Exhibit 99.1

Exhibit 99.1 September 2017 Alta Mesa Resources, Inc. Investor Presentation

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. 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.

Table of Contents I. Introduction II. Company Overview III. Our Upstream Assets IV. Our Midstream Assets V. Financial Summary VI. Valuation and Timeline Appendix Multi-Well Pad Drilling KFM Cryogenic Processing Plant 3 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.

Introduction

Transaction 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, 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 record Pro Forma Organizational Structure Alta Mesa Resources, Inc.: AMR Jim Hackett, Executive Chairman Hal Chappelle, President & CEO Finance & Upstream Kingfisher Corporate Land Accounting Operations Midstream Development Mike McCabe Mike Ellis Jim Hackett Tim Turner David Murrell Vice President and CFO Founder and COO COO Vice President Vice President 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.

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Silver Run II Delivering on Investment Criteria Upstream

Economic significantly ? below current oil price High margin core basin ? with low field break-evens, and extensive inventory ? Multiple stacked pays High-quality assets with ? significant unbooked resource potential

Opportunities to improve ? costs through technology Opportunity to expand ? through technology and acquisitions Midstream

Competitively-positioned ? assets that benefit from strong supply/demand fundamentals

Expansion opportunities in ? rapidly growing basin Locked-in base returns through ? stable fee-based contracts Assets with return asymmetry from incremental volumes, ? moderate margin exposure, and/or organic growth projects

Synergy with existing ? upstream portfolio 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 net acres with substantial infrastructure in core of STACK Oil-weighted resource with $25/BBL breakeven; >80% single-well rate of return1 4,200+2 gross primary locations; 13,000+ 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 YTD 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 a 2018 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 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.

Transaction Summary Sources & Uses ($MM) Implied Firm Value ($MM) Post-Transaction Ownership Sources Shares Outstanding 388.6 KFM Legacy Owners’ Rollover Equity $1,993 Owners Share Price $10.00 14% Silver Run II Cash Investment 9991 Legacy Riverstone Cash Investment 2 600 Equity Value $3,886 Mesa Owners Total Sources $3,591 Less: Cash(551) 37% Total Cash Sources $1,599 Riverstone 2 Plus: Debt 500 22% Firm Value $3,836 Uses Legacy Owners’ Rollover Equity $1,993 TRUE Legacy Cash to KFM Owners 813Transaction Multiples SRII

Owners Cash to Alta Mesa Balance Sheet & Interim Capex Funding 786 FV / 2018E EBITDA ($543MM) 7.1x 27% Total Uses $3,591 FV / 2019E EBITDA ($1,019MM) 3.8x Total Cash Uses $1,599 Ownership at Various Share Prices 27% 27% 26% 26% 25% 24% 22 22 22 22 21 21 15 15 14 14 14 15 37 37 37 37 39 40 $10.00 $11.50 $14.00 $16.00 $18.00 $20.00

Legacy Alta Mesa Owners KFM Owners Riverstone Legacy SRII Owners Minimal dilution to investors even when full earnout is realized Note: Sources & Uses includes estimates of transaction fees, debt at close, and other transaction closing adjustments, and is subject to change. 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 8 the applicable contribution agreements.

Transaction Multiple Summary Firm Value / 2018E EBITDA1 Firm Value / 2019E EBITDA1 7.4x 6.1x 6.1x 2 Mesa 3.1x Alta Alta Mesa Peer Median Alta Mesa Peer Median

14.1x 11.1x 2 7.3x KFM 4.2x

KFM Peer Median KFM Peer Median 7.1x 7.5x 6.3x AMR 4.1 6.2x 3.8x AMR Peer Median AMR Peer Median Debt-Adjusted Multiple3 1 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. 2 Excludes equity promote. 3 Debt-Adjusted 2019E Firm Value adjusts for forecasted cumulative outspend from 2H 2017-YE 2019. AMR adjusted Firm Value adjusts for forecasted cumulative outspend from current until close 2017 until YE 2019. 9

Company Overview

Alta Mesa Resources

Focused on development and acquisition in the STACK Upstream Metrics

Net STACK Surface Acres ~120,000

Current Production (BOE/D) ~20,000

% Liquids 69% Resource Potential (MMBOE)1 >1,000 Breakeven Oil Price, $/BBL WTI <$30 Single-well IRR >80%

Estimated Potential Gross Identified

4,196 Locations1 Operated STACK Hz. Wells Producing / 167 / 205 Operated STACK Hz. Wells Drilled3

2017 YTD Average Rigs 6 Contiguous Core Position in STACK Oil Window 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 90 MMCF/D offtake processing contracted 3Q 2017. 11 5 Lease Automatic Custody Transfer units.

Optimization, Delineation and Expansion Systematic horizontal development and growth of contiguous acreage 1992—2013 Major Garfield blaine kingfisher candian 1992-2013 wells alts mesa acreage 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 Major Garfield blaine kingfisher candian 2014 and 2015 welss alts mesa acreage 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 2016 & 2017 Plan Major Garfield blaine kingfisher candian Exisiting kfm plant compressor station 2017 development plan wells kingfisher midstream system auto mesa acreage 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

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High Caliber STACK Operating Team Cohesive, tenured, scalable team producing world class results Name Position Years at AMR Years Experience 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 Development 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+

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)

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Progressive Execution Track record of growth in production, reserves, leasehold Net STACK Acreage ~ 120,000 102,466 73,512 44,506 40,587 YE 2013 YE 2014 YE 2015 YE 2016 Current Total Net Production (MBOE/D)1 22.2 13.1 8.8 4.8 1.0 1.7 2012 2013 2014 2015 2016 June 2017 100% cagr NYMEX Proved Reserves (MMBOE)2 143.6 68.3

27.6 17.0 8.7

YE12 YE13 YE14 YE15 YE 16 Alta Mesa Footprint Recent addition Core STACK acreage Acreage has grown from ~40,000 net acres to ~120,000 net acres since 2013 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 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. 14

Strong Economic Fundamentals High quality rock and robust rig activity drive compelling returns Alta Mesa—Updip Oil

2 $24.40 STACK Major Core Midland— $27.16 Wolfcamp A&B U. S. S. Delaware Basin—Oil $27.53 Reeves Wolfcamp A Plays STACK Meramec— $27.71 Over-Pressured Oil DJ Basin—Wattenberg $32.14 Core XRL Breakeven N. Delaware Basin - $33.36 Wolfcamp XY Prices ( $ SCOOP Woodford $34.66 Condensate /BBL)

1 Eagle Ford—Karnes $34.76 Trough

40. $ 00/bbl / $ 44% 57% 2. 50/MCF Gen 2.Alta 0 $ (59 50. Mesa 00/bbl wells) / $ 73% 92% 3. Type Gen 2. 00/MCF Well 5 (95 IRR

wells)3 Broker 82% 103% Consensus

4 KFM Acreage Dedications / Resource Allocations Breakdown5 KFM Gas Inlet Volumes by Producer (MMCF/D) (‘000 of gross acres) % Alta 69% 52% 55% Mesa(6)

175 541 366 639 393 193 86 118 239 50 22 128 Existing + expansion cagr; 235% Existing Infrastructure cagr: 194% cagr:119% Existing Infrastructure Expansion Existing + Expansion Additional Acreage 2017E 2018E 2019E Under Negotiation Alta Mesa Other 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. 15 6Percentage of Existing Infrastructure shown.

