served in numerous increasinglylandmen, and field representatives to facilitate Alta successive acquisitions of fields from major oilresponsible positions from 1986 to 2007Mesa’s growth companies Holds a B.S. in Petroleum Engineering from Marietta Holds a B.B.A in Petroleum Land Management from Holds a B.S. in Civil Engineering from West VirginiaCollegethe University of Oklahoma University Kevin BourqueTim TurnerDavid McClure VP, OperationsVP, Corporate DevelopmentVP, Facilities & Midstream Kevin Bourque progressed through several roles to Tim Turner joined Alta Mesa as Vice President of David McClure has served as Vice President of the position of Vice President of Mid-ContinentCorporate Development in 2013Facilities and Midstream Operations since 2016 Operations in 2012 when we began STACK Over 30 years of industry experience including From 2010 to 2016, he was Vice President for horizontal drilling programvarious operations, reservoir engineering andLouisiana Operations, leading a multi-disciplined He joined Alta Mesa as a field engineer in 2007managerial roles with Sun Oil, Santa Fe Minerals,team of engineers, regulatory, land, geoscience, and Led the growth of our mid-continent drilling andFina Oil & Chemical, Total, Newfield Exploration,operations personnel in development of the Weeks production operations as we expanded ourand Quantum ResourcesIsland field presence in Oklahoma Led multi-disciplined A&D and asset teams Previously held roles at ExxonMobil Production 10+ years of E&P operational experience with AltaCompany and Tetra Technologies Mesa Managed corporate reserves and planning functions Over 15 years of industry experience in field 10+ years of project management and business Led business development and new ventures teamsoperations, facilities and subsea engineering, management experience as the owner of his own Holds a B.S. in Petroleum Engineering from thepipelines, and management companyUniversity of Texas and an MBA in Finance from Oklahoma City University Holds a B.S. in Chemical Engineering from Auburn University 39
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Optimization, Delineation and Expansion Systematic horizontal development and growth of contiguous acreage 1992—2013 2014—2015 2016 & 2017 Plan 40,000+ Net Acres73,000+ Net Acres120,000+ Net Acres 198720132016 Founded by Mike Ellis with ~$200K Progressed through first two completion designs (Gen 1.0 Production reached ~20 MBOE/D and Gen 1.5) Drilled 100th STACK HZ well & first Gen 2.5 well 1991 DrillCo JV started, accelerated STACK drilling with 5 Initial Sooner Trend acreage acquired from2014-2015operated rigs Conoco/Exxon/Texaco-operated units Commenced aggressive STACK leasing/acquisition and Phase I of Kingfisher Midstream completed, with 60 accelerated STACK development, increasing from 4MMCF/D processing plant, crude and gas gathering, 2007-2012operated rigs (37% of capex budget) to 70% of total capextransmission pipelines, 50,000 BBL/D crude terminal, and Drilled 27 vertical stratigraphic delineation wells within legacybudgetfield compression acreage; defined robust Osage prospectivity in vertical wells Built STACK acreage from 40K to 70K+ acres through bolt- Spud first two operated HZ STACK wells in December 2012on acquisitions2017 Increased to 6 STACK operated rigs (95% of capex budget) Phase II of KFM expected to be complete, which includes 200MMCF/D cryo plant expansion, gas gathering pipelines, field compression and high-pressure gas transmission pipelines 40
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Appendix Well Performance
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Focus: Optimize Stimulated Rock Volume Operational advancements with proven results Completion Summary By Generation Alta Mesa has advanced completion designs with each generation – leading to improved well response and economics: Number of stages increases with each generation as stage spacing decreases Average sand per stage has increased with each generation Total fluid per stage increases with each generation Continuously optimizing completions designs through reduced frac stage spacing for increased formation stimulation Design Parameters Gen 1.0 Gen 1.5Gen 2.0Gen 2.5CurrentFuture Avg Frac Stages1218243235 Avg. Stage Spacing (Ft.)340256194150140 Slickwater—Avg Total (BBLS/Ft.)2942566675 Sand—Total Avg. (Lbs/Ft.)3174576771,1931,500Improvement Frac Design TypePacker/SleeveHybridPlug/PerfPlug/PerfPlug/PerfFurther Flow Design TypeSlickwaterSlickwater Slickwater Slickwater Slickwater Packers TypeMechanicalHybridSwellSwellSwell Well Count1765995— Goal: optimize stimulation 100to increase value / EUR 90 (MBO) 80 70 60 Production 50 40 30 Cumulative 20Flowback Rate-Controlled 10In Early Periods 0 061218 Production Month Type Curve by Generation2 MBO MBOE 714 652 472 149 183250 71 AverageAverageGeneration 2.0Generation 2.5Beyond Generation 1.0Generation 1.5Type CurveType CurveGeneration 2.5 1 Wells completed as of 8/16/17 2 Gen 1.0, 1.5, 2.0 based on Ryder Scott-audited Reserve Report. Excludes 9 wells with circumstances that will not be repeated due to unacceptable results: i) 4 wells with 660’ spacing in a high porosity area, ii) 3 child wells drilled between 2 parent wells without injecting water into the parent wells prior to frac, iii) 1 well which were shut in for more than 90 days after frac, iv) 1 well that fraced into a vertical well and the vertical well was not plugged in the Osage/Meramec.42
