Exhibit 99.1

Alta Mesa Resources Pure-Play STACK Enterprise August 2017

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. A ll 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 (“Alt a 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, pl ans 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 s uch 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 bas ed on currently available information as to the outcome and timing of future events. Except as otherwise required by applicable law, Silver Run II, Alt a 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, increas ed operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, processing volumes and pipeline throughput, un certainties related to new technologies, geographical concentration of Alta Mesa’s and KFM’s operations, environmental risks, we ather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in pro jecting 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 a nd limited control over non-operated properties. Should one or more of the risks or uncertainties described in this presentation and the oral statements made in c onnection therewith occur, or should underlying assumptions prove incorrect, Silver Run II’s, Alta Mesa’s and KFM’s actual resul ts 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 an d 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 furt her production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recove red. 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 rati o and capital budget, as well as Alta Mesa’s production and KFM’s volumes, for the fiscal years 2017, 2018 and 2019. Neither Sil ver 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 perform ed 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 ill ustrative 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, econ omic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the pr ojected information. Even if our assumptions and estimates are correct, projections are inherently uncertain due to a number of factors outside our control. A ccordingly, 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 i n the projected information. Inclusion of the projected information in this presentation should not be regarded as a representat ion 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 co mparable 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 amou nts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capita l structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, o r more meaningful than, net income as determined in accordance with GAAP or as an indicator of Alta Mesa’s operating performance or liquidity. Certain it ems excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, s uch 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 E BITDAX. 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 belie ved by Silver Run II, Alta Mesa and KFM to be reliable, including independent industry publications, government publications or o ther 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 int ernal sources as well as the independent sources described above. Although Silver Run II, Alta Mesa and KFM believe these source s 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 th e operation of their respective businesses. This presentation also contains trademarks, service marks and trade names of third p arties, which are the property of their respective owners. The use or display of third parties’ trademarks, service marks, trade names or products in this p resentation is not intended to, and does not imply, a relationship with Silver Run II, Alta Mesa or KFM, or an endorsement or sp onsorship 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

Table of Contents I. Introduction II. Company Overview III. Our Upstream Assets IV. Our Midstream Assets V. Financial Summary VI. Valuation and Timeline Appendix 3

Introduction

Silver Run II Delivering on Investment Criteria Upstream Midstream Assets economic well below current oil price Competitively-positioned assets that benefit from strong supply/demand fundamentals High margin core basin with low field break-evens, deep inventory Expansion opportunities in rapidly growing basin Multiple Stacked Pays Locked-in base returns through stable fee-based contracts High-quality assets with significant unbooked resource potential Assets with return asymmetry from incremental volumes, moderate margin exposure, and/or organic growth projects Opportunities to improve costs through technology Opportunity to expand through technology and acquisitions Synergy with existing upstream portfolio 5 Combined upstream and midstream company allows for significant value uplift from financial optimization

Pure Play STACK Company Premier liquids upstream growth with value-enhancing midstream • World class asset with attractive geology Highly contiguous ~120,000 acres with substantial infrastructure in core of STACK Oil-weighted resource with $25/BBL breakeven; >85% single-well rate of return 4,200+1 gross primary locations; 12,000+1 possible through down-spacing and additional zones • Top-tier operator with substantial in-basin expertise and highly consistent well results 200+ horizontal STACK wells drilled across entirety of Kingfisher acreage maximizes confidence in type well EUR Consistency and geographic breadth of well results affirms repeatability Oil-weighted production in early well life maximizes near-term oil-based revenue (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 potential; 2-year expected EBITDA CAGR of 128% Demonstrated ability to manage a large development program – average of 6 rigs running in 2017 Robust acquisition pipeline 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 Future opportunity to monetize Kingfisher Midstream through an IPO, and fund upstream capital needs through proceeds of an IPO, 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 6 1 Does not include additional resource potential or undeveloped locations on ~20,000 net acres recently acquired in Major, Blaine and Kingfisher counties in July 2017, as described in further detail on page 27 (the “Major County Acquisition”).

Transaction Overview • Jim Hackett and Riverstone raised ~$1 billion through Silver Run Acquisition Corporation II ("Silver Run II") IPO to invest in a market leading company which could generate significant potential return Silver Run II has agreed to merge with Alta Mesa ("Alta Mesa") and Kingfisher Midstream (“KFM”), collectively renamed as Alta Mesa Resources, Inc. (“AMR”) at the closing of the contemplated transaction. The existing Silver Run II public stockholders and Riverstone will collectively hold a 49% interest in the combined Company1 Pursuant to the contemplated transaction, the combined Company implied Firm Value (“FV”) will be ~$3.8 billion at $10 per share, representing the following acquisition metrics: • • FV / 2018E EBITDA FV / 2019E EBITDA 6.1x 3.1 7.3x 4.2 7.1x 3.8 • • • Existing owners of Alta Mesa will roll 100% of their equity into Silver Run II; owners of KFM will retain significant equity stakes Riverstone and related investment vehicles will invest at least $600 million of cash2 Anticipated closing of the transaction in 4Q 2017 1 Assumes no Silver Run II public stockholders elect to have their shares of Class A common stock redeemed in connection with t he closing of the transaction. 2 Includes $400 million of shares of Class A Common Stock and warrants to be purchased from Silver Run II under the forward purchase agr eement 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. 7 AMR KFM Total

Transaction Summary ($ millions) KFM Owners 14% Legacy Owners' Rollover Equity Silver Run II Cash Investment Riverstone Cash Investment 2 $1,993 999 1 600 Shares Outstanding Share Price Equity Value Less: Cash Plus: Debt Firm Value 388.6 $10.00 Legacy Alta Mesa Owners 37% Total Sources $3,591 $3,886 (551) 500 Total Cash Sources $1,599 2 Riverstone 22% Legacy Owners' Rollover Equity Cash to KFM Owners Cash to Alta Mesa Balance Sheet & Interim Capex Funding $1,993 813 786 $3,836 Legacy SRII Owners 27% Total Uses $3,591 Total Cash Uses $1,599 Accounting 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 purc hase 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 shar es 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 Alta Mesa Resources, Inc.: AMR Jim Hackett, Executive Chairman Hal Chappelle, President & CEO Upstream Operations Kingfisher Midstream Corporate Development Land Finance & Mike McCabe Vice President and CFO Mike Ellis Founder and COO Jim Hackett COO Tim Turner Vice President David Murrell Vice President Pro Forma Organizational Structure Transaction Multiples FV / 2018E EBITDA ($543)7.1x FV / 2019E EBITDA ($1019)3.8x Uses Sources Post-Transaction Ownership3 Implied Firm Value Sources & Uses ($ MM)

Company Overview

Alta Mesa Overview Focused on development and acquisition in the STACK MMCF/D acres loading LACTs5 Source: Public Filings, Investor Relations. Note: All reserve figures per NYMEX strip pricing as of 12/31/2016 close; represents 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 80 MMCF/D offtake processing expected 3Q 2017. 5 Lease Automatic Custody Transfer units. 10 Midstream Metrics Natural Gas Processing Current / YE 2017 60 / 3404 Pipelines 300+ miles Dedicated Acreage ~300,000 gross Storage Capacity 50 MBBL with 6 Contiguous Core Position in STACK Oil Window Legend Upstream Metrics Net STACK Surface Acres ~120,000 Current Production (BOE/D) ~20,000 % Liquids 69% Proved Reserves (MMBOE) 144 Resource Potential (MMBOE)1 >1,000 Estimated Potential Gross Identified Locations1 4,196 Estimated Total Gross Locations1,2 12,133 Gross Stack Wells Producing / Horizontal Operated STACK Wells Drilled3 167 / 205 2017 Average Rigs 6

High Caliber STACK Operating Team Cohesive, tenured, scalable team producing world class results Hal Chappelle President and CEO 13 30+ Mike Ellis Founder and Chief Operating Officer 30 30+ Mike McCabe VP and Chief Financial Officer 11 25+ Gene Cole VP and Chief Technical Officer 10 25+ Kevin Bourque VP, Mid Continent Operations 10 20+ David McClure VP, Facilities and Midstream 7 15+ Tim Turner VP, Corporate Planning and Reserves 4 30+ Dave Smith VP, Geology, Geophysics & Exploration 18 30+ Ron Smith VP and Chief Accounting Officer 10 30+ David Murrell VP, Land 10 25+ 11 Relentless focus on technological advancements and continuous learning Corporate / Finance & Accounting (50 Employees) Engineering & Geology (45 Employees) Operations (60 Employees) (40 Contractors) Land (25 Employees) Robust Capabilities, Organizational Scale, Public Company Processes to Drive Long-Term Success Name Position Years at AMR Years Experience

