SMLP 2016 Analyst Day August 10, 2016

Senior Leadership Team With Over 100 Years of Combined Energy Experience Presenter Bios ` Steve Newby - Founder of Summit Midstream and a member of the Board of Directors of Summit Midstream Partners, LP and Summit Midstream Partners, LLC President & Chief Executive Officer Founded Summit in 2009 - Former fund manager for ING Investment Management focused on the energy infrastructure space - Former Managing Director and Head of Project Finance in SunTrust Robinson Humphrey’s Capital Markets Division - Over 20 years of energy experience Matt Harrison - Former Executive Vice President, CFO, Secretary, and Director at Hiland Partners, LP EVP & Chief Financial Officer Joined Summit in 2011 - Former Director in the Energy & Power Merger & Acquisitions Group at Wachovia Capital Markets and a Director in the M&A Group at AG Edwards & Sons, Inc. - Over 15 years of energy experience Brad Graves - Former Partner with Crestwood Midstream Partners, LLC EVP & Chief Commercial Officer Joined Summit in 2010 - Served as Executive Vice President, Business Development at Genesis Energy, LP - Over 25 years of energy experience Leonard Mallett - Former Senior Vice President of Engineering at Enterprise Products Partners, L.P. EVP & Chief Operations Officer Joined Summit in 2015 - Served as SVP of Operations at TEPPCO and, post-merger with Enterprise, was named SVP-Environmental, Health and Safety - Over 35 years of energy experience Brock Degeyter - Former Director of Corporate Governance and Senior Counsel at Energy Future Holdings EVP, General Counsel & Chief Compliance Officer Joined Summit in 2012 - Attorney with Correro Fishman Haygood Phelps Walmsley & Casteix LLP, specializing in securities regulations, structured finance, M&A and corporate transactions - Over 13 years of energy experience Marc Stratton - Former Assistant Vice President in the Midstream Energy Group at ING Investment Management SVP, Treasurer & Head of Investor Relations Joined Summit in 2009 - Former Vice President in Project Finance Group in SunTrust Robinson Humphrey's Capital Markets Division - Over 13 years of energy experience

Table of Contents Executive Summary 2016 Drop Down Review Macro Perspectives Utica / Marcellus Williston Basin Piceance / DJ / Barnett Engineering, Construction & Operations Health, Safety, Environmental & Regulatory Affairs Financial Overview Investment Considerations – Why Own SMLP Appendix: Non-GAAP Reconciliations

Disclaimers FORWARD-LOOKING STATEMENTS This presentation includes certain statements, estimates and projections concerning expectations for the future that are forward looking within the meaning of the federal securities laws. These “forward-looking” statements appear in a number of places in this presentation and include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would” and “could.” They also include, but are not limited to, statements regarding Summit’s plans, intentions, beliefs, expectations and assumptions, as well as other statements that are not historical facts. Generally, these statements can be identified by the use of forward-looking terminology including “will,” “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. When considering these “forward-looking” statements, you should keep in mind that a number of factors that are beyond Summit’s control could cause actual results to differ materially from the results contemplated by any such forward-looking statements including, but not limited to, the following risks and uncertainties: fluctuations in oil, natural gas and NGL prices; the extent and quality of natural gas volumes produced within proximity of Summit’s assets; failure or delays by Summit’s customers in achieving expected production in their natural gas projects; competitive conditions in Summit’s industry and their impact on Summit’s ability to connect natural gas supplies to its gathering and processing assets or systems; actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, and shippers; Summit’s ability to successfully integrate recently acquired assets including but not limited to the Drop Down Assets; operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond Summit’s control; Summit’s ability to control the costs of construction, including costs of materials, labor and right-of-way and other factors that may impact Summit’s ability to complete projects within budget and on schedule; the results or outcome of any legal matters or governmental investigations related to the January 2015 pipeline rupture at Mountaineer Midstream; and the effects of existing and future laws and governmental regulations, including environmental requirements on Summit’s business or operations. Forward-looking statements contain known and unknown risks and uncertainties (many of which are difficult to predict and beyond management’s control) that may cause SMLP’s actual results in future periods to differ materially from anticipated or projected results. Forward-looking statements in this presentation include statements regarding the necessity of accessing the debt and equity capital markets, financial guidance with respect to distribution growth, distribution coverage ratios, adjusted EBITDA, expected commodity prices and adjusted distributable cash flow, and the expected amount of the Deferred Payment. An extensive list of specific material risks and uncertainties affecting SMLP is contained in its 2015 Annual Report on Form 10-K as updated and superseded by the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 6, 2016, and as amended and updated from time to time. Any forward-looking statements in this presentation are made as of the date of this presentation and SMLP undertakes no obligation to update or revise any forward-looking statements to reflect new information or events. All of the forward-looking statements made in this document are qualified by these cautionary statements, and Summit cannot assure you that actual results or developments that Summit anticipates will be realized or, even if substantially realized, will have the expected consequences to, or effect on, Summit or its business or operations. Although the expectations in the forward-looking statements are based on Summit’s current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Summit expressly disclaims any obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Furthermore, the “forward-looking” statements reflect various assumptions by Summit concerning anticipated results, which assumptions may or may not prove to be correct. Neither Summit nor any of its affiliates has undertaken any independent investigation or evaluation of such assumptions to determine their reasonableness.