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Completion Design Focus on increasing stimulated reservoir volume STACK Well Completion StrategyAverage Total D&C Cost / Well ($MM)Average D&C Cost / Lateral Foot Progressed through testing multiple generationsActual D&CTarget Pattern Test D&C$1,359Actual D&CTarget Pattern Test D&C Highly fractured area benefits from “open-hole” design$5.1 Targeting average lateral length of 4,800ft (one-mile)$4.7 $4.2$1,074 Drilling N–S orientation to intersect natural fractures $940 Controlled flowback rate to optimize conductivity$3.4$3.4$3.2 Generation 2.5 proppant loading is optimum at an$720$713 average of 1,400 lb/ft; tested up to 2,100 lb/ft$667 Current Completion Design Targets 7” intermediate casing + 4.5” liner in lateral Open-hole swell packers; proppant loading of 1,400 lbs/ft 3 joints (casing) betweenpackers defines 150ft stages 10,000 bbls of slick water per stage20122013201420152016Target Pad20122013201420152016 Target Pad 100 bbl/min total fluid injection rateDrillingDrilling Cap flowback rate at 100 bbl/hr of total fluidAvg. Days Spud to TD463425171313 Averages by Completion Generation Stage SpacingProppantFluid 354001,4008,0003,00010,75210,86411,000 321,2752,630 3403501,2007,0009,860 302,5002,35210,000 . Ft6,000 24300l1,0006,078Total9,750 25256St. 2,0009,000 250ge a5,000Ft1,764 20800 18194/677 / e Stages200Spacis . Latera4,000ProppantLateral 1,5001,2188,000Fluid 15150L b600/ v erag12150ngg ..4573,1223,000(‘0001,0007,000Stage A 10400317 . (FtAvFluid 100)2,000Lbs . tal2,128)5006,000 550T o2001,000 1,339 000005,000 Gen 1.0 Gen 1.5Gen 2.0 Gen 2.5Gen 1.0Gen 1.5Gen 2.0Gen 2.5Gen 1.0Gen 1.5Gen 2.0Gen 2.5 StagesStage SpacingProppant Lbs./Lateral Ft. Total ProppantFluid/Lateral Ft.Fluid / Stage Source: Company Data.43
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Cost-Advantaged Asset Base Infrastructure and basic well design mitigate cost inflation Advantage Why It Matters 1 Allows for the elimination of additional strings of casing, liner Shallowertie-back, and reduces horsepower used during stimulation Targets Reduced drilling time and costs per well enhances capital flexibility and efficiencies 2 Reduces mechanical risk of completions vs two-mile One-mile Use less steel by utilizing smaller diameter pipe program Laterals Lower cost per foot to execute drilling and completions 3Naturally Heavier proppant loads not required Fractured Flexibility to use more commoditized proppant Formation Gross D&C1 ($MM) Lat. Length: 4.8k 4.8k 4.8k 5.0k 4.8k 5.0k 9.6k 9.8k 9.6k 10.0k $ 12.0 $ 10.0 $ 8.0 $ 6.0 $ 4.0 $ 2.0 $ 0.0 AMR -MRMC/OSAGE (Gen 2.0) AMR -Average MRMC/OSAGE (Gen 2.5) D&C CHK—OSWEGO Cost DVN—MRMC SLNP / Lateral MRO—MRMC Foot DVN—UPPR MRMC NFX—MRMC SXL CLR—MRMC MRO—MRMC XEC—MRMC Average Total D&C Cost/Well ($MM) Actual D&CTarget Pattern Test D&CActual D&CTarget Pattern Test D&C $1,359 $5.1 $4.7 $4.2$1,074 $940 $3.4$3.4$3.5$3.2 $720$713$729$667 20122013201420152016Current AFE Target Pad20122013201420152016Current AFE Target Pad DrillingDrilling Avg. Days Spud to TD46342517131313 1 AMR Pad Drilling D&C only and does not include $300k of allocated facilities cost.44
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Osage Interval of Meramec/Osage System Osage produces across acreage, thickening to north and east Summary 118 Generation 2.0+ wells with sufficient production history Average Generation 2.5 lateral length of 4,612’; Generation 2.0+ 4,767’ Type Curve average 30-day IP 300 BOPD Type Curve average 180-day cumulative production of 75 MBOE Generation 2.5 Type Curve 622 MBOE 2-Stream EUR; 714 MBOE 3-Stream EUR 303 MBO, 1.6 BCF residue, 144 MB NGL Generation 2.0 Type Curve 561 MBOE 2-Stream EUR; 652 MBOE 3-Stream EUR 250 MBO, 1.6 BCF residue, 141 MB NGL Type Curves assume 16% Shrink and 75 bbl/MMcf NGL yield Gen 2.5 Type Curve Gen 2.0 Type Curve Average Type Curve Key Statistics Gen 2.5Gen 2.0 Initial Rate (BO/D / MCF/D)200 / 500200 / 500 Incline Period (oil / gas)2 months / 4 months2 months / 4 months Peak Rate (BO/D / MCF/D)400 / 900350 / 900 b factor (oil / gas)1.2 / 1.51.2 / 1.5 Initial Decline (oil / gas)71% / 41%72.6% / 41.2% Lateral Length4,8004,800 2-Stream EUR (MBOE)622561 3-Stream EUR (MBOE)714652 Type Well IRR %187.2%69.2% Gen 2.0 Type Curve Cumulative Production Gen 2.5 Type Curve Cumulative Production Note: Production data normalized for 4,800’ lateral length. 1 NYMEX Strip as of 9/8/2017. Does not include $300k PAD D&C facilities costs. Adjusted for transportation costs paid to KFM. Excludes $1.25 / bbl oil transportation costs. 45
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Meramec Well Delineated Across our Acreage Meramec produces across acreage, thickening to south and west Summary Meramec Thickness in STACK with Vertical and Horizontal Meramec Producing Wells Meramec resource and production affirmed on Alta Mesa acreage by 100’s of vertical Meramec completions and newer horizontal wells Alta Mesa, Newfield, Devon, Marathon, Gastar, and Chaparral drilled >100 wells landed in Meramec portion of the Meramec/Osage in Alta Mesa footprint Alta Mesa patterns include Meramec and Osage landings Average Type Curve Results â’532 MBOE 2-Stream EUR; 615 MBOE 3-Stream EUR â’249 MBO, 1.4 BCF residue, 128 MB NGL Type Curve assumes 16% Shrink and 75 bbl/MMcf NGL yield Average Type Curve Cumulative Production 400 Meramec Type Curve 350Offset Well Results1 Key Statistics Meramec Offset Well Results Initial Rate (BO/D / MCF/D)170 / 296 300 Incline Period (oil / gas)2 months / 2 months Peak Rate (BO/D / MCF/D)500 / 1250 250b factor (oil / gas)1.2 / 1.5 (MBOE)Initial Decline (oil / gas)80% / 56% Lateral Length4,800 2002-Stream EUR (MBOE)532 oduction3-Stream EUR (MBOE)615 rType Well IRR %278.1% P Cum150 s os Gr100 50 0 Note: Production data normalized for 4,800’ lateral length. 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 1 Offset results based on Meramec wells drilled in the Updip Oil window of Kingfisher County since 2014. 2 Time (Months) NYMEX Strip as of 9/8/2017. Does not include $300k PAD D&C facilities costs. Adjusted for transportation costs paid to KFM. Excludes $1.25 / bbl oil transportation costs. 46