Optimization, Delineation and Expansion Systematic horizontal development and growth of contiguous acreage 12 2016 & 2017 Plan Legend 120,000+ Net Acres 2016 • Production reached ~20 MBOE/D • Drilled 100th STACK HZ well & first Gen 2.5 well • DrillCo JV started, accelerated STACK drilling with 5 operated rigs • Phase I of Kingfisher Midstream completed, with 60 MMCF/D processing plant, crude and gas gathering, transmission pipelines, 50,000 BBL/D crude terminal, and field compression 2017 • 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 1992 - 2013 40,000+ Net Acres 1987 • Founded by Mike Ellis with ~$200K 1991 • Initial Sooner Trend acreage acquired from Conoco/Exxon/Texaco-operated units 2007-2012 • Drilled 27 vertical stratigraphic delineation wells within legacy acreage; defined robust Osage prospectivity in vertical wells • Spud first two operated HZ STACK wells in December 2012 2014 - 2015 73,000+ Net Acres 2013 • Progressed through first two completion designs (Gen 1.0 and Gen 1.5) 2014-2015 • Commenced aggressive STACK leasing/acquisition and accelerated STACK development, increasing from 4 operated rigs (37% of capex budget) to 70% of total capex budget • Built STACK acreage from 40K to 70K+ acres through bolt-on acquisitions

Alluring Macroeconomic Fundamentals High quality rock drives compelling returns, robust rig activity 169.3% 4 5 NYMEX Strip Broker Consensus $70.00/bbl / $3.50/mcf Gen 2.0 Gen 2.5 (‘000 of gross acres) 69% 52% 55% Mesa(7) 175 541 639 Phase I + II Phase III / Western Expansion Phase I + II + III Additional Acreage Under Negotiation 2017E Alta Mesa 2018E Other Producers (Phase I & II) 2019E Other Producers (Phase III) 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 NYMEX strip pricing as of 8/3/2017 close until 2021 and held flat thereafter. 5 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). 6 Not inclusive of producer customers’ entire gross acreage position; additional gross acreage proximate to KFM available for g athering and processing services. Includes additional acreage to come and/or under negotiation. 7Percentage of Phase I & II shown. 13 Alta Mesa - Updip Oil STACK 2 $24.40 Core Midland - Wolfcamp A&B $27.16 S. Delaware Basin - Reeves Wolfcamp A $27.53 STACK Meramec - Over-Pressured Oil $27.71 DJ Basin - Wattenberg Core XRL $32.14 N. Delaware Basin - Wolfcamp XY $33.36 SCOOP Woodford Condensate $34.66 Eagle Ford - Karnes Trough $34.76 393 193 86 22 118 239 128 366 KFM Gas Inlet Volumes by Producer (MMCF/D) % Alta KFM Acreage Dedications / Resource Allocations Breakdown6 102.6% 89.7% 137.1% 82.3% 71.2% Alta Mesa Type Well IRR3 Major U.S. Oil Plays – Breakeven Prices ($/BBL)1

Asset Value of AMR’s STACK Position ~$7B PV-10 Value from Identified Gross Locations before downspacing primary focus of the near-term development plan Major County Acquisition 6 $1,260 to 20 WPS2 to 27 WPS 3Uplift Asset Value Facilities Value 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). 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 (“KFM Margin Uplift”). 1 Illustrative midstream uplift value assumes 2018E EBITDA valued at 13.7x. 2 Low Risk downspacing of Osage to 11 WPS (966 locations), Meramec to 5 WPS (318 locations), and Oswego to 4 WPS (516 locations). 3 Additional downspacing of Osage to 15 WPS (1,288 locations) and Meramec to 8 WPS (954 locations). 4 Assumes 2018E Upstream G&A capitalized at 7.5x. 5 Assumes pro forma net debt at transaction close based on Alta Mesa Q2 2017 revolver balance outstanding. 6 Additional Formations include Big Lime, Manning, Hunton, Woodford, Cherokee, and Chester. 14 Alta Mesa’s 4,196 Identified Gross Drilling Locations are the Combined Illustrative $2,646mm Midstream Value excludes GP/IDRs $395$7,141 $905 $10,574 $1,294 $1,233 $2 $10,266 ($239) ($7) ($64) Additional Formations $687 $1,564 $199 $2,566 $417 PDP Osage Meramec Oswego DrillCoKFM Margin Alta Mesa Third Party Total Base UpliftMidstream Midstream Case Gross Uplift 1Uplift 1 Asset Value DownspacingDownspacing KFM Margin Total Gross G&A 4Net Debt 5 Pipeline & Hedges Net Asset Capex $54 Implied P/NAV: 38%

Our Upstream Assets

Significant Activity in Alta Mesa “Neighborhood” Prominent operators active in Updip Oil Window adjoining Alta Mesa Source: IHS Enerdeq, HPDI. Note: Represents a combination of current and recent rig activity. 1 Operators with 2 rigs or fewer running. 16 Permits 180 Days MRO CLR 1 CLR CLR MRO MRO DVN MRO NFX CLR MRO CLR NFX MRO DVN NFX DVN MRO DVN AMR DVN AMR AMR CHK NFX DVN MRO CHK CHK CHK SD SDSD CHK

Alta Mesa Vision Rigorous development and balance sheet to consolidate regional assets Existing Asset Value • Early phase of systematic Meramec/Osage, and Oswego development Our goal: maximize discounted cash flow • • Improve drilling efficiencies through technology and pad drilling Continually optimize well density, stage spacing, pump rates, fluids, proppant, hydraulics • • Delineate and develop other horizons • Established productive zones – Big Lime, Manning, Cherokee sands, Woodford, Hunton Untested zones – Chester Shale • STACK Enterprise Expansion • Consolidate acreage where we can be best-in-class Operator 17 Note: Wells drilled map as of August 2017. Alta Mesa Position in Expanding STACK/MERGE/SCOOP Area

Progressive Increase in Completion Alta Mesa leadership in operational advancements Intensity • Alta Mesa has proactively advanced completion designs with each generation – leading to improved well response and economics: 100 90 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 80 70 60 • Continuously optimizing completions designs through reduced frac stage spacing for increased formation stimulation 50 40 Avg Frac Stages Avg. Stage Spacing (Ft.) Slickwater - Avg Total (BBLS/Ft.) Sand - Total Avg. (Lbs/Ft.) 12 340 29 317 18 256 42 457 24 194 56 677 32 150 66 1,193 35 140 75 1,500 ? ? ? ? 30 20 10 Frac Design Type Flow Design Type Packers Type Well Count1 Packer/Sleeve Slickwater Mechanical 7 Hybrid Slickwater Hybrid 6 Plug/Perf Slickwater Swell 59 Plug/Perf Slickwater Swell 94 Plug/Perf Slickwater Swell --? ? ? ? 0 0 6 12 18 Production Month 18 1 Wells completed as of 8/16/17 Further Improvement Cumulative Production (MBO) Flowback Rate-Controlled In Early Periods Design ParametersGen 1.0Gen 1.5Gen 2.0Gen 2.5CurrentFuture Current Type Curve – Gen 2.0 Completion Summary By Generation

Average Well Results Results as of YE 2016 with early-stage Gen 2.5 forecasts MBOMBOE • Financial goal: maximize discounted cash flow • Well design goal: optimize stimulated reservoir volume 598 Well spacing Proppant loading Fluid rates Landing zones Average Generation 1.0 Average Generation 1.5 Average Generation 2.0 Expected Generation 2.5 Beyond Generation 2.5 7 6 50 Wells • Approximately 57% of the oil, 50% of the natural gas liquids, and 38% of the natural gas are produced in the first five years thereby enhancing the early revenue per unit and the resulting economics Cumulative % MBOE (2-Stream) Oil % (2-Stream) 100% 18 16 80% 14 • The GOR increases over time with month one approximately 1 Mcf/Bbl, month twelve approximately 5 Mcf/Bbl, month sixty approximately 8 Mcf/Bbl. 12 60% 10 • In month one, 2-stream production from the well is 82% oil and 3-stream production is 86% liquids 8 40% 6 • In year one, 2-stream production from the well is 66% oil and 3-stream production is 74% liquids 4 20% 2 • The well breaches the 2-stream 50% oil point near the end of year 2 and 3-stream production remains above 50% liquids point for the life of the well 0% 0 0 12 24 36 48 60 Months 72 84 96 108 120 Source: Ryder Scott-audited Reserve Report, Company data. 1 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 inje cting 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. 2 LNU17N06W02A Miss well (Ryder Scott-audited Reserve Report). 19 GOR (MCF/BBL) % Liquids (3-Stream) GOR (MCF/BBL) Oil-Weighting Over Time Oil and Liquids Content Over Time2 # of 472 149 247 183 71 Optimizing Stimulated Reservoir Volume Average EUR by Generation1