I. Executive Summary Steve Newby, President & CEO

SMLP Overview Public Unit Holders 45.4% LP Interest 100% Summit Midstream Partners, LLC (“Summit Investments”)(3) Summit Midstream Partners Holdings, LLC (“SMP Holdings”) 100% 2.0% GP Interest / IDRs 43.7% LP Interest 29.7MM Common Units Summit Midstream Partners, LP (NYSE: SMLP) (2) Org Structure Summit Midstream Partners, L.P. (NYSE: SMLP) is a growth-oriented limited partnership focused on developing, owning and operating midstream assets strategically located in core producing unconventional resource basins in the U.S. SMLP currently provides natural gas, crude oil and produced water gathering services primarily under long-term and fee-based gathering and processing agreements with customers in five resource basins, including the Appalachian Basin (including the Utica / Marcellus), Williston Basin, Fort Worth Basin, Piceance Basin and DJ Basin. SMLP Total Return / Annualized DPU As of August 5, 2016. As of June 30, 2016, an affiliate of Energy Capital Partners directly owned an 8.9% interest in SMLP. As of June 30, 2016, Summit Investments directly owned 151,160 LP units, representing a 0.2% interest in SMLP. Growth rate measured from SMLP’s minimum quarterly distribution at IPO of $0.40 per unit, or $1.60 per unit annualized. Distribution for the quarter ended June 30, 2016, will be paid on August 12, 2016. Total Return Annualized Distribution 48.8% 0.3% DPU Growth Since IPO(4): 43.8% DPU CAGR Since IPO(4): 10.9% ($ in millions, except per unit figures) (5) SMLP Price Per Unit (1) 22.55 $ Market Capitalization 1,502 $ Total Enterprise Value 2,817 $ Annualized 2Q 2016 Distribution Per Unit 2.30 $ Current Distribution Yield 10.2% 2016 Adjusted EBITDA Guidance $270 - $290

Track Record of Growth & Asset Diversification 2016E Adj. EBITDA Composition 56% 7% 21% 32% 6% SMLP Asset Map 2012 Initial public offering 2013 Entered Williston and Marcellus with the acquisitions of Bear Tracker and Mountaineer Midstream 2015 Continued development of Utica and Willison systems YTD 2016 SMLP acquires all remaining assets from GP 2014 Entered Utica with acquisition of 40% interest in Ohio Gathering Announced $300MM of new development projects in the Bakken Shale Executed contract with XTO to develop dry gas gathering system in the Utica 2012 IPO Adj. EBITDA Composition 48% 52% Includes contributions to equity method investees. Excludes drop down M&A. $250MM $723MM $879MM $201MM $358MM -- $107MM -- Organic Capex(1): Third-Party M&A(2): . . . . . .

Large U.S. Independent Producer Piceance / DJ 2Q16 Segment Adj. EBITDA(1) Services Provided AMI (acres) Aggregate Remaining MVCs Key Customers Natural Gas Gathering and Condensate Stabilization Natural Gas Gathering & Processing High-Pressure Natural Gas Gathering Natural Gas Gathering & Treating Natural Gas, Crude Oil & Produced Water Gathering >800,000 (3) 800,000 n/a 120,000 1,200,000 1,776 Bcf Confidential 82 Bcf 255 Bcfe $17 MM (21%) $26 MM (32%) $5 MM (6%) $14 MM (17%) $19 MM (24%) Segment adjusted EBITDA excludes the effect of allocated corporate expenses. Excludes 937 MMcf/d gross volumes associated with Ohio Gathering. Includes dedicated acreage from Ohio Gathering. Diverse Portfolio of Basins, Customers and Commodities Handled 2Q 2016 Volume Throughput N/A Nat Gas: 167 MMcf/d(2) Nat Gas: 24 MMcf/d Liquids: 86 Mbbl/d Nat Gas: 564 MMcf/d Nat Gas: 341 MMcf/d Nat Gas: 416 MMcf/d Utica Williston Barnett Marcellus Large U.S. Independent Producer

Evolution of SMLP’s Business Profile Revenue Composition 2016 Drop Down continues to further diversify SMLP geographically while enhancing its core focus on fee-based revenue Adjusted EBITDA Composition 18% 22% 42% 24% 32% 17% 2016E 2019E 2016E 2019E 12% 56% 32% 2012 at IPO 2012 at IPO 48% 52% 21% 12% 6% 6% Excludes CO2 revenue, electricity and favorable and unfavorable amortization of contracts, and other reimbursables, which are pass-through items. Includes gas retainage revenue which is used to offset compression power expense in the Barnett. Fee - Based (1) 97% Variable 3% Fee - Based (1) 98% Variable 2% Fee - Based (1) 98% Variable 2% Barnett Piceance Marcellus Utica Williston Barnett Piceance Marcellus Utica Williston Barnett Piceance

Differentiated Contract Portfolio with Significant MVC Underpinning SMLP Contract Portfolio Overview As of June 30, 2016. Weighted averages based on Total Remaining Minimum Revenue (Total Remaining MVCs x Average Rate). Weighted averages based on 2Q 2016 volume throughput for material customers’ contracts. Includes dedicated acreage from Ohio Gathering. Avg. MVCs Through 2020 = 62% of 2Q 2016 Throughput 62% Piceance/DJ Basins Barnett Shale Williston Basin Marcellus Shale Utica Shale Wtd. Avg. / Total Acreage Dedication (net acres) 800,000 120,000 1,200,000 n/a >800,000 (4) > 2,920,000 Total Remaining Commitment (Bcfe) (1) 1,776 82 255 Confidential n/a 3,434 Avg. Daily MVCs through 2020 (Mmcfe/d) (1) 696 50 113 Confidential n/a 1,249 2Q 2016 Avg. Daily Throughput (MMcf/d) 564 341 24 416 167 1,512 2Q 2016 Avg. Daily Throughput (Mbbl/d) -- -- 86 -- -- 86 Wtd. Avg. Remaining MVC Life (1,2) 8.9 years 3.3 years 5.3 years Confidential n/a 8.4 years Remaining Contract Life Range (1,3) 13.4 years 10.8 years 6.7 years Confidential 12.5 years 13.4 years