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Oswego a Significant Regional Producing Zone Development expected across most of Alta Mesa acreage Oswego Formation Thickness in STACK with Oswego vertical main field pay in legacy Alta Mesa acreage Vertical and Horizontal Oswego Producing Wells Alta Mesa, Chesapeake, Chaparral, and other operators actively targeting Oswego Typical well performance demonstrates shallower declines with lower IP rates and much higher oil component Oswego well costs typically lower than Meramec/Osage Average Type Curve Results â’233 MBOE 2-Stream EUR; 243 MBOE 3-Stream EUR â’200 MBO, 0.2 BCF residue, 15 MB NGL Type Curve assumes 16% Shrink, 75 bbl/MMcf NGL yield Average Type Curve Cumulative Production 400Key Statistics Type CurveInitial Rate (BO/D / MCF/D)320 / 320 Incline Period (oil / gas)none 350Offset Well Results1Peak Rate (BO/D / MCF/D)320 / 320 (MBOE)Oswego Offset Well Resultsb factor (oil / gas)1.2 / 1.2 Initial Decline (oil / gas)72% / 72% 300Lateral Length4,800 oduction2-Stream EUR (MBOE)233 r3-Stream EUR (MBOE)243 P Cum250Type Well IRR %256.7% oss r G200 150 100 50 0 0 12 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Note: Production data normalized for 4,800’ lateral length.Time (Months) 1 Offset results based on Oswego wells drilled in the Updip Oil window of Kingfisher County since 2014.47 2 NYMEX Strip as of 9/8/2017. Doesnot include $300k PAD D&C facilities costs. Adjusted for transportation costs paid to KFM. Excludes $1.25 / bbl oil transportation costs.
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High Early-Period Oil, Low Water Cut Drive Value Consistent Meramec/Osage GOR behavior Product Weighting Over Time Approximately 57% of oil, 38% of natural gas liquids, and 38% of natural gas produced in first five years — enhancing early revenue per unit and resulting economics. Ten year recoveries are 73% oil, 58% NGL’s, 58% gas GOR increases over time from approximately 0 MCF/BBL to approximately 5 MCF/BBL at year one to approximately 10 MCF/BBL at 5 years, consistent with historic vertical well production In month one, 2-stream production is 82% oil, 3-stream production is 85% liquids In year one, 2-stream production is 66% oil, 3-stream production is 70% liquids Average 2-stream 50% oil point near end of year 2, 3-stream production remains above 50% liquids life of well Water-oil ratio rapidly declines from ~5 once oil begins in early flowback to ~1.5 after 12 months Projected Oil and Liquids Content1 Average GOR Behavior1 Water Type Curve Source: Ryder Scott-audited Reserve Report, Company data. 1 LNU17N06W02A Miss well (Ryder Scott-audited Reserve Report). 48
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Appendix Geology
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Sooner Trend Petroleum System Ideal for horizontal development in multiple horizons Oklahoma Oil & Gas Fields Significant system of petroleum reservoirs in eastern Anadarko, defined by 1000s of vertical wells Natural fracturing extensive, east-west orientation of Garfieldnear-vertical fractures intensifies near Nemaha Fault MajorSystem Osage/Meramec co-produce in ~500 ft thick section STACK average 35 MMBO oil in place in our footprint Kingfisher Canadian favorable rock properties in siliceous Osage and silty/shaly Meramec limestones extend across Sooner Trend in Kingfisher & Major counties Oswego/Big Lime ~120 ft fractured oolitic limestone Manning ~90 ft fractured limestone / limy sandstone Woodford Shale 50-150 ft OKLAHOMA Simplified Stratigraphy of Major STACK Targets in Kingfisher County SWNE Kingfisher County 50
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Stacked Pay: Oswego, Osage/Meramec Prominent Oswego, Osage, and Meramec consistent east to west; Manning in northwest West A East A’ Big Lime Penn—Cherokee Oswego Manning Chester Unc. A A’ Chester Shale Meramec Unconformity Upr Meramec Lwr Meramec Upr Osage Lwr Osage Woodford Hunton Pre-WDFD Unc. 51
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Significant Oswego, Osage/Meramec Section Consistent thickness east to west West B East B’ Big Lime Oswego Penn—Cherokee Chester Unc. Chester Shale Meramec Unconformity Upr Meramec Lwr Meramec B B’ Upr Osage Lwr Osage Woodford Pre-WDFD Unc. Hunton 52
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Significant Oswego, Osage/Meramec Osage & Woodford prominent, thickening to the north; Manning in north North C South C’ C Manning Chester Shale Meramec Unc. Upr Meramec Lwr Meramec C’ Upr Osage Lwr Osage Pre-WDFD Unc. Hunton Woodford 53
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Appendix STACK Development
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Significant Activity in Alta Mesa “Neighborhood” Prominent operators active in Updip Oil Window adjoining Alta Mesa Permits 180 Days SD SD SD CHK CHK CHK MRO CHK DVN NFX CHK AMR DVN AMR MRO AMR DVN MRO DVN DVN CLR NFX NFX MRO CLR MRO CLR NFX DVN MRO MRO CLR MRO 1 CLR Source: IHS Enerdeq, HPDI. Note: Represents a combination of current and recent rig activity. 1 Operators with 2 rigs or fewer running.55
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STACK Shifting from Delineation to Development Leading STACK operators plan for multi-well / multi-bench patterns Recent Increased-Density Filings in Meramec/Osage and Oswego Drilling Units 56