Cost-Advantaged Asset Base Infrastructure and basic well design mitigate cost inflation 1 $ 12.0 $ 10.0 $ 8.0 2 $ 6.0 $ 4.0 $ 2.0 $ 0.0 3 Naturally Flexibility to use more commoditized proppant 20 1 AMR Pad Drilling D&C only and does not include $300k of allocated facilities cost. Penn Mississippian AMR - MRMC/OSAGE (Gen 2.0) AMR - MRMC/OSAGE (Gen 2.5) CHK - OSWEGO DVN - MRMC SLNP MRO - MRMC DVN - UPPR MRMC NFX - MRMC SXL CLR - MRMC MRO - MRMC XEC - MRMC Updip Oil Window Oswego Pre-Pennsylvanian Unconformity STACK PLAY TESTED HORIZONTAL TARGETS Osage/Meramec True Dip 1 degree SW Cross Section Location Map STACK Regional Stratigraphy Gross D&C1 ($MM) Lat. Length: 4.8k 4.8k 4.8k 5.0k 4.8k 5.0k 9.6k 9.8k 9.6k 10.0k Advantage Why It Matters Shallower Targets Allows for the elimination of additional strings of casing, liner tie-back, and reduces horsepower used during stimulation Reduced drilling time and costs per well enhances capital flexibility and efficiencies One-mile Laterals Reduces mechanical risk of completions vs two-mile Use less steel by utilizing smaller diameter pipe program Lower cost per foot to execute drilling and completions Fractured Formation Heavier proppant loads not required

Alta Mesa: Low Cost Operator Peer leader in operating cost and capital efficiency $24.21 $8.77 $8.89 $8.53 $7.96 2 2 AMR XEC CLR PE FANG RSPP NFX MRO DVN $6.39 0.8x AMR 5 CLR AMR FANG PE RSPP XEC NFXMRO DVN XEC NFXCLR PE MRO RSPP FANG DVN Alta Mesa STACK Peers Permian Peers Source: Public Filings as of 4Q 2016. 1 Calculated as future development costs divided by proved undeveloped reserves. Shown as of 12/31/2016. 2 MRO and DVN PUD F&D evaluated based on US assets only. 3 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 acquisiti ons. 4 Does not include gathering & transportation. 5 LTM 3/31/2017 excluding legacy vertical and waterflood-related production. 21 $4.81$4.98$5.10 $3.58$3.66$3.70$3.87 $2.99 4.0x Illustrative KFM Margin Uplift 3.4x3.2x 3.1x 1.8x1.7x 3.7x 1.1x Q1 2017 LTM LOE ($ / BOE)4 Recycle Ratio3 $13.78 $9.37$10.02 $5.62 SEC Future Development Cost Per Proved Undeveloped BOE ($ / BOE)1

Solid Results Affirm De-Risked Acreage Position Representative wells across 11 townships Operated Barbara 1706 3-22MH Beyer 4-6H Boecher 1706 4-19MH Bollenbach 1705 4-21MH 4,812 4,452 4,832 4,820 579 863 574 994 120 194 119 206 346 505 560 185 82% 75% 72% 55% 72 113 116 38 1 2 3 4 5 Bollenbach 1705 6-30MH 4,795 1,198 250 436 92% 91 Brown 1706 6-27MH 4,850 839 173 316 76% 65 6 7 Cleveland 1805 2-26MH Dixon 1505 3-16MH 4,645 4,858 686 657 148 135 451 325 77% 81% 97 67 8 9 10 EHU 220H EHU 235H Evelyn 1706 5-18MH Francis 1706 5-8MH Gilbert 1706 6-21MH Hawk 1906 7-13MH Helen 1605 5-33MH 3,651 5,300 4,857 4,856 4,738 4,813 4,620 678 559 575 664 590 540 652 186 106 118 137 125 112 141 216 357 621 349 409 216 331 91% 89% 87% 69% 59% 80% 77% 59 67 128 72 86 45 72 11 12 13 14 15 16 17 18 James 1706 5-26MH 4,748 738 155 352 79% 74 19 20 LNU 16-2H LNU 49-4H Mad Hatter 1506 2-34MH Martin 1505 4-9MH Matheson 1705 5-10MH Mitchell 1806 2B-27MH 4,788 4,518 4,670 4,795 4,765 4,598 873 756 632 620 729 646 182 167 135 129 153 140 282 518 294 278 448 311 89% 79% 90% 64% 79% 81% 59 115 63 58 94 68 21 22 23 24 25 26 27 28 29 30 Pinehurst 1706 5-5MH Redbreast 1505 4-7MH Rigdon 17015 6-11MH Rudd 1605 2A-5MH Three Wood 1505 4-17MH 5,061 4,709 4,827 4,010 4,634 672 655 725 520 629 133 139 150 130 136 572 251 697 489 321 75% 73% 82% 58% 76% 113 53 144 122 69 31 32 33 34 35 Vadder 1805 2-12RMH Wakeman 1706 6-25MH Weber 1806 3-22MH 4,504 4,842 4,797 669 925 646 148 191 135 542 787 112 63% 62% 75% 120 162 23 36 37 38 39 Non-Operated Deep River 30-1MH Holiday Road 2-1H King Koopa 1606 2UMH-22 5,586 5,100 4,691 NA NA NA 89 67 83 324 153 380 41% 85% 60% 58 30 81 40 41 42 43 Post 1706 1-30MH Ruzek 1H-3X Trifecta 1807 20H-14-1 4,919 6,872 4,346 456 498 662 93 72 152 461 688 555 66% 67% 92% 90 100 128 44 45 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 ne t 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. 46 22 OOID 1OH-24 5,357 1,459 272 533 88% 99 White Rabbit 1506 2-27MH 4,811 633 132 428 91% 89 Todd 1706 6-4MH 5,019 946 188 599 68% 119 Oak Tree 1605 2-30MH 4,744 813 171 634 69% 134 Oltmanns 1805 6-14MH 4,930 822 167 631 70% 128 Oswald 1705 6-28MH 4,815 1,144 238 278 66% 58 Lankard 1706 6-34MH 4,855 847 174 1,291 58% 266 Hoskins 1705 2-9MH 4,693 932 199 507 85% 108 EHU 219H 4,950 790 160 123 88% 25 Clark 1705 5-12MH 4,657 827 178 615 85% 132 Lateral EUR EUR/'000 IP90 IP90 IP90/'000 Well Name1 Length (MBOE)2 Lateral ft2 (BOE/D) % Oil Lateral ft Notable 2017 Alta Mesa Wells Well Target IP30 (BOE/D) Aces High 1606 4-11MH Osage 823 Coleman 1706 6A-9MH U Osage/L Meramec 514 Dalwhinnie 1605 1-31MH Osage 702 Fazio 1705 1-13MH Osage 909 Hasley 1605 1-28MH Osage 549 Huntsman 1506 2-23MH Meramec 598 Macallan 1806 4-17MH Osage 643 Odie 1606 1-12MH U Osage/L Meramec 849 Peat 1606 1-26MH Osage 522 Pollard 1805 3-2MH Osage 507 Red Queen 1506 1-1MH Osage 509 Shiner 1505 1-3MH Osage 585 Speyside 1606 1-27MH Osage 997 Yellowstone 1505 4-8MH Osage 740

Alta Mesa STACK Development Moving into development mode on de-risked Kingfisher acreage Oswego/ Big Lime 1,500’ Meramec Osage 750’ 1,500’ 750’ 750’ 750’ 750’ • Near term development plan focuses on continued optimization of frac stage spacing, transitioning to development mode, delineating Oswego performance, and accelerating infrastructure investments Delineate and de-risk recently acquired Major County Acquisition acreage All wells in inventory are planned as single-section laterals Transition to primarily pattern development in 2017 Average of 6 rigs running in 2017 • • • • 23 550 ft 450 ft150 ft Alta Mesa Development Strategy 2017 Development Plan Base Case Development Plan For AMR

STACK: A Significant Petroleum System Additional development potential in multiple stacked pay zones • Existing spacing tests at 660’ show full development potential 660’ spacing tests have more than 200 days of online production Over 800 days of strong well performance at spacing of 1,200’ Three target zones in Osage/Meramec, which represents a continuous 550’ section and one additional in Oswego Down-spacing Additional Formations Type Log Formation Targeted Total • • • • Eight zones have proven hydrocarbon production from vertical wells Chester Shale offers added potential AMR and others have already drilled successful Oswego, Meramec, Osage, Woodford, and Hunton horizontal wells Additional formations, including Big Lime and Red Fork, have horizontal permits and strong vertical production Drilling days expected to remain similar across the various formations AMR drilling Manning Limestone in 2017 • • • • • Note: Actual Alta Mesa log above displays productive formations. 24 Additional Zones Big Lime44 Oswego224 Cherokee Shale Prue Sand Skinner Sand44 Red Fork Sand Manning Lime44 Chester Shale44 Meramec448 437 Osage 448 Woodford Shale88 Hunton Lime44 Total14132855 Potential 55 Wells per Section Alta Mesa Existing Development

Deep Drilling Inventory 4,196 Identified Gross Locations represent 14+ years of inventory Osage Meramec Oswego Big Lime Manning Hunton Woodford Other3 Note: Identified locations based on AMR interest in 320 Meramec/Osage and 257 Oswego sections; excludes additional resource p otential or undeveloped locations on ~20,000 net acres recently acquired in the Major County Acquisition. 1 Low Risk downspacing of Osage to 11 WPS (966 locations), Meramec to 5 WPS (318 locations), and Oswego to 4 WPS (516 locations ). 2 Additional downspacing of Osage to 15 WPS (1,288 locations) and Meramec to 8 WPS (954 locations). 3 Other Formations include Cherokee and Chester. 25 Alta Mesa’s 4,196 Identified Gross Drilling Locations are the primary focus of the near-term development plan 174 12,133 8,238 484 4,196 2,448 OsageMeramecOswegoCurrent Identified (8 WPS)(4 WPS)(2 WPS)Targeted Locations Downspacing to Downspacing to Current IdentifiedAdditionalOther Additional Total PotentialMajor County 20 WPS 127 WPS 2and Downspacing Formations -FormationsLocationsAcquistion Locations2017 Drilling 1,264 516 318 966 954 1,288 484 488 753 1,996