ECP Defines a Supportive Sponsor More Capital Committed Today Since December 2015, ECP has implemented a $100MM open market unit purchase program Willing to invest more to support SMLP growth objectives and other strategic initiatives Four Drop Downs at Attractive Valuations Four drop down transactions since SMLP IPO in 2012 Assets dropped at EBITDA multiples ranging from 6.5x – 9.3x GP assumed development and financing risk, enabling SMLP to participate in growth that it would not have been able to pursue independently “Fund II” 2010 Vintage Reviewing ECP’s Track Record of Support Flexibility in Consideration Mix Transactions have been structured with a mix of cash and equity consideration to maximize value to SMLP In conjunction with the first drop down in 2Q 2013, the GP took back $50MM of equity consideration, at-the-market In conjunction with the 2013 acquisition of Mountaineer Midstream, the GP invested $100MM of equity, at-the-market During 1Q 2016, the GP dropped down all operating assets to SMLP, pursuant to a long-dated Deferred Payment structure Capital Markets Support IPO proceeds primarily used to reduce SMLP’s debt to provide leverage capacity, enabling SMLP to pursue organic development and drop downs Willing to take back additional units for the Deferred Payment in 2020

II. 2016 Drop Down Review

Market Perception vs. Reality Summit Investments’ ownership of approximately 30 million SMLP units and 100% of the IDRs provides ECP with a powerful economic incentive to drop down assets from Summit Investments to SMLP on an accretive basis to facilitate future distribution growth. Our goal is to structure drop downs in a manner that eliminates the equity capital market risk in 2016 for SMLP, strengthens growth and coverage of SMLP and improves the long term credit profile of the partnership. - Summit Investments Press Release, December 11, 2015 What We Said – December 2015 What We Did – February 2016 Market Perception of SMLP in 2H ’15 investor response puts downward pressure on SMLP unit price. 1. ORPHAN RISK Prevailing fear among investors that ECP’s strategic review would result in the sale of Utica assets to a Third Party, leaving SMLP without a growth catalyst 2. CAPITAL MARKETS RISK Even if Utica assets aren’t sold to a Third Party, the capital markets are unavailable or equity prices unattractive to drop down assets on an accretive basis 3. DISTRIBUTION RISK Distribution coverage ratio of 0.85x in 3Q 2015 together with weakening commodity prices leads to concern that distribution may be cut

Transformational Drop Down Positions SMLP for Future Growth Further Diversifies Business Expands operating footprint into the Utica and DJ while enhancing Williston presence Adds additional high quality customers Diversifies overall customer exposure and reduces individual producer risk profile Utica assets situate SMLP in the core of one of the largest and most prospective natural gas plays in the United States Assets dropped to SMLP in February 2016 - at the low point in the recent commodity cycle Positions SMLP to capitalize on a recovery in commodity prices through new organic and acquisition growth opportunities Offers Significant Growth Opportunities Highly attractive valuation and structural protections demonstrate ECP’s commitment to SMLP As the largest single owner of SMLP, the GP is highly incentivized to “make SMLP work” Structure and enhanced economic alignment alleviates the Street’s prior concerns regarding orphan risk and ECP’s commitment to SMLP Illustrates ECP’s Continued Support of SMLP Structure allows SMLP to avoid accessing the public debt and equity capital markets Increases scale and improves distribution coverage with 2016 YTD distribution coverage of 1.27x Transaction allowed SMLP to increase its liquidity revolver position to more than $500 million and enhance its credit profile in a challenging macro environment Strengthens Capital Position Compelling valuation with consideration for Drop Down Assets based on a 6.5x multiple of average LTM EBITDA actually generated during 2018 and 2019 Estimated $1.1 billion total net investment represents a book value multiple of ~1.0x Structure offers substantial downside protection to SMLP with development and asset performance risk retained by the GP Highly Attractive Valuation and Structure to SMLP

Impact of the 2016 Drop Down Transaction Pre-Announce Total Return (1/1/2016 – 2/25/2016) 31.7% 13.6% 18.0% AMZ Total Return SMLP Total Return Relative Total Return 88.8% 33.6% 55.2% AMZ Total Return (1) SMLP Total Return Relative Total Return SMLP has outpaced the Alerian MLP Index by ~55% since announcing the 2016 Drop Down Sources: SNL Financial and Alerian MLP Index. (1) Data for the Alerian MLP index only available through 7/29/2016 per the Alerian MLP Index website. Post-Announce Total Return (2/26/2016 – 8/5/2016) (40%) (30%) (20%) (10%) 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 110% 12/31/15 1/3/16 1/6/16 1/9/16 1/12/16 1/15/16 1/18/16 1/21/16 1/24/16 1/27/16 1/30/16 2/2/16 2/5/16 2/8/16 2/11/16 2/14/16 2/17/16 2/20/16 2/23/16 2/26/16 TR / Relative TR (40%) (30%) (20%) (10%) 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 110% 2/25/16 3/3/16 3/10/16 3/17/16 3/24/16 3/31/16 4/7/16 4/14/16 4/21/16 4/28/16 5/5/16 5/12/16 5/19/16 5/26/16 6/2/16 6/9/16 6/16/16 6/23/16 6/30/16 7/7/16 7/14/16 7/21/16 7/28/16 8/4/16 TR / Relative TR