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Well Spacing Optimization on De-Risked Acreage DVN, CLR, MRO, NFX and AMR aggressively defining optimum spacing Alta Mesa is the Leader in the Oil Window with Successful Long Life Spacing Tests Alta Mesa—4-well Spacing Test EHU 237, 239, 240, 241 S9-19N 6W Newfield—Stark Pilot, 10-well SpacingLower/Middle Osage, 1,500’ Test Upper/Lower Meramec Alta Mesa—4-well Spacing Test Newfield—Raptor-X Pilot, 6-well SpacingEHU 230, 231,232, 233 S6-18N 6W Test 880’ Upper/Lower MeramecLower/Middle Osage, 660’ Alta Mesa—5-well Spacing Test Continental—Ludwig Pilot, 8-well SpacingLNU 15-4, 15-5, 16-2,16-3, 16-4 Test (74%oil)Lower (1,320’)/Middle (1,200’) Osage 1,320’ Upper/Lower Meramec Alta Mesa—10-well Spacing Test Bullis – Coleman Pattern S9 17N 6W Continental—Blurton STACK Pilot, 8-wellLower/Middle (932’) Osage; Lower Meramec/4-well Woodford TestMeramec 1,320’ Upper/Lower Meramec Alta Mesa—3-well Spacing Test Continental—Bernhardt STACK Pilot, 8-Borelli – Dodd Pattern S8-17N 5W well Meramec/4-well Woodford TestLower/Middle (1,500’) Osage 1320’ Upper/Lower Meramec Alta Mesa—3-well Spacing Test Oswald Pattern S28-17N 6W Continental—Verona STACK Pilot, 8-wellLower/Middle (1,500’) Osage Meramec/4-well Woodford Test 1,320’ Upper/Lower MeramecNewfield—Chlober, 5-well Spacing Test 1,050’ Upper/Lower Meramec Newfield—Dorothy Pilot, 5-well Spacing Test 1,050’ Upper/Lower Meramec Marathon—Yost, 6-well infill Spacing Test Meramec Continental—Gillilian STACK Pilot, 8-well Meramec/4-well Woodford Test 1,320’ Upper/Lower MeramecDevon—Pump House, 7-well Spacing Test 2,200 lbs/ft proppant, 4,700’ laterals Devon—Born Free, 13-well Spacing TestUpper Meramec 400’ Upper/Lower Meramec Alta Mesa – 4 Well Spacing Test Cimarex—Gundy, Future 10-well SpacingHuntsman Pattern S23-15N 6W in Meramec/9-well Spacing in WoodfordAlta Mesa¯1,200 ft. spacing Osage and Meramec 550’ Upper/Lower MeramecOptimization of Well SpacingDevon—Alma, 5-well Spacing Test MilesIP60 1,300boed, Upper/Lower Meramec 01.75 3.57 Source: 1Derrick, IHS, Drilling Info and Company Presentations. 57
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STACK: A Significant Petroleum System Additional development potential in multiple stacked pay zones Alta Mesa Existing Development Over 800 days of strong well performance at spacing of 1,200’—1,500’ At least three target landing zones in Osage/Meramec — a continuous 550’ section — and one additional in Oswego Identified Meramec/Osage locations represent average 8% OIP recovery Existing spacing tests at 660’ show full development potential 660’ spacing tests have more than 200 days of online production Additional Zones Eight zones have proven hydrocarbon production from vertical wells Chester Shale offers added potential Alta Mesa and others have already drilled successful Red Fork, Big Lime, Oswego, Meramec, Osage, Woodford, and Hunton horizontal wells in STACK Additional formations have strong vertical production history Drilling days expected to remain similar across the various formations Alta Mesa beginning Manning de-risking in northern Kingfisher with 3-4 wells in 2017 Potential 55 Wells per Section Type LogDown-Additional FormationIdentifiedTotal spacingFormations Big Lime44 Oswego224 Cherokee Shale Prue Sand44 Skinner Sand Red Fork Sand Manning Lime44 Chester Shale44 Meramec448 437 Osage 448 Woodford Shale88 Hunton Lime44 Total14132855 58
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Substantial Inventory of Drilling Locations Identified Drilling Locations Prospective Drilling LocationsCombined Average Working Interest AverageOther(Including WorkingFormationsDow nspacingTotalDow nspacingTotal LocationsInterest (%)LocationsLocationsLocationsLocations) (%)Locations Operated: Osage 1,19672%—1,1411,14173%2,337 Meramec 67674%—67667674%1,352 Osw ego 20375%—20620681%409 Manning——168—16875%168 Other Formations——1,327—1,32770%1,327 Total Operated 2,07573%1,4952,0233,51873%5,593 Drilling Inventory (Years)14.4—10.414.024.4—38.8 Other: Osage 1,25215%—1,1131,11315%2,365 Meramec 58815%—59659615%1,184 Osw ego……………………28113%—31031014%591 Manning…………………….——316—31614%316 Other Formations .——2,084—2,08455%2,084 Total Other………2,12115%2,4002,0194,41928%6,540 Total Gross Locations4,1963,8954,0427,93712,133 Note: Does not include additional resource potential or undeveloped locations on ~20,000 net acres recently acquired in the Major County Acquisition. 59
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Alta Mesa Spacing Design Consistent with STACK Peers Spacing tests across footprint give confidence in base case Summary Observations Base case design reflects over 4,000 locations and is consistent with plans disclosed by our peers Lower risk upside, also in-line with peers, could produce an incremental 1,800 locations Initial 6 spacing test pilots, which are producing, support long-term development plans Formation Oswego Meramec Osage Woodford Total Wells per DSU Publicly Disclosed Inventory per DSU Assumptions Peer 1Peer 2Peer 3Peer 4Peer 5Base Case 24 20 16 14 12 4 N/AN/AN/AN/A42 8121212N/A4 ----N/A8 1684-N/A- 24201612414 Source: OK Corporation Commission, public disclosures from investor presentations and 60