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 Market including 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 in projects 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 Limited G&P infrastructure provides opportunity for KFM expansion Development Project

KFM involved in negotiations with anchor customers Future opportunity to monetize KFM and fund upstream capital needs Midstream Business Can Support through 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

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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 Structure Illustrative 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 Median Midstream Median GP Median Value of Margin MLP Multiple MLP Value Multiple Potential in Upstream Expansion Expansion Midstream Value (MLP + GP) Valuation Arbitrage Likely valuation uplift (multiple arbitrage vs. traditional peer group) 30.0x 27.3x 25.6x GP Median: 26.5x TDA 25.0x I EB 20.0x E 14.6x 15.3x 13.7x Midstream Median: 14.1x 1 8 15.0x 2 0 11.0x / 7.8x Upstream Median: 7.5x 10.0x 7.8x 7.2x FV 5.8x 5.0x 0.0x AMGP EQGP EQM AM HESM NBLX DVN XEC CLR NFX Upstream 4.9x 5.6x 8.1x 6.8x Multiple Midstream GP Upstream 1 Illustrative KFM future value expansion assuming KFM 2019E EBITDA of $318mm. 17

Alta Mesa’s Conservative Approach Assumption Commentary 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 Upstream 6 rigs in 2017 YTD average of 6 rigs Production / Rig 10 rigs in 2018 Organization readily scalable for 10-rig program Ramp 11 rigs in 2019 Third frac spread and fourth frac spread added in Q3 2017 LOE per BOE comparable to peers despite oiler production mix Upstream and much currently lower total production $3.70 / BBL Operating Expense Fixed costs associated with substantial infrastructure and multi-well pads create leverage to further reduce LOE Currently contracted to 5 third party customers, forecast is for Rig Count 14.8 rigs in 2017 an increase of only 3 additional third party rigs over 2017 exit Supporting Current 22.3 rigs in 2018 levels Midstream System 23.5 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 18.5 rigs in 2017 Supporting counties with a severely underserved G&P market 31.3 rigs in 2018 Expanded PE companies will be looking for growth / exits and will need 32.5 rigs in 2019 Midstream System takeaway that only KFM can provide

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Our Strategic Vision: Premier STACK Operator Disciplined Execution Alta Mesa Position in Expanding STACK/MERGE/SCOOP Area 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 woods alfaila grant woodward expanding stack major Garfield dewey blaine stack core custer cana woodford Washita caddo kiowa caddo merge grady

Note: Wells drilled map as of August 2017. 19

Our Upstream Assets

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 Major Garfield blaine kingfisher candian Nemaha ridge uplift alta mesa acreage updip oil— api gravity=40-42, gor=~ 500-750 scf/bbl Oil-api gravity=42-45,gor, 750-1,500 scf/bbl volatile oil-api gravity=45-50,gor 1,500-5000 scf/bbl wet gas-api gravity=50-60, gor=5,000-15000 scf/bbl dry gas-api gravity 60+,gor=>15,000 scf/bbl Source: IHS Enerdeq, HPDI. Note: Represents a combination of current and recent rig activity. 1 Operators with 2 rigs or fewer running. 21

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 Garfield near-vertical fractures intensifies near Nemaha Fault System Major Osage/Meramec co-produce in ~500 ft thick section ST??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 OKLAHOMA Woodford Shale 50-150 ft Simplified Stratigraphy of Major STACK Targets in Kingfisher County SW Penn Mississippian Pre- Pennsylvanian Unconformity Chester Shale Hunton Sylvan Shale Osage/Meramec True Dip 1 degree SW Updip Oil Window Oswego Meramec Osage Woodford Shale STACK PLAY TESTED HORIZONTAL TARGETS Cross Section Location Map

Solid Results Affirm De-Risked Acreage Position Representative wells across 11 townships Notable 2017 Alta Mesa Wells Lateral EUR EUR/‘000 IP90 IP90 IP90/‘000 Well Target IP30 (BOE/D) Well Name1 Length (MBOE)2 Lateral ft2 (BOE/D) % Oil Lateral ft Aces High 1606 4-11MH Osage 823 Operated Coleman 1706 6A-9MH U Osage/L Meramec 514 1 Barbara 1706 3-22MH 4,812 579 120 346 82% 72 Dalwhinnie 1605 1-31MH Osage 702 Beyer 4-6H 4,452 863 194 505 75% 113 Fazio 1705 1-13MH Osage 909 2 Hasley 1605 1-28MH Osage 549 3 Boecher 1706 4-19MH 4,832 574 119 560 72% 116 Huntsman 1506 2-23MH Meramec 598 4 Bollenbach 1705 4-21MH 4,820 994 206 185 55% 38 Macallan 1806 4-17MH Osage 643 Bollenbach 1705 6-30MH 4,795 1,198 250 436 92% 91 Odie 1606 1-12MH U Osage/L Meramec 849 5 Peat 1606 1-26MH Osage 522 6 Brown 1706 6-27MH 4,850 839 173 316 76% 65 Pollard 1805 3-2MH Osage 507 7 Clark 1705 5-12MH 4,657 827 178 615 85% 132 Red Queen 1506 1-1MH Osage 509 Cleveland 1805 2-26MH 4,645 686 148 451 77% 97 Shiner 1505 1-3MH Osage 585 8 Speyside 1606 1-27MH Osage 997 9 Dixon 1505 3-16MH 4,858 657 135 325 81% 67 Yellowstone 1505 4-8MH Osage 740 10 EHU 219H 4,950 790 160 123 88% 25 11 EHU 220H 3,651 678 186 216 91% 59 12 EHU 235H 5,300 559 106 357 89% 67 13 Evelyn 1706 5-18MH 4,857 575 118 621 87% 128 14 Francis 1706 5-8MH 4,856 664 137 349 69% 72 15 Gilbert 1706 6-21MH 4,738 590 125 409 59% 86 16 Hawk 1906 7-13MH 4,813 540 112 216 80% 45 17 Helen 1605 5-33MH 4,620 652 141 331 77% 72 18 Hoskins 1705 2-9MH 4,693 932 199 507 85% 108 19 James 1706 5-26MH 4,748 738 155 352 79% 74 20 Lankard 1706 6-34MH 4,855 847 174 1,291 58% 266 21 LNU 16-2H 4,788 873 182 282 89% 59 22 LNU 49-4H 4,518 756 167 518 79% 115 23 Mad Hatter 1506 2-34MH 4,670 632 135 294 90% 63 24 Martin 1505 4-9MH 4,795 620 129 278 64% 58 25 Matheson 1705 5-10MH 4,765 729 153 448 79% 94 26 Mitchell 1806 2B-27MH 4,598 646 140 311 81% 68 27 Oak Tree 1605 2-30MH 4,744 813 171 634 69% 134 28 Oltmanns 1805 6-14MH 4,930 822 167 631 70% 128 29 Oswald 1705 6-28MH 4,815 1,144 238 278 66% 58 30 Pinehurst 1706 5-5MH 5,061 672 133 572 75% 113 31 Redbreast 1505 4-7MH 4,709 655 139 251 73% 53 32 Rigdon 17015 6-11MH 4,827 725 150 697 82% 144 33 Rudd 1605 2A-5MH 4,010 520 130 489 58% 122 34 Three Wood 1505 4-17MH 4,634 629 136 321 76% 69 35 Todd 1706 6-4MH 5,019 946 188 599 68% 119 36 Vadder 1805 2-12RMH 4,504 669 148 542 63% 120 37 Wakeman 1706 6-25MH 4,842 925 191 787 62% 162 38 Weber 1806 3-22MH 4,797 646 135 112 75% 23 39 White Rabbit 1506 2-27MH 4,811 633 132 428 91% 89 Non-Operated 40 Deep River 30-1MH 5,586 NA 89 324 41% 58 41 Holiday Road 2-1H 5,100 NA 67 153 85% 30 42 King Koopa 1606 2UMH-22 4,691 NA 83 380 60% 81 43 OOID 1OH-24 5,357 1,459 272 533 88% 99 44 Post 1706 1-30MH 4,919 456 93 461 66% 90 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 45 Ruzek 1H-3X 6,872 498 72 688 67% 100 46 Trifecta 1807 20H-14-1 4,346 662 152 555 92% 128 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. 23 2 3-Stream EUR assuming 75.4 BBL/MMCF NGL yield and 15.9% shrink. Notable Horizontal Wells Horizontal Wells Notable 2017 Wells Updip Oil Oil Volatile Oil Wet Gas Filed wide Units Alta Mesa Acreage Osage Structure Nemaha Ridge Uplift Notable Horizontal Wells Horizontal Wells Notable 2017 Wells Updip Oil Oil Volatile Oil Wet Gas Filed wide Units Alta Mesa Acreage Osage Structure Nemaha Ridge Uplift