Progressive Execution Track record of growth in production, reserves, acreage position 102,466 Recent addition YE 2013 YE 2014 YE 2015 YE 2016 Core STACK acreage 22.2 2012 2013 2014 2015 2016 June 2017 • Acreage has grown from ~40,000 net acres to ~120,000 net acres since 2013 143.6 • Disciplined acreage aggregation focused primarily on ”bolt-on” acquisitions to systematically increase contiguous position • July 2017 added ~20,000 net acres in Major, Blaine, and Kingfisher; geologic character similar to central-eastern Kingfisher acreage 17.0 8.7 YE12 YE13 YE14 YE15 YE 16 (SEC) YE 16 (NYMEX) 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 YE 2016 proved reserves as of 12/31/2016 close. 3 YE12-15 proved reserves based on NYMEX pricing. 26 129.6 68.3 27.6 Proved Reserves (MMBOE)2,3 13.1 8.8 4.8 1.01.7 Total Net Production (MBOE/D)1 73,512 40,587 44,506 Net STACK Acreage Alta Mesa Footprint

• •• I •• .. •Ell•is • &:. .. t-... • a Hemphill • Rbge; • ·-I • I • • • • • • •• Ctar • -fs... D Alta Mesa Kingfisher Acreage D Alta Mesa Major County Acquisition Actionable Acreage - Washita - 27 Source Investor Presentations. 1Derrick Private Equity Backed/Prvi ate Company (-2.1MM Gross A cres) Public Company (-0.5 MM Gross A cres) Public Company I Private Equity Backed/Private Company Overlap Alta Mesa Overlap o I • 1 • •••

Our Midstream Assets

KFM is Value Accretive to Alta Mesa Vertical integration yields substantial strategic and financial benefits including 80 MMCF/D of additional offtake 29 Rapidly Expanding G&P Complex in the Heart of the STACK •KFM is positioned to capture volume growth from the STACK •Acreage dedications / resource allocations of ~300,000 gross acres Gathering, Processing and Market Access Support Production Growth •Total processing capacity is expected to be 340 MMCF/D in 4Q 2017, •Substantial firm transport to support future growth Bundled Natural Gas Residue Solution Enhances Marketability •KFM capable of providing takeaway solutions to end-markets today •KFM has secured firm takeaway capacity on PEPL and OGT Competitive Advantage in Acquisitions •KFM well positioned to serve other operators; major gas pipeline projects recently announced by others will be more costly and less timely •Modern processing recoveries and priority residue access to premium markets should result in higher netbacks KFM’s Expansion Offers Complementary, High-Growth Development Project •Expansion focused on the next stage of STACK development •Limited G&P infrastructure provides opportunity for KFM expansion •KFM involved in negotiations with anchor customers Midstream Business Can Support Future Capital Needs •Volumetric growth from third-party development provides upside •Attractive trading multiples and GP/IDR optionality / currency •Future opportunity to monetize KFM and fund upstream capital needs through an MLP IPO, drop downs, and GP / IDR distributions

Market Multiples for Midstream Higher than Upstream Alta Mesa owners to capture GP / IDR cash flow / multiple arbitrage • Likely valuation uplift (multiple arbitrage vs. traditional peer group) 30.0x GP Median: 25.3x 23.8x 25.0x 20.0x 15.0x 10.0x 5.0x 0.0x AMGP EQGP EQM AM HESM NBLX DVN XEC CLR NFX Base 2,668 Multiple Midstream GP Upstream •Potential to continue to benefit from cash flows through retained LP, GP, and IDR ownership interest ($ in millions) $5,275 EBITDA Splits Multiple Implied Value Value of Margin in Upstream MLP Multiple Expansion MLP Value Multiple Expansion Potential Midstream Value (MLP + GP) Uplift 30 1 Illustrative KFM future value expansion assuming KFM 2019E EBITDA of $318mm. FV / 2018E EBITDA $4,350 $2,390 $1,960 $924 Upstream Midstream GP $1.0 100% $1.0 100% $1.0 75%25% 7.5x 13.7x 13.7x25.3x $7.5 $13.7 $10.3$6.3 --1.8x 2.2x Illustrative Value Accretion from GP Structure Illustrative Midstream Value Creation1 Upstream4.8x6.1x8.1x6.3x 26 .8x 13.8x13.8x13.6x12.3xMidstream Median: 13.7x 9x Upstream Median: 7.5x 7.9x7.7x7.3x5. Valuation Arbitrage

Kingfisher Midstream Summary Existing Infrastructure mi. Note: Represents multiple lines in ditch. 1 Includes 16 miles under construction 2 Includes 20 miles under construction 31 Natural Gas Processing •Current processing capacity of 60 MMCF/D •Second 200 MMCF/D plant under construction •80 MMCF/D offtake processing expected 3Q 2017 •1,200 BBL/D condensate stabilizer Low Pressure Pipeline •223 miles1 of low-pressure crude and gas gathering lines Natural gas gathering: 6”-16” pipeline Crude gathering: 6”-8” pipeline High Pressure Pipeline •98 miles2 of 4” to 16” rich gas transportation 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 Facilities •Field Compression 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 3516 at West Kingfisher Compressor Site 1 CAT 3508 at 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 Infrastructure •50,000 BBL crude storage with 6 truck loading LACTS •3 NGL bullet tanks: 90,000 gallon capacity Producer Connections •54 central delivery point receipt connections serve 188 units Cushing ~60

KFM Midstream Takeaway Overview Pipeline Description Current Takeaway Capacity Expansion Projects Commentary producers. KFM’s residue position provides KFM producer clients insuring that KFM producer customers can rates that will be needed to solidify new netbacks for KFM producers dedicated to netbacks the area optionality between in-state and the Gulf 32 Natural Gas •Connected to PEPL – owned and operated by Energy Transfer •PEPL consists of four large diameter pipelines extending approximately 1,300 miles throughout Mid-Continent and other market centers •KFM will connect to OGT Q3 2017 •OGT services local Oklahoma gas demand, but via on expansion will begin to deliver gas to WAHA in Q2 2018 •100,000/day FT on PEPL •50,000/day FT on OGT, expanding to 125,000/day June 2018 25,000 Dth/d for 4 years 100,000 Dth/d for 10 years •KFM in discussion with all proximate outlet pipelines looking to expand out of the basin •Gas takeaway is functionally full creating a constrained environment for some flow assurance and better netbacks for •Residue gas is split connect between PEPL and OGT, and under long term agreements flow out of the basin •Capacity rates are low compared to new capacity out of the basin creating better the system NGL •Connected to Chisholm Pipeline - operated by Phillips 66 •Delivers NGLs to Conway •Operational capacity of ~41,000 Bbls/d on existing Chisholm line • Currently under a 3 year contract extendable for 2 1-year terms with shipper history •Opportunity to tie into other NGL pipelines in the area • Volumes could warrant expansion or new build to Mt. Belvieu •Connected to P66’s Chisolm Y-grade pipeline that takes Y-grade to Conway, KS for fractionation • Multiple NGL lines within 7 miles of plant to further diversify Y-Grade options when needed •KFM Y-grade optionality will allow producers to capture netback uplift between Conway, KS and Mt Belvieu Crude •Crude gathered to a central delivery point at the plant site •Six truck bays for LACT loading and unloading •Multiple pipeline connection options •Not currently committed •Long haul pipeline opportunities to Cushing and other demand sources in •Crude system is focused around keeping Alta Mesa barrels and future third party barrels clean to market, producing better •Proximity to Cushing provides market Coast refineries. • No long terms commitments provide KFM the option to build out long-haul crude pipelines enhancing drop down inventory

KFM Phase III Expansion Overview • Recent Major county acquisition adds scale through ~20,000 acre dedication • 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 33