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Multiple Long Term Density Pattern Tests Density Patterns Test Horizontal and Vertical Spacing 1,320ft spacing / 2 benches1,500ft spacing / 2 benches1,500ft spacing / 2 benches Section 29 18N 5WSection 8 17N 5WSection 28 17N 5W Spacing600’ 600’ Pattern180’180’ 180’ 1,320’1,320’ 1500’1500’ Implies 12 wells per sectionImplies 12 wells per sectionImplies 12 wells per section Cum 622 MBOE – 780 daysCum 663 MBOE – 660 daysCum 480 MBOE – 540 days 1,000,0001,000,0001,000,000 100,000100,000100,000 10,00010,00010,000 Pattern1,0001,0001,000 Results100100100 1121241 361 48160111212413614816011121241361 481601 Cum BO—3 WellsCum BO—3 Wells Cum BO—5 Wells Mean—5 x 250 MBO 660ft spacing / 2 benches1,000ft spacing / 3 benches1,200ft spacing / 2 benches Section 31 19N 6WSection 9 & 10 17N 6WSection 23 15N 6W 334’ 334’ Spacing170’ 330’ 330’466’ 466’ 466’466’ 466’660’ 334’1236’ 310’ Pattern180’140’140’140’ 230’230’ 660’ 932’932’1,126’1,002’618’ 618’618’ Implies 24 wells per sectionImplies 18 wells per sectionImplies 12 wells per section Cum 319 MBOE – 360 daysCum 348 MBOE – 56 daysCum 12 MBOE – 19 days 1,000,0001,000,0001,000,000 100,000100,000100,000 Pattern10,00010,00010,000 Results1,0001,0001,000 100100100 1121 241 361 48160111212413614816011121241361481601 Cum BO—10 WellsCum BO—4 Wells Cum BO—4 Wells Mean—4 XMean—10 X 250 MBOMean—4 4 X 259 250 MBO 61
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One Mile Laterals Optimum for Up-Dip STACK Alta Mesa and other efficient operators adopt fit-for-purpose solutions ~5,000’ laterals used for multi-faceted benefits: drilling, completions, production operations, land and legal Consideration Commentary Spacing One-mile lateral fits into a single section; two-mile laterals require establishing a “Multi-Unit spacing” DrillingAbility to use lower cost water-based muds and reduced time spent drilling helps to reduce drilling risk and control costs associated to high levels of natural fractures CompletionsLess proppant, fluids, and pumping time per well, more simplified design, lower friction while pumping all help to reduce costs of optimized completions Mineral OwnerWorking with mineral owners across one-section (versus two-sections for longer laterals) allows for Relationsmore seamless and confident development program planning 62
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Appendix Midstream
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Complete Midstream Operation Processing, Pipelines, Compression, Other Infrastructure Natural Gas Current processing capacity of 60 MMCF/D Cushing ~60 mi.Processing Second 200 MMCF/D plant under construction 90 MMCF/D offtake processing Low 223 miles1 of low-pressure crude and gas gathering lines Pressure Pipeline-Natural gas gathering: 6”-16” pipeline -Crude gathering: 6”-8” pipeline High 98 miles2 of 4” to 16” rich gas transportation pipeline Pressure Pipeline-Average operating pressure of 1,100 psig and piggable 4 miles of 16” residue gas pipeline with 230 MMCF/D of capacity to PEPL 5 miles of 16” residue gas pipeline connecting KFM to OGT in service October 2017 4 miles of 6” NGL Y-grade pipeline, with 10,000 BBL/D capacity to Chisolm Pipeline Compression Field Compression Facilities-3 CAT 3516s at Lincoln South Location (4,140 total horse power) -3 CAT 3516s at WSOR Location (4,140 total horse power) -1 CAT 3516, 1 CAT 3306 at Garfield Compressor Site -1 CAT 3508 at Snowden Compressor Site -1 CAT 3516at West Kingfisher Compressor Site -1 CAT 3508at Great Divide Compressor Site Inlet Compression – 6x CAT 3606s (10,650 total horse power) Residue Compression—3x CAT 3516s (4,140 total horse power) Other 50,000 BBL crude storage with 6 truck loading LACTS Infrastructure 3 NGL bullet tanks: 90,000 gallon capacity 1,200 BBL/D condensate stabilizer Producer 54 central delivery point receipt connections serve Connections188 units Note: Represents multiple lines in ditch. 1 Includes 16 miles under construction64 2 Includes 20 miles under construction
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Market Access Optionality Pipeline DescriptionCurrent Takeaway CapacityExpansion ProjectsCommentary Natural Connected to PEPL – owned and 100,000/day FT on PEPL for KFM in discussion Gas takeaway is functionally full creating a Gasoperated by Energy Transfer20 yearswith proximateconstrained environment for some PEPL consists of four large 50,000/day FT on OGT,outlet pipelinesproducers. KFM’s residue position diameter pipelines extendingexpanding to 125,000/daylooking to expandprovides flow assurance and better approximately 1,300 milesJune 2018out of the basinnetbacks for KFM producer clients throughout Mid-Continent and-25,000 Dth/d for 4 years Residue gas is split connect between other market centersPEPL and OGT, and under long term KFM will connect to OGT Q3 2017-100,000 Dth/d for 10agreements insuring that KFM producer yearscustomers can flow out of the basin OGT services local Oklahoma gas demand, but via an expansion will Capacity rates are low compared to new begin to deliver gas to WAHA inrates that will be needed to solidify new Q2 2018capacity out of the basin creating better netbacks for KFM producers dedicated to the system NGL Connected to Chisholm Currently under a 3 year Opportunity to tie Connected to P66’s Chisolm Y-grade Pipeline—operated by Phillips 66contract extendable for 2 1-into other NGLpipeline that takes Y-grade to Conway, KS Delivers NGLs to Conwayyear terms with shipperpipelines in the areafor fractionation history Volumes could Multiple NGL lines within 7 miles of plant warrant expansionto further diversify Y-Grade options when or new build to Mt.needed Belvieu KFM Y-grade optionality will allow producers to capture netback uplift between Conway, KS and Mt Belvieu Operational capacity of ~41,000 Bbls/d on existing Chisholm line Crude Crude gathered to a central Not currently committed Long haul pipeline Crude system is focused around keeping delivery point at the plant siteopportunities toAlta Mesa barrels and future third party Six truck bays for LACT loadingCushing and otherbarrels clean to market, producing better and unloadingdemand sources innetbacks the area Multiple pipeline Proximity to Cushing provides market connection optionsoptionality between in-state and the Gulf Coast refineries. No long terms commitments provide KFM the option to build out long-haul crude pipelines enhancing drop down inventory 65