Top Cumulative Oil Producing STACK Wells Alta Mesa wells among top producers 1 Selected Permian Operator Producing Osage/Meramec/Oswego STACK Public Operator Producing Wells (2012-2Q 2017) Wells (2012-2Q 2017)2 255 176 194 159 158 58 56 43 34 29 3 Diamondback Parsley RSP Permian Newfield Alta Mesa Devon/Felix Marathon/Payrock Continental Cimarex Chesapeake Number of Top 100 Wells in the Oil and Updip Oil Windows by Operator, Measured by 60-Day Cumulative Oil Production4 24 22 20 20 14 Alta Mesa Marathon/ Newfield Devon/ Other Payrock Felix Woods Major Dewey Garfield Kingfisher Blaine Logan Canadian Mississippian Wells Nemaha Ridge Alta Mesa Updip Oil Oil Miles 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. 24 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.

Progressive Increase in Completion Intensity Alta Mesa leadership in operational advancements Completion Summary By Generation Type Curve Gen 2.0 Alta Mesa has proactively advanced completion designs with each 100 generation leading to improved well response and economics: 90

Number of stages increases with each generation as stage (MBO) 80 spacing decreases 70 60

Average sand per stage has increased with each generation Production 50

Total fluid per stage increases with each generation 40 30 Continuously optimizing completions designs through reduced frac stage spacing for increased formation stimulation Cumulative 20 Flowback Rate-Controlled

10 In Early Periods 0 0 6 12 18 Production Month Design Parameters Gen 1.0 Gen 1.5 Gen 2.0 Gen 2.5 Current Future EUR by Generation2 Avg Frac Stages 12 18 24 32 35 MBO MBOE Avg. Stage Spacing (Ft.) 340 256 194 150 140 Slickwater—Avg Total (BBLS/Ft.) 29 42 56 66 75 651 714 Sand—Total Avg. (Lbs/Ft.) 317 457 677 1,193 1,500

Improvement 472 Frac Design Type Packer/Sleeve Hybrid Plug/Perf Plug/Perf Plug/Perf Further Flow Design Type Slickwater Slickwater Slickwater Slickwater Slickwater 149 183 250 303 71 Packers Type Mechanical Hybrid Swell Swell Swell Average Average Generation 2.0 Generation 2.5 Beyond 1 Generation 1.0 Generation 1.5 Type Curve Type Curve Generation 2.5 Well Count 7 6 59 95 — 1 Wells completed as of 8/16/17 2 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 25 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.

High Early-Period Oil Cut Drives Value Consistent Meramec/Osage GOR behavior Oil-Weighting Over Time Approximately 73% of the oil, 58% of the natural gas liquids, and 58% of the natural gas are produced in the first five years thereby enhancing the early revenue per unit and the resulting economics The GOR increases over time from approximately 1 MCF/BBL to approximately 5 MCF/BBL at one year to approximately 10 MCF/BBL at 5 years. This same behavior is exhibited by historical vertical wells In month one, 2-stream production from the well is 82% oil and 3-stream production is 85% liquids In year one, 2-stream production from the well is 66% oil and 3-stream production is 70% liquids 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 Projected Oil and Liquids Content1 Average GOR Behavior1 CUM OIL % Oil % Liquids CUM MMCF GOR Source: Ryder Scott-audited Reserve Report, Company data. 1 LNU17N06W02A Miss well (Ryder Scott-audited Reserve Report). 26

Low Cost Operator Peer leader in operating cost and capital efficiency Recycle Ratio1 Illustrative KFM 4.0x Margin Uplift 3.4x 3.2x 3.1x 1.8x 1.7x 3.7x 1.1x 0.8x CLR AMR FANG PE RSPP XEC NFX MRO DVN SEC Future Development Cost Per Proved Undeveloped BOE ($ / BOE)2 Q1 2017 LTM LOE ($ / BOE)4 $24.21 $6.39 $4.98 $5.10 $4.81 $13.78 $3.66 $3.70 $3.87 $3.58 $9.37 $10.02 $8.53 $8.77 $8.89 $2.99

$7.96 $6.33 3 3 5 AMR XEC CLR PE FANG RSPP FX MRO DVN XEC NFX CLR AMR PE MRO RSPP FANG DVN Alta Mesa STACK Peers Permian Peers Source: Public Filings as of 4Q 2016. 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 3/31/2017 excluding legacy vertical and waterflood-related production. 27