Attractive Valuation Based on Actual Future Performance Illustrative Deferred Payment Sensitivity Total Net Investment Fixed at 6.5x EBITDA Multiple Based on 2018 and 2019 average adjusted EBITDA of the Drop Down Assets 6.5x fixed adjusted EBITDA multiple determines implied value in 2020 Structure Protects SMLP from Performance & Development Risks In return for the GP retaining risk, the cumulative Free Cash Flow (“FCF”) from the assets over the deferral period (cumulative EBITDA less cumulative capex), accrues to the GP If EBITDA underperforms, the Deferred Payment decreases If EBITDA outperforms, the Deferred Payment increases SMLP Secures an Attractive Valuation The 2016 Drop Down structured to ensure SMLP only pays for actual performance of assets Under all scenarios shown, the 2016 Drop Down represents a total net investment of 6.5x multiple of average 2018 and 2019 EBITDA ($ in millions) Significant Structural Benefits Deferred Payment Calculation SMLP Net Investment Deferred Payment $509 $683 $858 $1,031 $1,205 (+) Initial Payment $360 $360 $360 $360 $360 (+) Cum. FCF retained at SMLP ($57) ($68) ($80) ($91) ($102) Total net investment $813 $975 $1,138 $1,300 $1,463 Multiple of Avg. EBITDA 6.5x 6.5x 6.5x 6.5x 6.5x '18 - '19 Avg. EBITDA $125 $150 $175 $200 $225 Sensitivity % (29%) (14%) 0% 14% 29% (x) EBITDA multiple 6.5x 6.5x 6.5x 6.5x 6.5x A) Implied value $813 $975 $1,138 $1,300 $1,463 B) Initial Payment ($360) ($360) ($360) ($360) ($360) (+) Cum. EBITDA $394 $472 $555 $630 $709 (-) Cum. Capex ($337) ($404) ($475) ($539) ($606) C) Cum. FCF $57 $68 $80 $91 $102 Deferred Payment (A+B+C) $509 $683 $858 $1,031 $1,205

Structure Protects SMLP From Asset Performance & Development Risk What if EBITDA & Capex expectations are wrong? LOWER EBITDA HIGHER Capex HIGHER EBITDA LOWER Capex The amount of the Deferred Payment is adjusted by the cumulative amount of capital expenditures and EBITDA generated by the assets over the deferral period (through December 31, 2019) This mechanism keeps the asset performance and development risks at the GP during the deferral period ($ in millions) Sensitizing EBITDA Sensitizing Capex Consistent Outcome '18 - '19 Avg. EBITDA $125 $150 $175 $175 $175 $200 $225 Sensitivity % (29%) (14%) 0% 0% 0% 14% 29% (x) EBITDA multiple 6.5x 6.5x 6.5x 6.5x 6.5x 6.5x 6.5x A) Implied value $813 $975 $1,138 $1,138 $1,138 $1,300 $1,463 B) Initial Payment ($360) ($360) ($360) ($360) ($360) ($360) ($360) (+) Cum. EBITDA $394 $472 $555 $555 $555 $630 $709 (-) Cum. Capex ($594) ($594) ($594) ($475) ($356) ($356) ($356) Sensitivity % 25% 25% 25% 0% (25%) (25%) (25%) C) Cum. FCF ($200) ($121) ($39) $80 $199 $274 $352 Deferred Payment (A+B+C) $252 $494 $739 $858 $976 $1,214 $1,455 (+) Initial Payment $360 $360 $360 $360 $360 $360 $360 (+) Cum. FCF retained at SMLP $200 $121 $39 ($80) ($199) ($274) ($352) Total net investment $813 $975 $1,138 $1,138 $1,138 $1,300 $1,463 Multiple of Avg. EBITDA 6.5x 6.5x 6.5x 6.5x 6.5x 6.5x 6.5x

Structure Provides Deferred Payment Financing Flexibility Deferred Payment Plan of Finance Structure Offers “Option Value” Pre-Announce of 2016 Drop Down: Bond YTW: 16.5% - 20.5% (2) Distribution Yield: 13.6% - 16.3% (2) Avg. Dist. Yld.: 8.9% Avg. YTW: 7.4% Sources: Bond and distribution yields per Bloomberg. Market statistics include dates in which the 5.5% Senior Notes due 2022 actually traded. Represents the range of yields based on the 5 days prior to announcing the 2016 Drop Down. Represents yield to worst of the 5.5% Senior Notes due 2022. (3) 2016 Drop Down acquired with SMLP’s revolver, avoiding dislocated capital markets Structure provides SMLP with option value, allowing it to “pick its spots,” should it choose to pre-fund the 2020 deferred payment SMLP intends to structure the consideration mix of debt and equity to target the following pro forma metrics: 4.0x leverage 1.10x – 1.20x distribution coverage The following is an illustrative analysis that demonstrates the impact of financing costs on incremental cash flow Illustrative assumptions include: $1.1 billion total net investment 50% debt and 50% equity consideration mix $2.30 distribution per unit Represents illustrative 2018 & 2019 average incremental annual cash flow Significant potential cash flow benefit if SMLP can finance the 2020 deferred payment near its 2-year average cost of capital Historical Bond & Dividend Yields (1) (In millions) At Long-Term Illustrative State of the Market Announce Current Average Illustrative total net investment $1,138 $1,138 $1,138 Revolver financing at close $360 $360 $360 Illustrative revolver cost (%) 4.0% 4.0% 4.0% Illustrative long-term debt financing $209 $209 $209 Illustrative cost of debt (%) 18.5% 6.9% 7.4% Illustrative equity financing $569 $569 $569 Illustrative distribution yield (%) 15.0% 10.2% 8.9% Illustrative units issued 37 25 22 Incremental avg. EBITDA (2018 / 2019) $175 $175 $175 (-) Incremental annual interest expense (53) (29) (30) (-) Incremental annual maintenance capex (10) (10) (10) Incremental annual DCF $112 $136 $135 (-) Incremental annual GP interest & IDRs (6) (4) (4) (-) Incremental annual dist. on units issued (85) (58) (51) Incremental annual cash flow $21 $74 $81 Incremental annual cash flow per LP unit $0.20 $0.81 $0.91 Relative to at announce $0 $53 $60 -8% -3% 2% 7% 12% 17% 22% Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Yield / Spread Spread Bond YTW Distribution Yield