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Premier Integration Story Drives Midstream Value Uplift AMR Growth Drives($ in millions unless otherwise noted) Midstream Value CreationKFM’s Scale Will Drive MLP Growth Story1 69 Long-Term Growth Profile$ 318 175% 3 year EBITDA 39CAGR 21$ 184 Organic Growth Production(Mboe/d)EBITDA$ 42 Third Party Volumes 2017E2018E2019E Self-funding 2H2018+ 2017E2018E2019E by239 207 Wells120 KFM’s Near-Term EBITDA Would be Sufficient to TotalYear3,4Provide Visible MLP Growth $ 318 Forecast2017E2018E2019EForecast Avg. 6 11011 20% long-term DPU Rigs growth target 2EBITDA Flexible Organic and Price$ 51.56MLPDrop Down Growth $ 86 Oil$ 24.40$ 50 No Immediate Follow- On Equity Needs Updip OilCurrent WTI BreakevenSTACK($/Bbl)Illustrative2018E2019E2019E KFM 1 Average 2017 YTD rigs.(8/8ths) 2 Based on 15% IRR hurdle. Assumes gas price deck of 2017: $3.10/mcf; 2018: $2.99/mcf; 2019: $2.83/mcf. AMR breakeven price <$30/BBL estimated based on 651 MBOE mean type curve. 3 The information relating to the expected IPO, as well as the illustrative EBITDA and other financial information of the MLP, is forward-looking information. There can be no assurance as to the timing, size or completion of any IPO or the timing of any future drop-down transactions, and we may not be able to complete the IPO or subsequent drop-down transactions on the terms presented herein or at all. Actual results may differ materially due to a number of factors, including, but not limited to, market conditions, the clearance by the relevant regulators of any filings related to the IPO and the other risks related to Alta Mesa’s and Kingfisher’s business described in Silver Run’s preliminary proxy statement filed with the SEC on September 25, 2017. See “Forward-Looking Statements” on page 2 of this presentation. 4 Illustrative MLP EBITDA forecast assumes 27% of KFM contributed to MLP at IPO and NTM forecast period based on 2018E EBITDA of $184 million. Assumes 20% LP DPU CAGR through 2019.66
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Appendix Financial Performance / Outlook
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2017 Capital Budget and Hedge Position Commentary Alta Mesa Alta Mesa’s 2017 net capital budget is estimated to be $349MM Alta Mesa estimates that ~$107MM of the FY 2017 capital budget will be funded by Bayou City per the JV agreement Alta Mesa’s total 2017 capital budget is estimated to be $457MM, including the Bayou City Energy JV FY 2017 acquisition (including leaseholds) capex spending expected to total $89MM, or ~19% of the total deployed budget (including Bayou City Energy JV) Expect 10-Rig program in the STACK by YE18 Continue growth and efficiency gains in the STACK while maintaining conservative Leverage Ratio Kingfisher Midstream KFM’s 2017 net capital budget is estimated to be $125MM Growth capital categorized through processing, pipeline, high / low pressure well connects, compression lease principal payments and compression lease interest expense items Oil Hedged (BBL/D) – as of 9/25/17 11,307 10,000 4,400 Sept-Dec ‘1720182019 Sept-Dec ‘1720182019 Average Floor Price ($/BBL)$49.90$51.37$50.00 2017E Budget by Quarter ($MM) – Ex. Acquisitions1 1 Upstream 19% 55% Midstream $152 26% Acquisition (Including Leasehold) $70 $94 $20 $79 $60 $18 $17 $74 $83 $61 $43 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Alta Mesa KFM Gas Hedges (MCF/D) – as of 9/25/17 30,527 16,233 Oct-Dec ‘17 2018 Oct-Dec ‘17 2018 Average Floor Price ($/BBL) $3.20 $4.43 Disciplined management protects future revenues and preserves asset value by hedging large percentage of proved-developed and prompt-year production. Currently hedge WTI (oil), Henry Hub (gas), Conway (propane), and Mid-Con gas basis. 1 Does not include Bayou City Energy JV. 68
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KFM Financial Overview Detailed Capital Expenditures by Phase Existing Infrastructure ($MM) 2017E 2018E2019E Processing$30$130$79 Pipeline & Well Connects535227 Compression Principal Payments01425 Compression Lease Interest Expense059 Total$84$202$139 Expansion ($MM)2017E2018E2019E Processing$5$81$0 Pipeline & Well Connects367517 Compression Principal Payments01013 Compression Lease Interest Expense044 Total$41$171$35 69
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Implied Valuation at Various Prices Share Price$10.00$11.50$14.00$16.00$18.00$20.00 @ $10.00 Equity Ow nership (Million Shares)@ $11.50@ $14.00@ $16.00@$18.00@$20.00 Legacy Silver Run II Ow ners1103.500103.500109.661113.203115.958115.958 Riverstone2,385.87585.87592.14995.75698.56298.562 KFM Ow ners455.00055.00062.14368.39368.39368.393 Legacy Alta Mesa Ow ners5144.271144.271154.986164.361178.249190.749 Total Shares Outstanding388.646388.646418.938441.713461.163473.663 37.12137.12136.99537.21038.65240.271 Equity Ow nership (%)@ $10.00@ $11.50@ $14.00@ $16.00@$18.00@$20.00 Legacy Silver Run II Ow ners127%27%26%26%25%24% Riverstone2,3222222222121 KFM Ow ners4141415151514 Legacy Alta Mesa Ow ners5373737373940 Equity Ow nership100%100%100%100%100%100% Equity Ow nership ($MM)@ $10.00@ $11.50@ $14.00@ $16.00@$18.00@$20.00 Legacy Silver Run II Ow ners1$1,035$1,190$1,535$1,811$2,087$2,319 Riverstone2,38599881,2901,5321,7741,971 KFM Ow ners45506338701,0941,2311,368 Legacy Alta Mesa Ow ners51,4431,6592,1702,6303,2083,815 Total Equity Value ($MM)$3,886$4,469$5,865$7,067$8,301$9,473 1 Includes 103.5 million shares issued in the Silver Run II March 2017 Initial Public Offering and 34.5 million warrants with an $11.50 strike price and $18.00 redemption price. 