Cost-Advantaged Asset Base Infrastructure and basic well design mitigate cost inflation Advantage Why It Matters Gross D&C1 ($MM) 1 Lat. Length: 4.8k 4.8k 4.8k 5.0k 4.8k 5.0k 9.6k 9.8k 9.6k 10.0k Allows for the elimination of additional strings of casing, liner $ 12.0 Shallower tie-back, and reduces horsepower used during stimulation Targets Reduced drilling time and costs per well enhances capital $ 10.0 flexibility and efficiencies $ 8.0 2 $ 6.0 Reduces mechanical risk of completions vs two-mile $ 4.0 One-mile Use less steel by utilizing smaller diameter pipe program $ 2.0 Laterals Lower cost per foot to execute drilling and completions $ 0.0 G O NP C SXL C E - - SL 3 Naturally 2.0) 2.5) MRM MRMC MRMC MRM MRMC SW C - - - - Heavier proppant loads not required AMR AMR O Fractured - RM RO MRMC RO EC Flexibility to use more commoditized proppant (Gen (Gen M - CLR M UPPR M X Formation - - MRMC/OSAGE MRMC/OSAGE CHK N FX DV DVN N Total D&C Cost ($MM) Actual D&C Target Pattern Test D&C $5.1 $4.7 $4.2 $3.4 $3.4 $3.5 $3.2 2012 2013 2014 2015 2016 Current AFE Target Pad Drilling Avg. Days Spud to TD 46 34 25 17 13 13 13 DV DVN N D&C Cost / Lateral Foot Actual D&C Target Pattern Test D&C $1,359 $1,074 $940 $720 $713 $729 $667 2012 2013 2014 2015 2016 Current AFE Target Pad Drilling 1 AMR Pad Drilling D&C only and does not include $300k of allocated facilities cost. 28

STACK Development

Moving into development mode on de-risked Kingfisher acreage Base Case Development Concept 2017 Development Plan Oswego/ Big Lime ft 150 1,500’ 1,500’ ft 1,500’ 450 Meramec 750’ 750’ Osage 750’ 750’ 750’ ft 750’ 550 1,500’ 1,500’ 750’ 1,500’ 750’ 750’ 750’ 750’ 750’ Alta Mesa Development Strategy 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 2017 Development Plan Wells Transition to primarily pattern development in 2017 Alta Mesa Acreage Average of 6 rigs running YTD 2017 29 Major Garfield blaine kingfisher candian

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 Publicly Disclosed Inventory per DSU Assumptions Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Base Case 24 20 16 14 12 4 Formation Oswego Meramec Osage Woodford N/A N/A N/A N/A 4 2 8 12 12 12 N/A 4 - - - - N/A 8 16 8 4 - N/A - Total Wells per DSU 24 20 16 12 4 14 Source: OK Corporation Commission, public disclosures from investor presentations and industry conferences. Peers are represented by Chesapeake, Cimarex, Continental, Devon and Newfield. 30

STACK: A Significant Petroleum System Additional development potential in multiple stacked pay zones Alta Mesa Existing Development 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 Additional Zones 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 Potential 55 Wells per Section Type Log Down- Additional Formation Targeted Total spacing Formations Big Lime 4 4 Oswego 2 2 4 Cherokee Shale Prue Sand 4 4 Skinner Sand

Red Fork Sand Manning Lime 4 4 Chester Shale 4 4 Meramec 4 4 8 4 3 7 Osage 4 4 8 Woodford Shale 8 8 Hunton Lime 4 4 Total 14 13 28 55 Note: Actual Alta Mesa log above displays productive formations.

31

Deep Drilling Inventory >4,000 Identified Gross Locations represent 14+ years of inventory Alta Mesa’s >4,000 Identified Gross Drilling Locations are the primary focus of the near-term development plan 484 1,264 4,196 2,448 Osage Meramec Oswego Current (8 WPS) (4 WPS) (2 WPS) Identified Targeted Locations 753 8,238 2,214 436 872 484 174 488 954 13,659 1,288 516 318 966 8,238 Kingfisher Kingfisher Current Additional Major/Blaine Major/Blaine Other Additional Total Potential Downspacing Downspacing to Identified and Formations—Osage/Meramec Osage/Meramec Formations Locations to 20 WPS1 27 WPS2 Downspacing Current Testing Primary Downspacing Locations Locations Locations Osage Meramec Oswego Big Lime Manning Hunton Woodford Other3 Note: Identified locations based on AMR interest in 320 Meramec/Osage and 257 Oswego sections. 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.

32

Asset Value of AMR’s STACK Position

~$6B PV-10 Value from Identified Gross Locations before downspacing

Alta Mesa’s >4,000 Identified Gross Drilling Locations are the primary focus of the near-term development plan $1,564 $5,752 ($307) $199 $54 $1,260 $2,566 $417 PDP Osage Meramec Oswego DrillCo KFM Margin Net Debt and Base Case Uplift Other 5 Net Asset Adjustments Value Implied PV-10 Upside Area of Focus Value ($MM) Manning 1 $484 Kingfisher Dow nspacing to 20 WPS 2 1,233 3 Kingfisher Dow nspacing to 27 WPS 1,294 Major/Blaine Osage/Meramec Primary Locations 1 597 Major/Blaine Osage/Meramec Dow nspacing 1 251 Upside KFM Margin Uplift 4 1,398 Big Lime Unspecified Hunton Unspecified Woodford Unspecified Cherokee Unspecified Chester Unspecified Total Upside Potential $5,258

Total Asset Value $11,010 Implied P/NAV 35% 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 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 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.

5 Adjusts 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.

33

Near Term Consolidation Opportunity

Play is expanding and significant acreage could change hands Lipscomb woodward woods alfalfa Garfield ellis deway blaine hemphill roger mills custer Canadian Oklahoma Canadian Washita caddo grady Cleveland mcclain Namaha ridge uplift alta mesa acreage Actionable acreage Actionable acreage Private equity backed/private company (~2.1 MM gross acres) public company (~0.5 MM gross acres) Public company/ private equity backed/private company overlap Alta mesa overlap

34

Our Midstream Assets

Kingfisher Midstream Overview Acreage Dedications Cushing ~60 mi. KFM Overview · Current natural gas processing of 60 MMCF/D – Year-end processing capacity of 350 MMCF/D includes 90 MMCF/D offtake processing expected 3Q 2017 · 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 · Over 7,000 gross locations associated with customers KFM EBITDA Estimates ($MM) $318 $184 $63 $44 $42 $255 $4 $141 $38 2017E 2018E 2019E Existing Infrastructure Expansion Alta Mesa & Third Party Throughput (MMCF/D) 639 393 207 146 118 193 86 13 50 22 128 239 2017E 2018E 2019E Alta Mesa Third Party (Existing) Third Party (Expansion) Alta Mesa & Third Party Rig Count 31.3 32.5 18.5 9.0 9.0 3.7 12.3 12.5 8.8 6.0 10.0 11.0 2017E 2018E 2019E Alta Mesa Third Party (Existing) Third Party (Expansion) 36 Note: Represents multiple lines in ditch.