III. Macro Perspectives Steve Newby, President & CEO Brad Graves, EVP & CCO

U.S. Natural Gas Demand + Net Exports set to grow from 65.9 Bcf/d in 2015 to 82.5 Bcf/d in 2020 Natural Gas Demand Growth is Happening Sources: Goldman Sachs Research (June 2016) and Baker Hughes. 2016 rig count as of July 29, 2016. Demand growth is real and not reliant upon winter weather: Gas-fired Power Demand: 26.2 Bcf/d in 2015 30.4 Bcf/d in 2020E LNG Exports: (0.3) Bcf/d in 2015 4.3 Bcf/d in 2020E Exports to Mexico: 3.0 Bcf/d in 2015 6.8 Bcf/d in 2020E U.S. natural gas rigs are near an all-time low. Price response is underway and will entice drilling necessary to accommodate future demand U.S. Demand + Net Exports U.S. Gas Rig Count 4.3% CAGR ~ 90% Reduction (10) 0 10 20 30 40 50 60 70 80 90 2011A 2015A 2020E Bcf per Day Net Exports Residential / Commercial Industrial Power Vehicle 809 431 374 340 162 86 0 100 200 300 400 500 600 700 800 900 2011 2012 2013 2014 2015 2016 Year-End Gas Rig Count

Production declines occurring; however, cautious on near-term prices as inventories remain a headwind Crude Oil Market Outlook Sources: Bloomberg & EIA. As of July 29, 2016. Based on IEA estimates of 1.5 million bbl/d. After an 85%+ rally from its February 2016 lows, WTI prices have retreated ~ 16% since the end of May 2016 58 new crude oil rigs added since the May 27th trough(1) Presumption that many E&Ps added hedges as the 12-month strip traded in the $50-$53 / bbl range in late May and early June Crude oil and product inventories remain at or near all-time highs, which has placed downward pressure on prices amidst tepid near-term global demand Long-term fundamentals remain intact as non-OPEC production is declining and OPEC spare capacity remains limited(2) WTI Pricing(1) U.S. Crude Oil Inventories Rig count trough (May 27: 316 rigs) 58 rig adds since trough Crude prices down ~ 16% $20 $25 $30 $35 $40 $45 $50 $55 $60 $65 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 $ per Barrel 200,000 250,000 300,000 350,000 400,000 450,000 500,000 550,000 600,000 Week 1 Week 5 Week 9 Week 13 Week 19 Week 23 Week 27 Week 31 Week 37 Week 41 Week 45 Week 49 Mbbl 5 Year Range 5 Year Average 2015 2016

Drilling Productivity Gains Bakken Drilling Efficiencies Utica Drilling Efficiencies Productivity Gains Rig count down ~90% from peak New-well production per rig up ~190% since peak rig date Rig count down ~80% from peak New-well production per rig up ~ 50% since peak rig date Producers have partially offset lower commodity prices with drilling efficiency gains and cost savings from other participants in the energy value chain As a result, producer IRRs have not declined in-line with commodity prices Basin differentials in the Williston Basin have tightened substantially as takeaway transitions from rail to pipe Higher netbacks of $6-$10 / Bbl provide immediate uplift to producer economics Drilling productivity gains = more volume throughput per well – highly incremental to gathering companies High grading of acreage Current drilling largely focused on most productive, core areas Longer laterals Producers continue to test the boundaries of lateral length Continuously improving technology / frac techniques Source: EIA.

Legend Processing Plants Pipelines Summit Family WILLISTON Cost reductions and other efficiency gains have offset lower commodity prices Further diversification of basin take-away capacity from rail to long-haul pipelines SMLP has an expansive footprint and is well-positioned to scale its presence Strategic Perspectives by Area Themes by Basin UTICA / MARCELLUS Early innings of Utica development World-class reservoir that is poised to supply the bulk of U.S. natural gas supply growth Long-haul capacity additions will improve basis differentials and overall drilling economics SMLP is strategically positioned to deploy meaningful amounts of capital and expand its existing position PICEANCE / DJ / BARNETT Significant customer diversity, including a number of single-basin customers, several of which have continued to drill through the cycle Volume upside as acreage trades occur and fresh capital enters the basin Provides SMLP with a steady cash flow base with numerous near-term catalysts that provide upside potential

III A. Utica / Marcellus Poised to Deliver Bulk of Marginal Supply

Utica & Marcellus production growth has more than outpaced the declines experienced across the rest of the U.S. Utica & Marcellus Growth Since 2010, total U.S. natural gas production has grown by approximately 16 Bcf/d Over that same period, production from the Utica & Marcellus have grown by 19 Bcf/d Source: EIA. U.S. Natural Gas Production 40 45 50 55 60 65 70 75 80 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15 Jan-16 Bcf/d Rest of U.S. Marcellus Utica 2010 YTD 2016 CAGR Rest of U.S. 55.7 52.1 (1.2%) Marcellus 2.5 18.2 43.9% Utica 0.2 3.6 79.2% Bcf/d