2 Includes 25.875 million shares and 15.1 million warrants with an $11.50 strike price acquired as part of the Silver Run II March 2017 Initial Public Offering and 60 million common shares and 20.0 million warrants with an $11.50 strike price acquired through Riverstone’s cash investment at the closing of the business combination. 3 Warrants held by Riverstone are not subject to a redemption at $18.00 per share; however, they are assumed to be exercised on a cashless basis at $18.00 per share. 4 Includes earnout incentive shares vesting according to the following schedule: $100 million at $14.00 per share and $100 million at $16.00 per share.70 5 Includes earnout incentive shares vesting according to the following schedule: $150 million at $14.00 per share, $150 million at $16.00 per share, $250 million at $18.00 per share, and $250 million at $20.00 per share.
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Alta Mesa Summary STACK Pro Forma Financials
Six Months Ended Years Ended December 31,
($ in
millions, unless specified) June 30, 2017 201620152014
Production
Oil (MBBLS) 1,845.0 3,057.22,006.11,071.6
Natural Gas
(MMCF) 7,004.0 9,110.24,272.62,083.0
NGLs (MBBLS) 589.0 901.0499.4315.6
Total Production (MBOE) 3,601.3 5,476.63,217.61,734.4
Daily Production
(BOE/D) 19,896.9 15,004.38,815.34,751.7
Statement of Operations
Revenue $123.2 $166.4$133.6$117.3
Operating Expenses (Cash
Items) $35.6 51.634.724.6
Exploration Costs (Cash Item) $8.2 17.29.811.8
Operating Expenses (Non-Cash) $40.4 63.380.329.4
General and Administrative1 $18.0 40.537.968.4
Interest
Expense1 $25.2 43.462.555.8
Other Financial Data
Adjusted EBITDAX2 $70.1 $74.3$61.0$24.3
%
Margin2 56.9% 44.7%45.7%20.7%
Note: This historical pro forma financial information is unaudited and gives effect to (i) the expected
disposition of Alta Mesa’s non -STACK assets and operations prior to the closing of the business combination as if such transaction occurred on January 1, 2014 and (ii) the contribution to Alta Mesa of
interests in 24 producing wells that were drilled under the BCE joint development agreement and purchased by High Mesa from BCE on December 31, 2016, as if such transaction occurred on January 1, 2016. 1 General and administrative expense
and interest expense for the total company. 2 Adjusted EBITDAX is a Non-GAAP financial measure. See reconciliation to the nearest comparable GAAP measure in the appendix to this presentation.71
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Reconciliation of Adjusted EBITDAX to Net Income Six Months Ended Years Ended December 31, ($ in millions, unless specified)June 30, 2017201620152014 Net Income (Loss)($3.7)($49.6)($91.6)($72.7) Adjustments: Interest expense25.243.462.555.8 Exploration expense8.217.29.811.8 Depreciation, depletion and amortization expense39.162.661.329.1 Impairment expense1.20.418.80.0 Accretion expense0.10.30.20.3 Adjusted EBITDAX1$70.1$74.3$61.0$24.3 Note: This historical pro forma financial information is unaudited and gives effect to (i) the expected disposition of Alta Mesa’s non -STACK assets and operations prior to the closing of the business combination as if such transaction occurred on January 1, 2014 and (ii) the contribution to Alta Mesa of interests in 24 producing wells that were drilled under the BCE joint development agreement and purchased by High Mesa from BCE on December 31, 2016, as if such transaction occurred on January 1, 2016. 1 Does not include non-cash items—provision for income taxes, loss on extinguishment of debt, unrealized loss (gain) on oil and gas hedges and (gain)/loss on sale of assets.72
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Alta Mesa’s Conservative Approach AssumptionCommentary Gen 2.0 ~650 MBOE Upstream Projections based on Gen 2.0 type curve type curve vs. Gen Production / Type Gen 2.5 drill & complete AFE costs assumed in forecasts 2.5 ~700 MBOE type Curve Plans to test ”Gen 3.0” reduced stage spacing in 2018 curve Upstream7 rigs in 2017 YTD average of 6 rigs Production / Rig11 rigs in 2018 Organization readily scalable for 10-rig program Ramp12 rigs in 2019 Third frac spread and fourth frac spread added in Q3 2017 LOE per BOE comparable to peers despite oiler production mix and much currently lower total production Upstream$4.221 / BOE Fixed costs associated with substantial infrastructure and multi- Operating Expensewell pads create leverage to further reduce LOE Accounting for SWD credits, LOE is $2.02 / BOE Currently contracted to 5 third party customers, forecast is for Rig Count16.5 rigs in 2017an increase of only 3 additional third party rigs over 2017 exit Supporting Current23.5 rigs in 2018levels Midstream System24.5 rigs in 2019 STACK inventory is highly competitive in each company’s portfolio and should demand further rig growth Rig Count There is a large amount of rig activity in Major and Blaine 22.5 rigs in 2017 Supportingcounties with a severely underserved G&P market 32.5 rigs in 2018 Expanded PE companies will be looking for growth / exits and will need 33.5 rigs in 2019 Midstream Systemtakeaway that only KFM can provide 73 1 Excludes nonrecurring expenses. Represents NE Kingfisher Hz only.