Complete Midstream Operation Processing, Pipelines, Compression, Other Infrastructure Cushing ~60 mi. Natural Gas • Current processing capacity of 60 MMCF/D 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 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 • 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 Connections 188 units Note: Represents multiple lines in ditch. 1 Includes 16 miles under construction 2 Includes 20 miles under construction 37

Market Access Optionality Pipeline Description Current Takeaway Capacity Expansion Projects Commentary Natural Connected to PEPL owned and 100,000/day FT on PEPL for KFM in discussion Gas takeaway is functionally full creating a Gas operated by Energy Transfer 20 years with proximate constrained environment for some PEPL consists of four large 50,000/day FT on OGT, outlet pipelines producers. KFM’s residue position diameter pipelines extending expanding to 125,000/day looking to expand provides flow assurance and better approximately 1,300 miles June 2018 out of the basin netbacks for KFM producer clients throughout Mid-Continent and ? 25,000 Dth/d for 4 years Residue gas is split connect between other market centers PEPL and OGT, and under long term KFM will connect to OGT Q3 2017 ? 100,000 Dth/d for 10 agreements insuring that KFM producer years customers 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 in rates that will be needed to solidify new Q2 2018 capacity 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 66 contract extendable for 2 1- into other NGL pipeline that takes Y-grade to Conway, KS

Delivers NGLs to Conway year terms with shipper pipelines in the area for fractionation history Volumes could Multiple NGL lines within 7 miles of plant warrant expansion to 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 site opportunities to Alta Mesa barrels and future third party Six truck bays for LACT loading Cushing and other barrels clean to market, producing better and unloading demand sources in netbacks the area Multiple pipeline Proximity to Cushing provides market connection options optionality 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 38

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 Note: Above represents committed acreage to KFM as well as gross acres surrounding existing agreements. 39

System Expansion Underway 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 Active Rigs Future Planned Expansion Existing KFM Plant Compressor Station KFM System Alta Mesa Acreage Existing Southern Infra. Existing Northern Infra. 40

Financial Summary

Financial Strategy & Pro Forma Financial Impacts Demonstrated trajectory to positive free cash flow with near-term development funded with transaction proceeds Significant Secure robust liquidity to fund development, with near-term production growth ensured by Financial 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 Maintain leverage 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 Flow changes in commodities and/or service costs Continued rolling hedge strategy to protect revenues and support development program Capitalization at Announcement Current ($ in millions, unless specified) Alta Mesa KFM Adjustments Pro Forma Cash and Cash Equivalents $5 $28 $5171 $551 Revolving Credit Facility 269 2 $0 (269) 2 0 7.875% Senior Notes due 2024 500 5003 Total Debt $769 $0 ($269) $500 Net Debt 763 (51) Financial and Operating Statistics 2017E EBITDA $155 $42 $197 2018E EBITDA 358 184 543 2019E EBITDA 701 318 1,019 Credit Metrics Net Debt / 2017E EBITDA NM 2018E EBITDA NM 2019E EBITDA NM Liquidity Expected Borrow ing Base $315 $200 $515 Less: Amount Draw n 269 (269) 0 Expected Borrow ing Base Availability $46 $515 Plus: Cash and Cash Equivalents 5 551 Liquidity $52 $1,066 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. 42

432017 Capital Budget and Hedge Position Commentary Alta Mesa 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 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 9/11/17 10,941 8,000 3,900 Sept-Dec’17 2018 2019 Sept-Dec’17 2018 2019 Average Floor Price $49.69 $51.42 $50.00 ($/BBL) 2017E Budget by Quarter ($MM) Ex. Acquisitions1 18% Upstream Midstream $154 26% 56% Acquisition (Including Leasehold) $70 $102 $20 $73 $60 $18 $17 $82 $84 $55 $44 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Alta Mesa KFM Gas Hedges (MCF/D) as of 9/11/17 30,527 16,233 Oct-Dec’17 2018 Oct-Dec’17 2018 Average Floor Price $3.20 $4.43 ($/BBL) 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. 43

Summary Financial Projections ($ in millions unless otherwise noted) 1 Average Net Daily Production (BOE/D) EBITDA(X) Capital Expenditures (excl. DrillCo Funds) $925 68,900 $1,019 $171 $785 $63 2,003 $35 $255 $139 $202 38,510 $543 $474 1,698 $44 $41 66,897 $84 20,841 $141 $701 $611 $552 549 36,812 $197 $4 $358 $349 20,292 $155 $38 2017 2018 2019 2017 2018 2019 2017 2018 2019 Alta Mesa Drill Co Alta Mesa KFM (Existing) KFM (Expansion) Alta Mesa KFM (Existing) KFM (Expansion) Free Cash Flow Liquidity2 Forecast Total Wells by Year $948 $195 $871 239 $144 207 $51 $676 ($237) ($233) 120 ($83) ($189) ($320) ($422) 2017 2018 2019 2017 2018 2019 2017 2018 2019 Avg. 3 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 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. 44 3 Average 2017 YTD rigs. 44

KFM Financial Overview Detailed Capital Expenditures by Phase Existing Infrastructure ($MM) 2017E 2018E 2019E Processing $30 $130 $79 Pipeline & Well Connects 53 52 27 Compression Principal Payments 0 14 25 Compression Lease Interest Expense 0 5 9 Total $84 $202 $139 Expansion ($MM) 2017E 2018E 2019E Processing $5 $81 $0 Pipeline & Well Connects 36 75 17 Compression Principal Payments 0 10 13 Compression Lease Interest Expense 0 4 4 Total $41 $171 $35 45 45

Valuation and Timeline

Upstream Valuation Benchmarking ($ in millions unless otherwise noted) Firm Value / 2018E EBITDA Firm Value / 2019E EBITDA 8.0x 7.8x 7.8x 7.5x 7.3x 7.2x 6.8x 6.3x 6.3x 6.2x 6.2x 6.1x 5.8x 6.0x 5.1x 4.6x 4.4x 3.1x MTDR DVN XEC LPI RSPP CLR CPE AMR NFX DVN XEC LPI CLR MTDR RSPP NFX CPE AMR Adjusted Firm Value1 / Net Acres 2017E 2019E Production CAGR $30,011 82% $22,063 $14,180 43% 33% 20% 19% 18% 18% 17% 16% 6% 2 2 3 GPOR / Vitruvian DVN / Felix AMR AMR CPE RSPP MTDR AR CNX EQT CLR NFX 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. 47

Benchmarking KFM Against High Growth G&P Peers ($ in millions unless otherwise noted) Firm Value / 2018E EBITDA Firm Value / 2019E EBITDA 15.3x 14.6x 13.7x 11.7x 11.3x 11.0x 11.0x 8.0x 7.3x 4.2x 1 1 HESM EQM AM NBLX KFM EQM AM HESM NBLX KFM Midstream 2017E 2019E EBITDA CAGR Consolidated 2017E 2019E EBITDA CAGR 128% 175% 47% 40% 28% 33% 27% 26% 20% 19% KFM NBLX AM HESM EQM AMR+KFM EQT AR HES NBL Integrated Upstream/Midstream Peers 1 Includes midstream Firm Value only. 48

Anticipated Transaction Timeline Date Event Mid-September 2017 File preliminary proxy statement / marketing materials with the SEC October 2017 Transaction marketing Mid/Late-November 2017 Anticipated close 49

Key Combination Highlights Pure Play STACK Enterprise Truly integrated upstream / midstream assets of material scale Highly-contiguous position in core of one of the most active US oil basins Delineated acreage with 167 horizontal operated wells since 2012 Extensive inventory of highly economic drilling locations; <$30/Bbl breakeven WTI Midstream supported by material 3rd party volumes, visible near-term contracted growth Peer-leading capital efficient growth over the next several years with current asset base Zero net-debt at close, fully-financed business plan, direct path to positive FCF by 2019 Natural consolidation opportunities for accretive growth in existing STACK asset base Opportunity to monetize KFM in 2018/2019 MLP IPO Existing owners of Alta Mesa (100%) and KFM are retaining significant equity stake Riverstone and related investment vehicles will invest at least $600 million cash 50