Basin Economics Justify Activity Levels Source: Gulfport public disclosures (May 2016). Assumes ethane rejection. Well economics are based on flat price case of $3.50 / MMBtu gas, $58.00 / Bbl oil, and $14.00 Bbl NGLs. Gulfport Drilling Economics Antero Drilling Economics “ at a $3 plus strip, we believe we can easily ramp to a six-rig program. Based on our current estimates, we anticipate this level of activity would result in a year-over-year growth in 2017 of approximately 20% to 25%.” – 2Q 2016 Earnings Call “As it relates to well economics, as you'd expect, a 33% reduction in well costs and a 33% increase in EURs has a significant impact on returns and drives very attractive economics on AR's development program.” – 2Q 2016 Earnings Call Source: Antero public disclosures (August 2016). 6/30/2016 pre-tax well economics based on 1.7 Bcf/1,000’ type curve for Marcellus 9,000’ lateral, 6/30/2016 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and ~50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates include $1.2 million for road, pad and production facilities. ROR @ 6/30/2016 Strip-With Hedges reflects 6/30/2016 well cost ROR methodology, with the 6/30/2016 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices. Marcellus undeveloped well locations as of 12/31/2015 adjusted for 6/30/2016 net acreage and pro forma for third-party acreage acquisition per press release dated 6/9/2016.

Utica – Continuously Raising the Bar Utica – Growth Engine Improving Productivity Summit entered the Utica Shale in 4Q 2013 with the announcement that it would acquire an option to acquire 40% of Ohio Gathering Option was exercised in 2Q 2014 Since its initial announcement, reported EURs are up over 20% in the wet gas and condensate windows and up over 50% in the dry gas window Drilling productivity gains are highly incremental to the midstream segment and have served to help offset declines in overall rig count 54% 20% 24% Productivity Example: Gulfport EURs Significant volume growth over the last two years Dry gas volumes have offset flattening liquids-rich volumes as crude oil / NGL prices have weakened Ohio Gathering volume throughput is reported on an 8/8ths basis. SMLP owns a 40% interest in Ohio Gathering. Based on information from the Ohio DNR. SMLP Utica Volumes 12.3 10.2 2.8 19.0 12.2 3.5 0.0 4.0 8.0 12.0 16.0 20.0 Dry Gas Wet Gas Condensate Bcf Acquisition - 2013 Current - 2016 0 150 300 450 600 750 900 1,050 1,200 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 MMcf/d OGC Liquids-Rich Gas(1) OGC Dry Gas(1) Summit Utica Dry Gas

SMLP’s Growing Market Share SMLP Has Participated Disproportionately in the Ramp of the Utica SMLP’s build-out of its wholly-owned Summit Utica gathering system and the commissioning of the OGC dry gas system have enabled it to grow its market share over the last four quarters Total production in the Utica is estimated to grow to 9 to 10 Bcf/d by 2020(1) Assuming SMLP maintains its current market share, its implied 2020 volume throughput would grow 150%+ relative to current levels Utica Production Growth Goldman Sachs Research (June 2016). Ohio Gathering volume throughput is reported on an 8/8ths basis. SMLP owns a 40% interest in Ohio Gathering. Illustrative Growth Outlook MMcf/d YTD 2016 2017E 2018E 2019E 2020E Total Est. Utica Production(1) 3,647 3,706 5,194 7,341 9,363 Status Quo Market Share SMLP Market Share 28.9% 28.9% 28.9% 28.9% 28.9% Implied SMLP Volume Throughput 1,055 1,072 1,502 2,123 2,708 Growth over YTD 2016 0% 2% 42% 101% 157% Increasing Market Share SMLP Assumed Market Share 35.0% 35.0% 35.0% 35.0% Implied Volume Throughput 1,297 1,818 2,569 3,277 Growth over YTD 2016 23% 72% 144% 211% Decreasing Market Share SMLP Assumed Market Share 25.0% 25.0% 25.0% 25.0% Implied Volume Throughput 927 1,299 1,835 2,341 Growth over YTD 2016 (12%) 23% 74% 122% 0% 15% 25% 29% 0% 5% 10% 15% 20% 25% 30% 35% 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 2013 2014 2015 YTD 2016 Market Share MMcf/d Non-Summit Utica Production Summit Utica Production(2) Summit Market Share

Utica Growth – How Do We Get There? Large Inventory of Drilling Locations Asset Footprint Based on existing leaseholds, SMLP estimates that its customers have ~ 1,200 to 1,500 future drilling locations in its Utica AMIs Condensate Wet Gas Dry Gas Summit Utica Focus Area Ohio Gathering Focus Area Levered to In-Fill Drilling Producer activity to date has been focused on holding leases Existing pad sites have an average of 3.2 wells per pad SMLP estimates that once fully developed, most Utica pad sites will have 6-8 wells Represents ~ 230 – 400 future wells that will not require additional pipe capex Assumes an average lateral length of 8,000 feet. Existing Wells per Pad Site (1) 160 acres 180 acres 200 acres Leased Acres in AMI ( Approx. ) 290,000 290,000 290,000 Acre Spacing 160 180 200 Total Potential Well Locations 1,813 1,611 1,450 Existing Wells 265 265 265 Future Wells 1,548 1,346 1,185 % of AMI Developed 15% 16% 18% Acre Spacing