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NAV Model Assumptions OperatedOther AreaOsageMeramecOswegoDrillCo Pricing & Discount Assumptions Gas Differential (% of HH)95%95%95%95% Oil Differential (% of WTI)94%94%94%94% NGL Realization (% of WTI)45%45%45%45% Drilling Assumptions Number of Drilling Locations2,3881,26448460DrillCo includes all Working Interest—Operated (%)72%74%75%57%Osage Wells Working Interest—Other (%)15%15%13%— NRI—Operated (%)60%61%62%47% NRI—Other (%)12%12%11%— Fixed Operating Cost ($k/well/month)$9.7$9.7$9.7$9.7 Variable LOE ($ / bbl of oil)$2.23$2.23$2.23$2.23 Gas Marketing & Transportation ($ / mcf of gas)—Until 2021$0.35$0.35$0.35$0.35 Gas Marketing & Transportation ($ / mcf of gas)—Thereafter$0.35$0.35$0.35$0.35 Initial Production Tax—Oil (%)2.1%2.1%2.1%2.1% Initial Production Tax—Gas/NGLs (%)2.1%2.1%2.1%2.1% Severance Holiday (months)36363636 Production Tax—Oil (%)7.1%7.1%7.1%7.1% Production Tax—Gas/NGLs (%)7.1%7.1%7.1%7.1% Ad Valorem Tax (%)0.0%0.0%0.0%0.0% Drilling & Completion Cost ($mm) 1$3.5$3.5$2.5$0.3 EUR Assumption Gross EUR Gross Sales Gas EUR (MMcf)1,5711,4251681,571 Gross NGL EUR (Mbbl)14112815141 Gross Oil EUR (Mbbl)250249200250 Total Gross EUR (Mboe)652615243652 Type Curve Assumptions Oil IP, 24-hr (Bbl/d)200170320200 Duration of Incline (Months)22—2 Peak Rate (Bbl/d)350500320350 B Factor1.201.201.201.20 Di-Continuous (Nominal) Decline (%)73%80%72%73% Terminal Decline (%)7%7%7%7% Natural Gas IP, Unshrunk, 24-hr (Mcf/d)500296320500 Duration of Incline (Months)42—4 Peak Rate (Mcf/d)9001,250320900 B Factor1.501.501.201.50 1-Di-Continuous (Nominal) Decline (%)41%56%72%41% Terminal Decline (%)5%5%7%5% NGL Yield (bbls/MMcf)75757575 % Gas Shrink15.9%16.1%15.9%15.9% Note: Assumes 4,800 lateral length for all type curves.74 1 D&C shown including PAD D&C facilities costs.
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Substantial Resources Volumes and PV-10 Value for 4,196 Primary Gross Identified Locations Only PV-10 at Research Consensus PV-10 at NYMEX1 PV-10 at $70/$3.50 OsageOsageOsage $3,541$2,782$4,945 $6,059MM$4,778MM$8,493MM MeramecMeramecMeramec $1,714$1,351$2,412 PDP OswegoPDP OswegoPDP Oswego $484 $231$414 $165$641 $354 DrillCoDrillCoDrillCo $90$67$141 PV-10 at Research Consensus includingBase PV-10 by Operated at Research Identified Locations by Commodity Downspacing2Consensus MeramecOswegoOperated $1,714$231NGL95% DrillCo21%Oil $9041% Low Risk4,1964,196 Osage$9,492MM DownspacingGrossGross $3,541$1,651LocationsLocations Gas Additional38% PDP DownspacingDrillCo Other $484 $1,7822% 3% Note: PV-10 figures are pre-tax, pre-G&A, pre-Net Debt, do not include the impact of hedges, and exclude $64mm Pipeline and facilities capital expenditures (PV-10). PV-10 figures as of 7/1/2017. Reflects Generation 2.0 Type Curve. Assumes Broker Consensus Price Deck (2017: $51.16/bbl / $3.16/mcf; 2018: $54.90/bbl / $3.14/mcf; 2019: $58.00/bbl / $3.05/mcf and held flat thereafter), unless otherwise noted. Does not include additional resource potential or undeveloped locations on ~20,000 net acres recently acquired in the Major County Acquisition. Adjusted for transportation costs paid to KFM. Excludes $1.25 / bbl oil transportation costs. 1 NYMEX strip pricing as of 9/8/2017 close until 2021 and held flat thereafter. For 4,196 Primary Identified locations (for all but bottom left output that includes downspacing).75 2 Low Risk downspacing of Osage to 11 WPS (966 locations), Meramec to 5 WPS (318 locations), and Oswego to 4 WPS (516 locations). Additional downspacing of Osage to 15 WPS (1,288 locations) and Meramec to 8 WPS (954 locations).