Appendix

Alta Mesa Management Jim Hackett Hal Chappelle Michael McCabe Executive Chairman and COO of Midstream President and Chief Executive Officer Vice 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 in President and CEO in 2004 and became 2006 and became a director in 2014 2017 a director in 2004 Raised private equity capital for Alta Prior roles include: Developed Alta Mesa into a premier Mesa from Denham Capital in 2006, HPS STACK operator, building a strong Investment Partners in 2013, and Bayou o Chairman and CEO of Anadarko management and technical team City in 2015; successfully navigated Alta Mesa through two industry cycles o President and COO of Devon Energy Successfully navigated Alta Mesa o Chairman, President and CEO of through significant industry cycles, Has over 25 years of corporate finance Ocean Energy building the Company’s oil assets in experience with a focus on the energy 2009-2010 and divesting of the industry o President of several midstream company’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 in includes serving as President and sole Gas Resources field operations, engineering, owner of Bridge Management Group, management, trading, acquisitions and Inc., 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 Energy Exploration, Burlington Resources, Tokyo, Bank of New England and Key Southern Company and Mirant Bank 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 and from Bridgewater State University, an Holds a B.S. from the University of an M.S. in Petroleum Engineering from M.S. in Chemical Engineering from Illinois and a MBA/MTS from Harvard the University of Texas Purdue University, and an MBA from University Pace University 52

Alta Mesa Management Michael Ellis Gene Cole David Murrell Founder and COO of Upstream Operations VP and Chief Technical Officer VP, 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 Amoco President and Chief Technical Officer since 2015 Business 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 and exploration and development programs, contract experience in management, engineering, international oilfield experience in management, well management and acquisitions and divestitures exploration, and acquisitions and divestitures completions, 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 a Alta Mesa and built a team of lease analysts, earn-in exploitation projects, then growing with field engineer and served in numerous increasingly landmen, and field representatives to facilitate Alta successive acquisitions of fields from major oil responsible positions from 1986 to 2007 Mesa’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 Virginia College the University of Oklahoma University Kevin Bourque Tim Turner David McClure VP, Operations VP, Corporate Development VP, 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-Continent Corporate Development in 2013 Facilities 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 program various operations, reservoir engineering and Louisiana Operations, leading a multi-disciplined He joined Alta Mesa as a field engineer in 2007 managerial roles with Sun Oil, Santa Fe Minerals, team of engineers, regulatory, land, geoscience, and Led the growth of our mid-continent drilling and Fina Oil & Chemical, Total, Newfield Exploration, operations personnel in development of the Weeks production operations as we expanded our and Quantum Resources Island 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 Alta Company 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 teams operations, facilities and subsea engineering, management experience as the owner of his own Holds a B.S. in Petroleum Engineering from the pipelines, and management company University of Texas and an MBA in Finance from Oklahoma City University Holds a B.S. in Chemical Engineering from Auburn University 53

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) Created new mission for Anadarko in 2003, upgraded corporate leadership 300% capabilities, rationalized and refocused the portfolio, improved technical and 250% 240% financial risk management tools and 200% processes, and generated success 150% through expansion into unconventional 100% onshore and conventional offshore 50% 74% assets 0% Applied leading-edge technology and processes in drilling, completions, and (50%) Strategic production Dec-03 Feb-05 Apr-06 Jun-07 Aug-08 Oct-09 Dec-10 Feb-12 Thought Leader Dynamic leader for years serving as Anadarko S&P 500 Index President and COO of Devon Energy, Ocean (Devon)1 Public Market Outperformer (1999 2003) Chairman, President and/or CEO of Ocean Energy, president of several 250% midstream companies, responsible for Duke Energy and PanEnergy’s 200% 210% midstream and upstream businesses, 150% and drove Anadarko’s midstream business consolidation and MLP/GP 100% IPO Western Gas Partners and 50% Western Gas Resources 0% (17%) Benchmark for Premier operator with some of the best (50%) Mar-99 May-00 Aug-01 Oct-02 Dec-03 Operational production metrics in U.S. onshore, Ocean (Devon)1 S&P 500 Index Excellence and U.S. Gulf of Mexico, and offshore East Execution 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. 54 1 Chart displays Ocean share price performance until merger with Devon completed. Thereafter, chart shows Devon performance on a per-Ocean share basis.

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 Newfield—Stark Pilot, 10-well Spacing Test Upper/Lower Meramec Newfield—Raptor-X Pilot, 6-well Spacing Test 880’ Upper/Lower Meramec Continental—Ludwig Pilot, 8-well Spacing Test (74%oil) 1,320’ Upper/Lower Meramec Continental—Blurton STACK Pilot, 8-well Meramec/4-well Woodford Test 1,320’ Upper/Lower Meramec Continental—Bernhardt STACK Pilot, 8- well Meramec/4-well Woodford Test 1320’ Upper/Lower Meramec Continental—Verona STACK Pilot, 8-well Meramec/4-well Woodford Test 1,320’ Upper/Lower Meramec Newfield—Dorothy Pilot, 5-well Spacing Test 1,050’ Upper/Lower Meramec Continental—Gillilian STACK Pilot, 8-well Meramec/4-well Woodford Test 1,320’ Upper/Lower Meramec Devon—Born Free, 13-well Spacing Test 400’ Upper/Lower Meramec Cimarex—Gundy, Future 10-well Spacing in Meramec/9-well Spacing in Woodford 550’ Upper/Lower Meramec Alta Mesa ¯ Optimization of Well Spacing Miles 0 1.75 3.5 7 Nemaha ridge uplift well tests alta mesa alta mesa & NFX alta mesa & MRO chaparral imarex continental devon energy gastar Longfellow Alta Mesa—4-well Spacing Test EHU 237, 239, 240, 241 S9-19N 6W Lower/Middle Osage, 1,500’ 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 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 Newfield—Chlober, 5-well Spacing Test 1,050’ Upper/Lower Meramec Marathon—Yost, 6-well infill Spacing Test Meramec Devon—Pump House, 7-well Spacing Test 2,200 lbs/ft proppant, 4,700’ laterals Upper Meramec Alta Mesa 4 Well Spacing Test Huntsman Pattern S23-15N 6W 1,200 ft. spacing Osage and Meramec Devon—Alma, 5-well Spacing Test IP60 1,300boed, Upper/Lower Meramec Source: 1Derrick, IHS, Drilling Info and Company Presentations. 55