Basin Positioning & Outlook Area Positioning, Strategy & Outlook SMLP’s Northeast assets have exposure to the liquids-rich Marcellus in West Virginia and the dry gas, wet gas, and condensate windows of the Utica in Ohio Geographic Footprint Area Positioning Expansive footprint with exposure to all three windows of the Utica as well as the rich-gas Marcellus in West Virginia Top tier drilling economics at strip pricing and despite basis headwinds 15+ Bcf/d of new takeaway capacity slated to come online by YE 2018, should improve basis and producer returns Producer activity to date focused on holding lease expirations Significant operating leverage as producers develop existing pad sites from ~ 3 wells per pad to 6-8 wells per pad Area Strategy Broad opportunity set for future growth Organic growth SMLP has a unique appeal to Utica producers that do not want to contract with E&P competitors’ midstream affiliates Regional asset-level M&A Significant upside relative to the emerging Deep Utica in SW Pennsylvania and NW West Virginia SMLP is having preliminary discussions with producers testing the Deep Utica Near-Term Outlook Increasing rig activity as commodity prices firm and basis differentials compress Return to liquids-rich drilling activity Infill drilling from existing PAD sites translates into more volume for less capex

III B. Williston Basin Weathering the Storm

SMLP still tracking to its Polar & Divide drop down multiple guidance despite 25%+ decline in crude oil strip since transaction was announced in May 2015 Williston Basin Growth SMLP – Doing What We Say How We Did It Customer diversity and SMLP’s location in the core area of the Bakken has enabled it to outperform basin-wide trends Since its peak in 4Q 2014, non-SMLP Bakken production has declined at an 11.1% CAGR Over that same period of time, crude oil throughput on SMLP’s gathering systems has increased by 21.0% SMLP Announces $255 Million Drop Down Acquisition of the Polar & Divide System in the Williston Basin “The all-in cost of the transaction, including the additional $35 million option and approximately $75 million of growth capex that we expect to incur through the end of 2016, is expected to represent a 7.8x multiple of 2016 projected EBITDA.” – 1Q 2015 Earnings - 20 40 60 80 100 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 MBbl/d Crude Oil Throughput Produced Water Throughput - 5 10 15 20 25 30 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 MMcf/d Natural Gas Throughput MBbl/d Non-Summit Bakken Production 4Q 2014 (Bakken Peak) 1,194 2Q 2016 1,000 CAGR (11.1%) Summit Crude Oil Throughput 4Q 2014 (Bakken Peak) 41 2Q 2016 54 CAGR 21.0%

Significant Efficiency Gains Overview Avg. Drilling & Completion Costs(1) At its peak, there was a significant amount of profit margin and redundancy in the North Dakota oil and gas value chain compared to other shale plays As commodity prices tumbled, producers have been able to offset reductions in price with lower operating and capital expenditures Additionally, producers are high-grading acreage, which has resulted in higher EURs on a per well basis Finally, transportation costs have decreased as long-haul pipelines have been commissioned and volumes have migrated from rail to pipe Avg. Bakken EUR (1) Current Transportation Costs (1) Based on public disclosures of major Williston operators, including CLR, EOG, HES, OAS, and WLL. 22% (24%) $0.00 $3.00 $6.00 $9.00 $12.00 $15.00 $18.00 Rail Pipe $ / Bbl $8.0 $6.1 $0.0 $3.0 $6.0 $9.0 2014E 2016E $ / MM 645 785 0 300 600 900 2014E 2016E MBOE

 Translates Into Enhanced Producer Returns Source: Whiting public disclosures (May 2016). All volumes shown are un-risked. EURs and IRRs will vary well to well. Whiting Drilling Economics (1) Source: SM Energy public disclosures (June 2016). Based on $4.1 million well cost and 10,000 ft lateral length. Well costs include drill, complete, and equip; assumes 2016 estimated CWC, $3.00/MMBtu gas. SM Energy Drilling Economics “Our Williston Basin enhanced completion technique continues to perform well, and our wells are tracking at 900,000 barrels of oil equivalent per well type curve after 200 days. This underscores the high quality of Whiting acreage.” – 2Q 2016 Earnings Call “Overall, we have an excellent, contiguous and largely HBP asset in North Dakota. It's a great operating environment up there with new infrastructure in place and an SM team that is successfully driving performance and improving the rates of return on our investment in new wells in the Bakken and Three Forks.” – 2Q 2016 Earnings Call

Significant Development Opportunities Exist Near-Term Upside with DUC Completions (1) In-Fill Drilling Offers “Low Hanging Fruit” SMLP estimates 55 drilled but uncompleted wells are on the system across five different producers Currently SMLP has ~265 PADs and ~515 wells connected to its system (2) 73% of PADs with 2 or less wells Limited incremental capex required from SMLP to bring incremental wells online Williston assets have a stable base of cash flow and offer upside potential: Completing the backlog of drilled but uncompleted wells already on the system In-fill drilling locations require limited to no incremental capex to SMLP Potential for additional locations with higher crude prices Existing PADs In-Fill Drilling Potential ~265 PADs 3+ Wells per PAD (27%) 2 Wells per PAD (22%) 1 Well per PAD (51%) As per DI Desktop production database, which includes wells with a “Spud” date, but no “Completion” date Represents an estimate of wells and pad sites on selected Williston assets; Excludes wells and pad sites on the Bison system 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0 18 27 40 47 48 55 0 10 20 30 40 50 60 Q4 '14 Q1 '15 Q2 '15 Q3 '15 Q4 '15 Q1 '16 Q2 '16 Cumulative DUCs SPUD date Est. Range Low High Approx. wells connected 515 (/) Appox. PADs connected 265 Avg. wells per PAD 1.9 Incremental wells per PAD 2.1 3.1 Total est. wells per PAD 4.0 5.0 (x) Approx. PADs connected 265 Total est. wells available 1,060 1,325 (-) Approx. wells connected (515) (-) Approx. DUCs (55) Est. wells from in-fill drilling 490 755