Financial Summary

Financial Strategy and Pro Forma Financial Impacts • Demonstrated trajectory to positive free cash flow with near-term development funded with transaction proceeds Secure robust liquidity to fund development, with near-term production growth ensured by KFM takeaway capacity 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 leverage through the cycle Preserve an optimal debt maturity profile Maintain simplified balance sheet • • • Prudent capital budget focused on securing leasehold and developing existing acreage Ensure capital budget is flexible to future changes in commodities and/or service costs Continued rolling hedge strategy to protect revenues and support development program • • 1 Cash to balance sheet includes funding for interim cash needs until closing. 2 Current revolving credit facility balance as of 8/10/2017 does not include approximately $5mm of letters of credit. 3 Change of control not triggered for 2024 Senior Notes upon execution of transaction. 35 Protect Cash Flow Maintain Conservative Balance Sheet Significant Financial Flexibility Capitalization at Announcement Current ($ in millions, unless specified) Alta Mesa KFM Adjustments Pro Forma Cash and Cash Equivalents $5 $28 $5171 2 2 Revolving Credit Facility 269 $0 (269) 7.875% Senior Notes due 2024 500 $551 0 5003 Total Debt $769 $0 ($269) Net Debt 763 $500 (51) Financial and Operating Statistics 2017E EBITDA $155 $42 2018E EBITDA 358 184 2019E EBITDA 701 318 Credit Metrics Net Debt / 2017E EBITDA 2018E EBITDA 2019E EBITDA Liquidity Expected Borrowing Base $315 $200 Less: Amount Drawn 269 (269) $197 543 1,019 NM NM NM $515 0 Expected Borrowing Base Availability $46 Plus: Cash and Cash Equivalents 5 $515 551 Liquidity $52 $1,066

2017 Capital Budget and Hedge Position Alta Mesa Upstream 14% • Alta Mesa’s 2017 net capital budget is estimated to be $349MM, ~11% higher than capital expenditures of $316MM in 2016 Alta Mesa estimates that ~$108MM 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 $458MM, including the Bayou City Energy JV FY 2017 acquisition (including leaseholds) capex spending expected to total $85MM, 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 % Midstream $154 42% • $147 $147 • • • • Kingfisher Midstream • • KFM’s 2017 net capital budget is estimated to be $251MM Growth capital categorized through processing, pipeline, high / low pressure well connects, compression lease principal payments and compression lease interest expense items Q1 2017 Q2 2017 Q3 2017 Q4 2017 Alta Mesa KFM 32,510 10,698 Jul-Dec'17 2018 2019 Aug-Dec'17 2018 Average Floor Price ($/BBL) Average Floor Price ($/BBL) $3.18 $4.43 $49.55 $51.67 $50.00 36 1 Does not include Bayou City Energy JV. 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. Jul-Dec'1720182019 Aug-Dec'17 2018 16,233 6,500 3,400 Gas Hedges (MCF/D) – as of 6/30/17 Oil Hedged (BBL/D) – as of 6/30/17 Acquisition (Including $70 Leasehold) $68 $65 $92 $84 $82 $24 $55 $44 Commentary 2017E Capital Budget by Quarter ($MM) – Excl. Acquisitions1

Valuation and Timeline

Summary Financial Projections ($ in millions unless otherwise noted) Capital Expenditures (excl. DrillCo Funds) 1 Average Net Daily Production (BOE/D) $1,019 68,900 $837 $761 $4 2017 2018 Alta Mesa 2019 2017 Alta Mesa 2018 KFM Phases I &II 2019 KFM Phase III 2017 Alta Mesa 2018 KFM Phases I &II3 2019 KFM Phase III Drill Co Free Cash Flow2 Forecast Total Wells by Year $945 239 $142 1 ($447) 2017 2018 2019 2017 2018 2019 2017 2018 2019 6 10 11 Rigs 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 DrillCo Funds is Bayou City JV deal. 2 Phase I & II capex includes planned, non-optional Phase III capex. 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 ($155)mm from current until year -end 2017. 38 Avg. 207 120 $92 $5 ($237) ($233) ($24) ($210) ($257) $910 $803 Liquidity3 $89 $601 $62 $137 $147 $611 $74 $552 $178 $349 38,510 2,003 66,897 20,841 36,812 20,292 $543 $63 $255 $701 $197 $44 $141 $358 $38 $155 EBITDA(X)

Valuation Benchmarking ($ in millions unless otherwise noted) Firm Value / 2018E EBITDA Firm Value / 2019E EBITDA 7.9x 7.9x 7.7x 7.7x 7.6x 7.3x 6.6x 6.4x 6.1x 6.1x 6.1x 5.9x 6.0x 4.3x MTDR DVN LPI XEC RSPP CLR CPE AMR NFX DVN LPI MTDR XEC CLR RSPP NFX CPE AMR Adjusted Firm Value1 / Net Acres 2017E – 2019E Production CAGR $30,011 82% 43% 32% 21% 21% 19% 18% 15% 15% 6% GPOR / Vitruvian 2 DVN / Felix 2 AMR 3 AMR CPE RSPP EQT MTDR AR CLR NFX CNX DVN 1 PDP value adjusted at $30,000 / BOE/D unless otherwise noted. 2 PDP value adjusted at $15,000 / BOE/D. 3 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. 39 $22,063 $14,180 5.3x 4.7x 3.1x 6.5x

Benchmarking KFM Against High Growth G&P Peers ($ in millions unless otherwise noted) Firm Value / 2019E EBITDA 13.8x 13.8x 13.6x 11.4x 11.2x 10.1x 8.7x 1 KFM KFM 1 EQM AM HESM NBLX AM EQM HESM NBLX Consolidated 2017E – 2019E EBITDA CAGR 175% 128% 33% 23% 27% 26% 19% 22% KFM NBLX AM EQM HESM AMR+KFM EQT AR NBL HES Integrated Upstream/Midstream Peers 40 1 Includes midstream Firm Value only. 41% 41% Midstream 2017E – 2019E EBITDA CAGR 4.2x 12.3x 7.3x Firm Value / 2018E EBITDA

Anticipated Transaction Timeline • File preliminary proxy statement / marketing materials with the SEC Mid-September 2017 41 Mid/Late-November 2017•Anticipated close DateEvent Weeks of September 4th – September 29th •Transaction marketing

Pure Play STACK Company Premier liquids upstream growth with value-enhancing midstream • World class asset with attractive geology • Top-tier operator with substantial in-basin expertise • Industry-leading growth potential; 2-year expected EBITDA CAGR of 128% • Highly strategic and synergistic midstream subsidiary with Kingfisher Midstream • Financial strength and flexibility to execute business plan through the cash flow positive in 2019 cycle; 42

Appendix

Alta Mesa Management Jim Hackett Executive Chairman and COO of Midstream Hal Chappelle President and Chief Executive Officer Michael McCabe Vice President and Chief Financial Officer • Jim Hackett is a Partner at Riverstone and became a director of Silver Run II in 2017 • Hal Chappelle joined Alta Mesa as President and CEO in 2004 and became a director in 2004 • Michael McCabe joined Alta Mesa in 2006 and became a director in 2014 • Raised private equity capital for Alta Mesa from Denham Capital in 2006, HPS Investment Partners in 2013, and Bayou City in 2015; successfully navigated Alta Mesa through two industry cycles • Prior roles include: • Developed Alta Mesa into a premier STACK operator, building a strong management and technical team Chairman and CEO of Anadarko o President and COO of Devon Energy o • Successfully navigated Alta Mesa through significant industry cycles, building the Company’s oil assets in 2009-2010 and divesting of the company’s gas assets in 2014-2016 • Has over 25 years of corporate finance experience with a focus on the energy industry Chairman, President and CEO of Ocean Energy o President of several midstream companies, as well as responsible for DCP Midstream and Western Gas Resources o • Previous management experience includes serving as President and sole owner of Bridge Management Group, Inc., a private consulting firm • Over 30 years of industry experience in field operations, engineering, management, trading, acquisitions and divestitures, and field re-development • Director of Enterprise Products Holdings, Fluor Corporation, National Oilwell Varco, Sierra Oil & Gas, and Talen Energy • Mr. McCabe’s leadership experience also spans senior positions with Bank of Tokyo, Bank of New England and Key Bank • Previously held roles at Louisiana Land & Exploration, Burlington Resources, Southern Company and Mirant • Former Chairman of the Board of the Federal Reserve Bank of Dallas • Holds a Bachelor of Chemical Engineering from Auburn University and an M.S. in Petroleum Engineering from the University of Texas • Holds a B.S. in Chemistry and Physics from Bridgewater State University, an M.S. in Chemical Engineering from Purdue University, and an MBA from Pace University • Holds a B.S. from the University of Illinois and a MBA/MTS from Harvard University 44