Completion Design Focus on increasing stimulated reservoir volume STACK Well Completion Strategy Total D&C Cost ($MM) D&C Cost / Lateral Foot Progressed through testing multiple generations Actual D&C Target Pattern Test D&C $1,359 Actual D&C Target 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) between packers defines 150ft stages 10,000 bbls of slick water per stage 2012 2013 2014 2015 2016 Target Pad 2012 2013 2014 2015 2016 Target Pad 100 bbl/min total fluid injection rate Drilling Drilling Cap flowback rate at 100 bbl/hr of total fluid Avg. Days Spud to TD 46 34 25 17 13 13 Averages by Completion Generation Stage Spacing Proppant Fluid 35 400 1,400 8,000 3,000 10,752 10,864 11,000 32 1,275 2,630 340 350 1,200 7,000 9,860 30 2,500 2,352 10,000 6,000 25 256 24 300 St l Ft. 1,000 6,078 Total 9,750 a 5,000 Ft. 2,000 1,764 9,000 250 ge 20 800 18 194 / 677 200 4,000 1,500 8,000 / e Stages Spaci s. Latera Proppant Lateral 1,218 Fluid 15 150 L b 600 / erag 12 150 ng 457 3,000 Stage v g. 3,122 1,000 7,000 A 10 400 317 Lbs(‘000 . (Ft Av Fluid 100 ) 2,000 . total 2,128 ) 500 6,000 5 50 T o 200 1,000 1,339 0 0 0 0 0 5,000 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 Stages Stage Spacing Proppant Lbs./Lateral Ft. Total Proppant Fluid/Lateral Ft. Fluid / Stage Source: Company Data. 56

Multiple Long Term Density Pattern Tests Density Patterns Test Horizontal and Vertical Spacing 1,320ft spacing / 2 benches 1,500ft spacing / 2 benches 1,500ft spacing / 2 benches Section 29 18N 5W Section 8 17N 5W Section 28 17N 5W Spacing 600’ 600’ Pattern 180’ 180’ 180’ 1,320’ 1,320’ 1500’ 1500’ Implies 12 wells per section Implies 12 wells per section Implies 12 wells per section Cum 622 MBOE 780 days Cum 663 MBOE 660 days Cum 480 MBOE 540 days 1,000,000 1,000,000 1,000,000 100,000 100,000 100,000 Pattern 10,000 10,000 10,000 1,000 1,000 1,000 Results 100 100 100 1 121 241 361 481 601 1 121 241 361 481 601 1 121 241 361 481 601 Cum BO—3 Wells Cum BO—3 Wells Cum BO—5 Wells Mean—5 x 250 MBO 660ft spacing / 2 benches 1,000ft spacing / 3 benches 1,200ft spacing / 2 benches Section 31 19N 6W Section 9 & 10 17N 6W Section 23 15N 6W 334’ 334’ Spacing 170’ 1236’ 330’ 330’ 466’ 466’ 466’ 466’ 466’ 660’ 334’ 310’ Pattern 180’ 140’ 140’ 140’ 230’ 230’ 660’ 1,126’ 1,002’ 618’ 932’ 932’ 618’ 618’ Implies 24 wells per section Implies 18 wells per section Implies 12 wells per section Cum 319 MBOE 360 days Cum 348 MBOE 56 days Cum 12 MBOE 19 days 1,000,000 1,000,000 1,000,000 100,000 100,000 100,000 Pattern 10,000 10,000 10,000 Results 1,000 1,000 1,000 100 100 100 1 121 241 361 481 601 1 121 241 361 481 601 1 121 241 361 481 601 Cum BO—4 Wells Cum BO— 10 Wells Cum BO—4 Wells Mean—10 X 250 MBO 4 X 250 MBO Mean—4 X Mean—4 259 57

NAV Model Assumptions Operated Other Area Osage Meramec Oswego DrillCo 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 Locations 2,388 1,264 484 60 DrillCo 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 $0.35 Initial Production Tax—Oil (%) 2.1% 2.1% 2.1% 2.1% Initial Production Tax—Gas/NGLs (%) 2.1% 2.1% 2.1% 2.1% Severance Holiday (months) 36 36 36 36 Production Tax—Oil (%) 7.1% 7.1% 7.1% 7.1% Production Tax—Gas/NGLs (%) 7.1% 7.1% 7.1% 7.1% Ad Valorem Tax (%) 0.0% 0.0% 0.0% 0.0% Drilling & Completion Cost ($mm) 1 $3.5 $3.5 $2.5 $0.3 EUR Assumption Gross EUR Gross Sales Gas EUR (MMcf) 1,571 1,425 168 1,571 Gross NGL EUR (Mbbl) 141 128 15 141 Gross Oil EUR (Mbbl) 250 249 200 250 Total Gross EUR (Mboe) 652 615 243 652 Type Curve Assumptions Oil IP, 24-hr (Bbl/d) 200 170 320 200 Duration of Incline (Months) 2 2 — 2 Peak Rate (Bbl/d) 350 500 320 350 B Factor 1.20 1.20 1.20 1.20 Di-Continuous (Nominal) Decline (%) 73% 80% 72% 73% Terminal Decline (%) 7% 7% 7% 7% Natural Gas IP, Unshrunk, 24-hr (Mcf/d) 500 296 320 500 Duration of Incline (Months) 4 2 — 4 Peak Rate (Mcf/d) 900 1,250 320 900 B Factor 1.50 1.50 1.20 1.50 1-Di-Continuous (Nominal) Decline (%) 41% 56% 72% 41% Terminal Decline (%) 5% 5% 7% 5% NGL Yield (bbls/MMcf) 75 75 75 75 % Gas Shrink 15.9% 16.1% 15.9% 15.9% Note: Assumes 4,800 lateral length for all type curves. 58 1 D&C shown including PAD D&C facilities costs.

Osage Type Curve Summary 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 ? 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 Average Type Curve Cumulative Production 200 Gen 2.5 Type Curve 180 Gen 2.0 Type Curve (MBOE) 160 tion c 140 odu 120 P r oss 100 Gr 80 ive ulat 60 u m 40 C 20 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) Average Type Curve Key Statistics 1,200 Gen 2.5 Type Curve Gen 2.5 Gen 2.0 Gen 2.0 Type Curve Initial Rate (BO/D / MCF/D) 200 / 500 200 / 500 AMR Gen 2.0 Well Results Incline Period (oil / gas) 2 months / 4 months 2 months / 4 months Peak Rate (BO/D / MCF/D) 400 / 900 350 / 900 AMR Gen 2.5 Well Results b factor (oil / gas) 1.2 / 1.5 1.2 / 1.5 1,000 Initial Decline (oil / gas) 71% / 41% 72.6% / 41.2% Lateral Length 4,800 4,800 2-Stream EUR (MBOE) 622 561 3 Stream EUR (MBOE) 714 652 /D) Type Well IRR %1 87.2% 69.2% E O 800 ( B on uc ti Prod 600 s r os G 400 200 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. 59 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.

Meramec Type Curve Summary 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 ? 532 MBOE 2-Stream EUR; 615 MBOE 3-Stream EUR ? 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 250 OE) Meramec Type Curve B (M 200 Meramec Offset Well Results duction 150 r o P Gross 100 e Cumulativ 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) Average Type Curve 1,200 Meramec Type Curve Key Statistics 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% 1,000 Lateral Length 4,800 2-Stream EUR (MBOE) 532 3Stream EUR (MBOE) 615 Type Well IRR %2 78.1% 800 E /D) (BO n ctio 600 Prod u Gross 400 200 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’ laterallength. 1 Offset results based on Meramec wells drilled in the Updip Oil window of Kingfisher County since 2014. 60 2 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.

Oswego Type Curve Summary 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 ? 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 Average Type CurveCumulative Production uc rod P Type Curve ros s 140 Offset Well Results1 G (MBOE) 120 tion 100 oduc Pr 80 oss G r 60 ve ati 40 Cumul 20 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) Average Type Curve 1,500 Key Statistics Type Curve 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 Length 4,800 1,250 2-Stream EUR (MBOE) 233 3-Stream EUR (MBOE) 243 Type Well IRR %2 56.7% OE /D) 1,000 (B uc tion rod 750 P ros s G 500 250 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)

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. 61

2 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.

Substantial Inventory of Drilling Locations Identified Drilling Locations Prospective Drilling Locations Combined Average Working Interest Average Other (Including Working Formations Dow nspacing Total Dow nspacing Total Locations Interest (%) Locations Locations Locations Locations) (%) Locations Operated: Osage………………………. 1,196 72% — 1,141 1,141 73% 2,337 Meramec…………………… 676 74% — 676 676 74% 1,352 Osw ego…………………… 203 75% — 206 206 81% 409 Manning……………………. — — 168 — 168 75% 168 Other Formations…………. — — 1,327 — 1,327 70% 1,327

Total Operated…… 2,075 73% 1,495 2,023 3,518 73% 5,593 Drilling Inventory (Years) 14.4 — 10.4 14.0 24.4 — 38.8 Other: Osage………………………. 1,252 15% — 1,113 1,113 15% 2,365 Meramec…………………… 588 15% — 596 596 15% 1,184 Osw ego…………………… 281 13% — 310 310 14% 591

Manning……………………. — — 316 — 316 14% 316 Other Formations…………. — — 2,084 — 2,084 55% 2,084 Total Other……… 2,121 15% 2,400 2,019 4,419 28% 6,540 Total Gross Locations 4,196 3,895 4,042 7,937 12,133 Note: Does not include additional resource potential or undeveloped locations on ~20,000 net acres recently acquired in the Major County Acquisition. 62

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 Osage Osage Osage $3,541 $2,782 $4,945 $6,059MM $4,778MM $8,493MM Meramec Meramec Meramec $1,714 $1,351 $2,412 PDP Oswego PDPOswego PDP Oswego $484 $231 $414 $165 $641 $354 DrillCo DrillCo DrillCo $90 $67 $141

PV-10 at Research Consensus including Base PV-10 by Operated at Research Downspacing2 Identified Locations by Commodity Consensus Meramec Oswego Operated $1,714 $231

NGL 95% DrillCo 21% Oil $90 41% 4,196 4,196 Low Risk Osage Downspacing Gross Gross $9,492MM $3,541 $1,651 Locations Locations

Gas Additional 38% PDP Downspacing DrillCo Other $484 $1,782 2% 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). 63

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).

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 Shale Chester Unc. Meramec Unconformity Upr Meramec Lwr Meramec Upr Osage Lwr Osage Woodford Hunton Pre-WDFD Unc.

64

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 65

Significant Oswego, Osage/Meramec Osage prominent throughout, thickening to the north C South C’ C’ 5 North C South C’ C’ Manning Meramec Unc. Chester Shale Upr Meramec Lwr Meramec Upr Osage Lwr Osage Pre-WDFD Unc. Hunton Woodford 66 66

DrillCo JV Pivotal relationship with Bayou City Energy Parameters Entered into joint development agreement with Houston-based private equity firm, Bayou City Energy, in January 2016 Bayou City Energy primarily targets small operators with current production and focuses on off-balance sheet structures DrillCo funds 100% D&C cost, capped at average of $3.2MM/well 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 Strengths for Alta Mesa Cash flow Grow reserves Continue resource definition Continue pace up learning curve(s) Capture, hold acreage Maintain people/crews 2017 Alta Mesa Estimated Capital Expenditures Alta Mesa Only ~$349MM STACK STACK Acquisitions Drilling Pipeline, Facilities & Other With BCE ~$458MM STACK Acquisitions DrillCo Funded D&C Pipeline, STACK Facilities & Drilling Other Alta Mesa Funded D&C 67

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” Drilling Ability 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 Completions Less proppant, fluids, and pumping time per well, more simplified design, lower friction while pumping all help to reduce costs of optimized completions Mineral Owner Working with mineral owners across one-section (versus two-sections for longer laterals) allows for Relations more seamless and confident development program planning

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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 ners1 103.500 103.500 109.661 113.203 115.958 115.958 Riverstone2,3 85.875 85.875 92.149 95.756 98.562 98.562 KFM Ow ners4 55.000 55.000 62.143 68.393 68.393 68.393

Legacy Alta Mesa Ow ners5 144.271 144.271 154.986 164.361 178.249 190.749

Total Shares Outstanding 388.646 388.646 418.938 441.713 461.163 473.663

37.121 37.121 36.995 37.210 38.652 40.271 Equity Ow nership (%) @ $10.00 @ $11.50 @ $14.00 @ $16.00 @ $18.00 @ $20.00 Legacy Silver Run II Ow ners1 27% 27% 26% 26% 25% 24% Riverstone2,3 22 22 22 22 21 21 KFM Ow ners4 14 14 15 15 15 14 Legacy Alta Mesa Ow ners5 37 37 37 37 39 40 Equity Ow nership 100% 100% 100% 100% 100% 100% Equity Ow nership ($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 $2,319 Riverstone2,3 859 988 1,290 1,532 1,774 1,971 KFM Ow ners4 550 633 870 1,094 1,231 1,368 Legacy Alta Mesa Ow ners5 1,443 1,659 2,170 2,630 3,208 3,815 Total Equity Value ($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. 69

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.

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) 942.0 989.1 3,057.2 2,006.1 1,071.6 Natural Gas (MMCF) 3,116.0 3,088.9 9,110.2 4,272.6 2,083.0 NGLs (MBBLS) 275.0 280.4 901.0 499.4 315.6 Total Production (MBOE) 1,736.3 1,784.3 5,476.6 3,217.6 1,734.4 Daily Production (BOE/D) 19,292.6 19,394.7 15,004.3 8,815.3 4,751.7 Statement of Operations Revenue $ 63.6 $ 61.7 $166.4 $133.6 $117.3 Operating Expenses (Cash Items) 17.2 16.2 51.6 34.7 24.6 Exploration Costs (Cash Item) 5.0 7.5 17.2 9.8 11.8 Operating Expenses (Non-Cash) 20.2 23.8 63.3 80.3 29.4 General and Administrative1 9.7 8.7 40.5 37.9 68.4 Interest Expense1 12.3 1.4 43.4 62.5 55.8 Other Financial Data Adjusted EBITDAX2 $ 36.7 $ 36.8 $74.3 $61.0 $24.3 % Margin2 57.7% 59.6% 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. 70

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) ($0.8) $4.1 ($49.6) ($ 91.6) ($72.7) Adjustments: Interest expense 12.3 1.4 43.4 62.5 55.8 Exploration expense 5.0 7.5 17.2 9.8 11.8 Depreciation, depletion and amortization expense 18.9 23.7 62.6 61.3 29.1 Impairment expense 1.2 0.0 0.4 18.8 0.0 Accretion expense 0.1 0.1 0.3 0.2 0.3 Adjusted EBITDAX1 $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 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. 71