Alta Mesa Management Michael Ellis Founder and COO of Upstream Operations Gene Cole VP and Chief Technical Officer David Murrell VP, Land and Business Development • Michael Ellis founded Alta Mesa in 1987 after beginning his career with Amoco Served as Chairman and COO as well as Vice President of Engineering and has over 30 years of experience in management, engineering, exploration, and acquisitions and divestitures Built Alta Mesa’s asset base by starting with small earn-in exploitation projects, then growing with successive acquisitions of fields from major oil companies Holds a B.S. in Civil Engineering from West Virginia University • Gene Cole has served in the position of Vice President and Chief Technical Officer since 2015 and became a director in 2015 Over 25 years of extensive domestic and international oilfield experience in management, well completions, well stimulation design and execution Started his career with Schlumberger Dowell as a field engineer and served in numerous increasingly responsible positions from 1986 to 2007 Holds a B.S. in Petroleum Engineering from Marietta College • David Murrell has served as Vice President, Land and Business Development since 2006 Over 25 years of experience in Gulf Coast leasing, exploration and development programs, contract management and acquisitions and divestitures Created a structured land management system for Alta Mesa and built a team of lease analysts, landmen, and field representatives to facilitate Alta Mesa’s growth Holds a B.B.A in Petroleum Land Management from the University of Oklahoma • • • • • • • • • Kevin Bourque VP, Operations Tim Turner VP, Corporate Development David McClure VP, Facilities & Midstream • Kevin Bourque progressed through several roles to the position of Vice President of Mid-Continent Operations in 2012 when we began STACK horizontal drilling program He joined Alta Mesa as a field engineer in 2007 Led the growth of our mid-continent drilling and production operations as we expanded our presence in Oklahoma 10+ years of E&P operational experience with Alta Mesa 10+ years of project management and business management experience as the owner of his own company • Tim Turner joined Alta Mesa as Vice President of Corporate Development in 2013 Over 30 years of industry experience including various operations, reservoir engineering and managerial roles with Sun Oil, Santa Fe Minerals, Fina Oil & Chemical, Total, Newfield Exploration, and Quantum Resources Led multi-disciplined A&D and asset teams Managed corporate reserves and planning functions Led business development and new ventures teams Holds a B.S. in Petroleum Engineering from the University of Texas and an MBA in Finance from Oklahoma City University • David McClure has served as Vice President of Facilities and Midstream Operations since 2016 From 2010 to 2016, he was Vice President for Louisiana Operations, leading a multi-disciplined team of engineers, regulatory, land, geoscience, and operations personnel in development of the Weeks Island field Previously held roles at ExxonMobil Production Company and Tetra Technologies Over 15 years of industry experience in field operations, facilities and subsea engineering, pipelines, and management Holds a B.S. in Chemical Engineering from Auburn University 45 • • • • • • • • • • • • •

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. 300% 250% 200% 150% 100% 50% 0% (50%) 240% 74% Dec-03 Feb-05 Apr-06 Jun-07 Anadarko Aug-08 Oct-09 Dec-10 Feb-12 S&P 500 Index 250% 210% 200% 150% 100% 50% 0% (17%) (50%) Mar-99 May-00 Aug-01 Oct-02 Dec-03 Ocean (Devon)1 S&P 500 Index 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. 1 Chart displays Ocean share price performance until merger with Devon completed. Thereafter, chart shows Devon performance on a per-Ocean share basis. 46 Ocean (Devon)1 Public Market Outperformer (1999 – 2003) Anadarko Public Market Outperformer (2003 – 2013) Strategic Thought Leader •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 Benchmark for Operational Excellence and Execution •Premier operator with some of the best production metrics in U.S. onshore, U.S. Gulf of Mexico, and offshore East Africa

Well Spacing Optimization on De-Risked Acreage DVN, CLR, MRO, NFX and AMR aggressively defining optimum spacing Meramec/4-well Woodford Test ¯ Optimization of 0 1.75 3.5 7 47 Source: 1Derrick, IHS, Drilling Info and Company Presentations. Test 880’ Upper/Lower Meramec Test (74%oil) Meramec/4-well Woodford Test Alta Mesa—3-well Spacing Test Borelli – Dodd Pattern S8-17N 5W Lower/Middle (1,500’) Osage Alta Mesa—3-well Spacing Test Oswald Pattern S28-17N 6W Lower/Middle (1,500’) Osage Continental—Verona STACK Pilot, 8-well 1,320’ Upper/Lower Meramec Newfield—Dorothy Pilot, 5-well Spacing Test 1,050’ Upper/Lower Meramec Alta Mesa Well Spacing Miles Devon—Alma, 5-well Spacing Test IP60 1,300boed, Upper/Lower Meramec Cimarex—Gundy, Future 10-well Spacing in Meramec/9-well Spacing in Woodford 550’ Upper/Lower Meramec Alta Mesa – 4 Well Spacing Test Huntsman Pattern S23-15N 6W 1,200 ft. spacing Osage and Meramec Devon—Born Free, 13-well Spacing Test 400’ Upper/Lower Meramec Devon - Pump House, 7-well Spacing Test 2,200 lbs/ft proppant, 4,700’ laterals Upper Meramec Continental—Gillilian STACK Pilot, 8-well Meramec/4-well Woodford Test 1,320’ Upper/Lower Meramec Marathon—Yost, 6-well infill Spacing Test Meramec Newfield—Chlober, 5-well Spacing Test 1,050’ Upper/Lower Meramec Continental—Bernhardt STACK Pilot, 8-well Meramec/4-well Woodford Test 1320’ Upper/Lower Meramec Continental—Blurton STACK Pilot, 8-well 1,320’ Upper/Lower Meramec Continental—Ludwig Pilot, 8-well Spacing 1,320’ Upper/Lower Meramec Newfield—Raptor-X Pilot, 6-well Spacing Alta Mesa—4-well Spacing Test EHU 230, 231,232, 233 S6-18N 6W Lower/Middle Osage, 660’ Alta Mesa—5-well Spacing Test LNU 15-4, 15-5, 16-2,16-3, 16-4 Lower (1,320’)/Middle (1,200’) Osage Alta Mesa—10-well Spacing Test Bullis – Coleman Pattern S9 17N 6W Lower/Middle (932’) Osage; Lower Meramec Nemaha Ridge Uplift Well Tests Continental Devon Energy Gastar Longfellow Marathon MRO & NFX Newfield Alta Mesa Alta Mesa & NFX Alta Mesa & MRO Chaparral Cimarex Newfield—Stark Pilot, 10-well Spacing Test Upper/Lower Meramec Alta Mesa—4-well Spacing Test EHU 237, 239, 240, 241 S9-19N 6W Lower/Middle Osage, 1,500’ Alta Mesa is the Leader in the Oil Window with Successful Long Life Spacing Tests

Completion Design Focus on increasing stimulated reservoir volume D&C Cost / Lateral Foot • • • • • • Progressed through testing multiple generations Highly fractured area benefits from “open-hole” design Targeting average lateral length of 4,800ft (one-mile) Drilling N–S orientation to intersect natural fractures Controlled flowback rate to optimize conductivity Generation 2.5 proppant loading is optimum at an average of 1,400 lb/ft; tested up to 2,100 lb/ft Actual D&C Target Pattern Test D&C Actual D&C Target Pattern Test D&C $1,359 $5.1 $4.7 • • • • • • 7” intermediate casing + 4.5” liner in lateral Open-hole swell packers; proppant loading of 1,400 lbs/ft 3 joints (casing) between packers defines 150ft stages 10,000 bbls of slick water per stage 100 bbl/min total fluid injection rate TaTrgaertgPetad TaTrgaergt ePtad 2012 2013 2014 2015 2016 2012 2013 2014 2015 2016 DrPilalindg DPrilalidng Drilling Cap flowback rate at 100 bbl/hr of total fluid 46 34 25 17 13 13 Spud to TD Proppant Fluid 1,400 8,000 10,752 10,864 3,000 11,000 35 400 340 7,000 1,200 350 30 2,500 10,000 6,000 300 1,000 25 2,000 9,000 5,000 250 800 20 4,000 1,500 8,000 200 600 15 3,000 150 1,000 7,000 400 10 2,000 100 500 6,000 200 5 50 1,000 0 5,000 0 0 0 0 Gen 1.0 Gen 1.5 Gen 2.0 Gen 2.5 Gen 1.0 Gen 1.5 Gen 2.0 Gen 2.5 Gen 1.0 Gen 1.5 Gen 2.0 Gen 2.5 Fluid/Lateral Ft. Fluid / Stage Stages Stage Spacing Proppant Lbs./Lateral Ft. Total Proppant 48 Source: Company Data. Fluid / Stage Total Proppant ('000 Lbs.) Stage Spacing (Ft.) Average Stages Total Avg. Lbs. / Lateral Ft. Fluid / Lateral Ft. 32 256 24 150 18 194 12 1,275 677 6,078 457 3,122 317 2,128 1,339 2,630 9,860 2,352 9,750 1,764 1,218 Averages by Completion Generation Stage Spacing Avg. DaysDrilling Current Completion Design Targets $4.2 $3.4 $3.4 $3.2 $1,074 $940 $720 $713 $667 Total D&C Cost ($MM) STACK Well Completion Strategy

Multiple Long Term Density Pattern Tests Density Patterns Test Horizontal and Vertical Spacing 600' 600' 180' 180' 1,320' 1,320' 1500' Implies 12 wells per section Cum 480 MBOE – 540 days 1500' Implies 12 wells per section Cum 622 MBOE – 780 days Implies 12 wells per section Cum 663 MBOE – 660 days 1 121 241 361 481 601 334' 334' 170' 660' 334' 1236' 330' 330' 466' 466' 466' 466' 466' 310' 180' 140' 140' 140' 660' 1,002' 1,126' 618' Implies 12 wells per section Cum 12 MBOE – 19 days 932' 932' 618' 618' Implies 24 wells per section Cum 319 MBOE – 360 days Implies 18 wells per section Cum 348 MBOE – 56 days 4 X 49 Pattern Results 1,000,000 100,000 10,000 1,000 100 1121241361481601 Cum BO - 4 Wells Mean - 4 X 259 MBO 250 MBO 1,000,000 100,000 10,000 1,000 100 1121241361481601 Cum BO - 10 Wells Mean - 10 X 250 MBO 1,000,000 100,000 10,000 1,000 100 1121241361481601 Cum BO - 4 Wells Mean - 4 X 259 MBO 230' 230' Spacing Pattern 1,000ft spacing / 3 benches Section 9 & 10 17N 6W 660ft spacing / 2 benches Section 31 19N 6W 1,200ft spacing / 2 benches Section 23 15N 6W Pattern Results 1,000,000 100,000 10,000 1,000 100 Cum BO - 5 Wells Mean - 5 x 250 MBO 1,000,000 100,000 10,000 1,000 100 1121241361481601 Cum BO - 3 Wells Mean - 3 x 259 MBO 1,000,000 100,000 10,000 1,000 100 1121241361481601 Cum BO - 3 Wells Mean - 3 x 259 MBO 180' Spacing Pattern 1,500ft spacing / 2 benches Section 8 17N 5W 1,500ft spacing / 2 benches Section 28 17N 5W 1,320ft spacing / 2 benches Section 29 18N 5W

NAV Model Assumptions Operated Other Area Osage Meramec Oswego DrillCo Gas Differential (% of HH) Oil Differential (% of WTI) NGL Realization (% of WTI) 95% 94% 45% 95% 94% 45% 95% 94% 45% 95% 94% 45% Working Interest - Other (%) NRI - Operated (%) NRI - Other (%) Fixed Operating Cost ($k/well/month) Variable LOE ($ / bbl of oil) Gas Marketing & Transportation ($ / mcf of gas) - Until 2021 Gas Marketing & Transportation ($ / mcf of gas) - Thereafter Initial Production Tax - Oil (%) Initial Production Tax - Gas/NGLs (%) Severance Holiday (months) Production Tax - Oil (%) Production Tax - Gas/NGLs (%) Ad Valorem Tax (%) Drilling & Completion Cost ($mm) 1 15% 60% 12% $9.7 $2.23 $0.35 $0.35 2.1% 2.1% 36 7.1% 7.1% 0.0% $3.5 15% 61% 12% $9.7 $2.23 $0.35 $0.35 2.1% 2.1% 36 7.1% 7.1% 0.0% $3.5 13% 62% 11% $9.7 $2.23 $0.35 $0.35 2.1% 2.1% 36 7.1% 7.1% 0.0% $2.5 --47% --$9.7 $2.23 $0.35 $0.35 2.1% 2.1% 36 7.1% 7.1% 0.0% $0.3 Gross EUR Gross Sales Gas EUR (MMcf) Gross NGL EUR (Mbbl) Gross Oil EUR (Mbbl) 1,571 141 250 1,425 128 249 168 15 200 1,571 141 250 Total Gross EUR (Mboe) 652 615 243 652 Oil IP, 24-hr (Bbl/d) Duration of Incline (Months) Peak Rate (Bbl/d) B Factor Di-Continuous (Nominal) Decline (%) Terminal Decline (%) Natural Gas IP, Unshrunk, 24-hr (Mcf/d) Duration of Incline (Months) Peak Rate (Mcf/d) B Factor 1-Di-Continuous (Nominal) Decline (%) Terminal Decline (%) NGL Yield (bbls/MMcf) % Gas Shrink 200 2 350 1.20 73% 7% 170 2 500 1.20 80% 7% 320 --320 1.20 72% 7% 200 2 350 1.20 73% 7% 500 4 900 1.50 41% 5% 75 15.9% 296 2 1,250 1.50 56% 5% 75 16.1% 320 --320 1.20 72% 7% 75 15.9% 500 4 900 1.50 41% 5% 75 15.9% 50 Note: Assumes 4,800 lateral length for all type curves. 1 D&C shown including PAD D&C facilities costs. Type Curve Assumptions EUR Assumption Drilling Assumptions Number of Drilling Locations2,3881,26448460 Working Interest - Operated (%)72%74%75%57% DrillCo includes all Osage Wells Pricing & Discount Assumptions

Osage Type Curve • • • • • 118 Generation 2.0+ wells with production history Average Generation 2.5 lateral length of 4,612’; Generation 2.0+ 4,767’ Type Curve average 30-day IP 0.3 MBOE/D Type Curve average 180-day cumulative production of 75 MBOE Generation 2.5 Type Curve 1,200 nths % 1,000 – – 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 800 • Type Curves assume 16% Shrink and 75 bbl/MMcf NGL yield 600 200 180 160 140 120 100 80 60 40 20 Gen 2.5 Type Curve 400 200 0 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (Months) 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Time (Months) 51 Note: Production data normalized for 4,800’ lateral length. 1 NYMEX Strip as of 8/3/2017. Does not include $300k PAD D&C facilities costs. Adjusted for transportation costs paid to KFM. Excludes $1.25 / bbl oil transportation costs. Cumulative Gross Production (MBOE) Gross Production (BOE/D) Gen 2.0 Type Curve Average Type Curve Cumulative Production Gen 2.5 Type CurveGen 2.5Gen 2.0 Gen 2.0 Type CurveInitial Rate (BO/D / MCF/D)200 / 500200 / 500 Incline Period (oil / gas)2 months / 4 months 2 months / 4 mo AMR Gen 2.0 Well ResultsPeak Rate (BO/D / MCF/D)400 / 900350 / 900 AMR Gen 2.5 Well Resultsb factor (oil / gas)1.2 / 1.51.2 / 1.5 Initial Decline (oil / gas)71% / 41%72.6% / 41.2 Lateral Length4,8004,800 1 Type Well IRR %89.7%71.2% Key Statistics Average Type Curve Summary

Meramec Type Curve • Over 100 wells drilled in the Meramec by Newfield, Devon, Marathon, Gastar, and Chaparral Alta Mesa is beginning to drill Meramec wells with performance expectations similar to the Osage Alta Mesa will be joint developing the Meramec with Osage stack and staggered well tests Majority of active rigs in the STACK play are targeting the Meramec to the southwest Average Type Curve Results 1,200 Meramec Type Curve • • 1,000 • • – – 532 MBOE 2-Stream EUR; 615 MBOE 3-Stream EUR 249 MBO, 1.4 BCF residue, 128 MB NGL 800 • Type Curve assumes 16% Shrink and 75 bbl/MMcf NGL yield 600 250 200 400 150 100 200 50 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Time (Months) 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Time (Months) Note: Production data normalized for 4,800’ lateral length. 1 Offset results based on Meramec wells drilled in the Updip Oil window of Kingfisher County since 2014. 2 NYMEX Strip as of 8/3/2017. Does not include $300k PAD D&C facilities costs. Adjusted for transportation costs paid to KFM. Excludes $1.25 / bbl oil transportation costs. 52 Cumulative Gross Production (MBOE) Gross Production (BOE/D) Meramec Type Curve Meramec Offset Well Results Average Type Curve Cumulative Production Offset Well Results1 Initial Rate (BO/D / MCF/D) 170 / 296 Incline Period (oil / gas) 2 months / 2 months Peak Rate (BO/D / MCF/D) 500 / 1250 b factor (oil / gas) 1.2 / 1.5 Initial Decline (oil / gas) 80% / 56% Lateral Length 4,800 Type Well IRR %2 81.1% Key Statistics Average Type Curve Summary

Oswego Type Curve 1,500 Type Curve • Chesapeake, Chaparral, Cimarex, Gastar, and Longfellow are actively targeting the Oswego Other operators have future plans to develop the Oswego as a cheaper/shallower target IP rates are typically lower than Osage/Meramec wells, but decline rates are shallower With drilling and completion costs cheaper for the Oswego, well results do not have to be as strong as the headline STACK formations to make economic wells Average Type Curve Results • % • 1,250 • • 1,000 – – 233 MBOE 2-Stream EUR; 243 MBOE 3-Stream EUR 200 MBO, 0.2 BCF residue, 15 MB NGL • Type Curve assumes 16% Shrink and 75 bbl/MMcf NGL yield 750 Type Curve 140 500 120 100 80 250 60 40 20 0 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (Months) 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (Months) Note: Production data normalized for 4,800’ lateral length. 1 Offset results based on Oswego wells drilled in the Updip Oil window of Kingfisher County since 2014. 2 NYMEX Strip as of 8/3/2017. Does not include $300k PAD D&C facilities costs. Adjusted for transportation costs paid to KFM. Excludes $1.25 / bbl oil transportation costs. 53 Cumulative Gross Production (MBOE) Gross Production (BOE/D) Offset Well Results1 Average Type Curve Cumulative Production Initial Rate (BO/D / MCF/D)320 / 320 Offset Well Results1 Incline Period (oil / gas)none Peak Rate (BO/D / MCF/D)320 / 320 b factor (oil / gas)1.2 / 1.2 Initial Decline (oil / gas)72% / 72 Lateral Length4,800 Type Well IRR %2 59.3% Key Statistics Average Type Curve Summary

Substantial Inventory of Drilling Locations Operated: Osage………………………. Meramec…………………… Osw ego…………………… Manning……………………. Other Formations…………. Total Operated…… Drilling Inventory (Years) Other: Osage………………………. Meramec…………………… Osw ego…………………… Manning……………………. Other Formations…………. Total Other……….. 1,196 676 203 ---- 72% 74% 75% ---- 73% ---- ---- 168 1,327 1,141 676 206 ---- 1,141 676 206 168 1,327 73% 74% 81% 75% 70% 73% --2,337 1,352 409 168 1,327 2,075 1,495 2,023 3,518 5,593 14.4 10.4 14.0 24.4 38.8 1,252 588 281 ---- 15% 15% 13% ---- 15% ---- --316 2,084 1,113 596 310 ---- 1,113 596 310 316 2,084 15% 15% 14% 14% 55% 28% 2,365 1,184 591 316 2,084 2,121 2,400 2,019 4,419 6,540 Note: Does not include additional resource potential or undeveloped locations on ~20,000 net acres recently acquired in the Major County Acquisition. 54 Total Gross Locations 4,196 3,895 4,042 7,937 12,133 Ide ntifie d Drilling Locations Pros pe ctive Drilling Locations Ave rage Work ing Inte re s t Ave rage Othe r (Including Work ing Form ations Dow ns pacing Total Dow ns pacing Locations Inte re s t (%) Locations Locations Locations Locations ) (%) Com bine d Total Locations

Substantial Resources Osage $2,795 Osage $3,541 Osage $4,945 $6,059MM $4,805MM $8,493MM Meramec $2,412 Meramec $1,714 Meramec $1,362 PDP Oswego PDP $414 PDP Osw $641 $354 $231 167 $484 0 $6 Consensus Oswego $231 Meramec $1,714 Operated 95% NGL 21% Oil 41% DrillCo $90 Low Risk Downspacing $1,651 4,196 Gross Locations 4,196 Gross Locations Osage $3,541 $9,492MM Gas 38% Additional PDP Downspacing Dri Ot 2% $1,782 $484 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 8/3/2017 close until 2021 and held flat thereafter. For 4,196 Primary Identified locations (for all but bottom left output that includes downspacing). 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). 55 Base PV-10 by Operated at Research Identified Locations by Commodity PV-10 at Research Consensus including Downspacing2 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

Stacked Pay: Oswego, Osage/Meramec Prominent Oswego, Osage, and Meramec consistent east to west West A East A’ Big Lime Penn - Cherokee Oswego Manning A A’ Chester Unc. Chester Shale Meramec Unconformity Upr Meramec Lwr Meramec Upr Osage Lwr Osage Woodford Hunton Pre-WDFD Unc. 56

Significant Oswego, Osage/Meramec Section Consistent thickness east to west East B’ West 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 57

Significant Oswego, Osage/Meramec C Osage prominent throughout, thickening to the north North C South C’ C’ Manning Chester Shale Meramec Unc. Upr Meramec Lwr Meramec Upr Osage Lwr Osage Pre-WDFD Unc. Hunton Woodford 58

Top Cumulative Producing STACK Wells Alta Mesa wells among top producers 122 108 70 61 48 48 38 28 20 Newfield Alta Mesa Longfellow Devon/ Felix Chaparral Marathon/ PayRock Cimarex Continental Chesapeake Newfield Alta Mesa Marathon / PayRock Devon / Felix Other Source: Company data, HPDI, IHS Herolds. Note: Publicly disclosed Alta Mesa well / permits include those assigned to Oklahoma Energy Acquisitions LP and Hinkle Oil & Gas Inc. 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 Top Osage/Meramec wells (excluding Mississippian Lime) in Updip Oil and Oil window based on 60-Day Cumulative Oil Production (BBLS) per 1,000 Ft. of Lateral. 3 Operators with 2 wells or fewer, except for Longfellow (8). 59 Number of Top 100 Wells in the Oil and Updip Oil Windows by Operator, Measured by 60-Day Cumulative Oil Production2 29 18 3 21 20 12 Cumulative Osage/Meramec STACK Producing Wells Drilled by Operator (2012-2016)1

Alta Mesa Track Record of Growth Consistent increases in production, reserves and acreage 71 102,466 YE 2013 YE 2014 YE 2015 YE 2016 2013 2014 2015 2016 Q1 2017 Q2 2017 Oil NGL Gas 22.2 143.6 8.7 2012 2013 2014 2015 2016 June 2017 YE12 YE13 YE14 YE15 YE 16 (SEC) YE 16 (NYMEX) 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 YE 2016 proved reserves as of 12/31/2016 close. 3 YE12-15 proved reserves based on NYMEX pricing. 60 13.1 8.8 4.8 1.0 1.7 129.6 55.4 68.3 31.2 27.6 56.9 17.0 Alta Mesa Proved Reserves (MMBOE)2,3 Alta Mesa Total Net Production (MBOE/D)1 2727 31 23 10 73,512 40,58744,506 Alta Mesa Net STACK Acreage Alta Mesa Operated Wells Drilled by Year 205 STACK wells drilled as of 8/10/17

DrillCo JV Pivotal relationship with Bayou City Energy • Entered into joint development agreement with Houston-based private equity firm, Bayou City Energy, in January 2016 Alta Mesa Only ~$349MM STACK Acquisitions • Bayou City Energy primarily targets small operators with current production and focuses on off-balance sheet structures STACK Drilling • DrillCo funds 100% D&C cost, capped at average of $3.2MM/well Pipeline, Facilities & Other • DrillCo gains 80% working interest in wellbore until 20-well tranche earns 15% IRR, 20% working interest until 25% IRR, then 12.5% working interest • Specific wells pre-agreed for each tranche • Cash flow With BCE ~$458MM • Grow reserves STACK Acquisitions DrillCo Funded D&C • Continue resource definition • Continue pace up learning curve(s) Pipeline, Facilities & Other Drilling • Capture, hold acreage • Maintain people/crews Mesa Funded D&C 61 Strengths for Alta Mesa 2017 Alta Mesa Estimated Capital Expenditures Parameters

One Mile Laterals Optimum for Up-Dip STACK Alta Mesa and other efficient operators adopt fit-for-purpose solutions and control costs associated to high levels of natural fractures all help to reduce costs of optimized completions 62 Consideration Commentary Spacing One-mile lateral fits into a single section; two-mile laterals require establishing a “Multi-Unit spacing” Drilling Ability to use lower cost water-based muds and reduced time spent drilling helps to reduce drilling risk Completions Less proppant, fluids, and pumping time per well, more simplified design, lower friction while pumping Mineral Owner Relations Working with mineral owners across one-section (versus two-sections for longer laterals) allows for more seamless and confident development program planning ~5,000’ laterals used for multi-faceted benefits: drilling, completions, production operations, land and legal

Alta Mesa Summary STACK Pro Forma Financials Three Months Ended Years Ended December 31, ($ in millions, unless specified) March 31, 2017 December 31, 2016 2016 2015 2014 Production Oil (MBBLS) Natural Gas (MMCF) NGLs (MBBLS) 942.0 3,116.0 275.0 989.1 3,088.9 280.4 3,057.2 9,110.2 901.0 2,006.1 4,272.6 499.4 1,071.6 2,083.0 315.6 Total Production (MBOE) Daily Production (BOE/D) 1,736.3 19,292.6 1,784.3 19,394.7 5,476.6 15,004.3 3,217.6 8,815.3 1,734.4 4,751.7 Statement of Operations Revenue Operating Expenses (Cash Items) Exploration Costs (Cash Item) Operating Expenses (Non-Cash) General and Administrative1 Interest Expense1 $63.6 17.2 5.0 20.2 9.7 12.3 $61.7 16.2 7.5 23.8 8.7 1.4 $166.4 51.6 17.2 63.3 40.5 43.4 $133.6 34.7 9.8 80.3 37.9 62.5 $117.3 24.6 11.8 29.4 68.4 55.8 Other Financial Data Adjusted EBITDAX2 % Margin2 $36.7 57.7% $36.8 59.6% $74.3 44.7% $61.0 45.7% $24.3 20.7% Note: This historical pro forma financial information is unaudited and gives effect to (i) the expected disposition of Alta M esa’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 a greement 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 t his presentation. 63

Reconciliation of Adjusted EBITDAX to Net Income Three Months Ended Years Ended December 31, ($ in millions, unless specified) March 31, 2017 December 31, 2016 2016 2015 2014 Net Income (Loss) Adjustments: Interest expense Exploration expense Depreciation, depletion and amortization expense Impairment expense Accretion expense Adjusted EBITDAX1 ($0.8) $4.1 ($49.6) ($91.6) ($72.7) 12.3 5.0 18.9 1.2 0.1 1.4 7.5 23.7 0.0 0.1 43.4 17.2 62.6 0.4 0.3 62.5 9.8 61.3 18.8 0.2 55.8 11.8 29.1 0.0 0.3 $36.7 $36.8 $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 M esa’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 a greement 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. 64