Basin Positioning Area Positioning, Strategy & Outlook SMLP has an expansive footprint in the northern core of the Williston Basin Geographic Footprint Area Positioning Expansive footprint 1,100+ miles of crude oil, natural gas and produced water pipelines Approximately 1.2 million acres dedicated in the Williston basin Drilling economics in Williams and Divide counties support future rig activity System designed to provide customers with downstream optionality COLT Hub (Crestwood Rail) Little Muddy (Enbridge) Stampede (Basin Transload Rail) DAPL (pipe to Patoka / Nederland) – Under construction Area Strategy Packaged services (i.e. crude oil, produced water, and natural gas gathering) are cost efficient and also attractive to the customer Broad opportunity set for future growth Producer RFP activities have begun to increase Capturing market share from trucks Consolidation opportunities Numerous failed M&A processes in 2014 / 2015 expected to come back to market over the next several years Near-Term Outlook Customers to continue drawing down DUC inventory during 2H 2016 and into 2017 Compressed basis differentials and firming commodity prices to drive increased infill drilling activity Enhanced completion activity driving higher EURs across footprint Liquids System Gas System $1.5BN to $2.0BN of Potential M&A Backlog in Close Proximity to SMLP’s Williston Assets

III C. Piceance / DJ / Barnett Don’t Judge a Book by its Cover

Highly contracted business model enables SMLP to avoid negative impact of declining volumes Resiliency of SMLP’s Piceance Footprint Since 2013, volume throughput on SMLP’s Piceance system has declined at a 5.4% CAGR During that same period, non-SMLP Piceance volumes have declined by 11.8 % All of SMLP’s total volume decline is attributable to SMLP’s anchor customer, which is substantially underpinned with MVCs Volume declines do not necessarily translate into decreases in cash flow Source: COGIS. (1) Excludes volumes associated with SMLP’s DJ Basin operations. (2) Includes contributions from SMLP’s DJ Basin operations. Piceance Volumes(1) Piceance / DJ Segment Adjusted EBITDA(2) SMLP Basin 7.7% (5.4)% (11.8)% CAGR: 0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2013 2014 2015 YTD 2016 MMcf/d Non-SMLP Piceance Volumes SMLP Piceance Volumes MVCs in Excess of SMLP Volumes $80 $111 $110 $104 $0 $20 $40 $60 $80 $100 $120 2013 2014 2015 LTM $s in millions Segment Adj. EBITDA in Excess of MVCs MVC Shortfalls MMcf/d Non-Summit Piceance Production 2013 1,510 2016 YTD 1,102 CAGR (11.8%) SMLP Piceance Volumes 2013 645 2016 YTD 561 CAGR (5.4%)

Piceance Basin – A Changing Landscape Recent acreage trades and fresh capital have stimulated production activity in SMLP’s Piceance Basin Ursa Announces Acquisition of Antero Resources Piceance Basin Assets “We are extremely pleased with our acquisition of the Antero Piceance assets. We look forward to working with all stakeholders to prudently develop these assets.” Results Antero had largely been inactive in the Piceance. Volumes were in a state of decline Recent well results have exceeded IP expectations by ~50% Results Noble had been largely inactive in the Piceance. Volumes were in a state of decline Since its acquisition, Caerus has drilled over 15 new wells Results WPX had reduced its activity in the Piceance following its acquisition of Permian Basin assets Since Terra’s announcement, the 12-month natural gas strip is up by more than 25% Noble Sells its Piceance Holdings to Caerus “The entry of privately held companies and MLPs has been a positive development as their business models and investment strategies are often in better alignment with opportunities of the Piceance.” Terra Energy Agrees to Acquire Piceance Basin Assets from WPX Energy “The Piceance Basin is an area that we know well and one that we believe offers considerable upside potential through focused management.” Source: DI Desktop and various other public filings. 2012 2014 2016

Piceance Basin – Potential Implications for Summit Source: DI Desktop and various public filings. (1) Per WPX’s August 18, 2015 investor presentation describing the Piceance assets. 68% 11% 8% 8% 5% RIG PRESENT Permitting Activity Picking Up in the Core of the Piceance Since 1/1/2016 Detail on Terra’s Acquisition of WPX’s Piceance Assets Acreage Acquired(1) Transaction Details Selected Asset Details Close Date: April 8, 2016 Transaction Value: $910MM Other: Terra assumed $104MM of transportation obligations and $105MM of natural gas derivative contracts ~200,000 net acres(1) ~10,000 gross drilling locations(1) ~160,000 acres of unbooked deep resource potential (Niobrara / Mancos dry gas)(1) 1,822 Bcfe of total proved reserves (85% gas) as of 12/31/2015 2015 production: 585 MMcfe/d

Niobrara – Permitting Activity Showing Signs of Strength(1) Producing Wells on Summit’s System “Original Drill” Permits Since 1/1/2016 Since January 1, 2016, there have been several new horizontal drilling permits granted within close proximity to Summit’s existing Niobrara footprint 75% of permits have been issued to existing Summit customers New drill permits have been issued for both the Codell and Niobrara, divided equally by formation Of the wells currently being served by Summit’s system, only 33% have targeted the Codell formation Source: DI Desktop and other publicly available information. DI Desktop permit database screening criteria: Permit Grant Date ranging from 1/1/2016 to current; Permit Type includes “Original Drill”; Status includes “Drilling” and “Permitted.” Represents producers identified within the DI Desktop permit database. Selected Producers within SMLP Capture Area(2) RIG PRESENT Large U.S. Independent Producer

Basin Positioning – Piceance / DJ Area Positioning, Strategy & Outlook Positioned in the core of the Piceance/DJ Basins with exposure to the liquids-rich Mesaverde formation as well as the emerging Mancos & Niobrara formations Geographic Footprint Area Positioning System fully built-out with minimal maintenance capex requirements SMLP’s scale in the area affords it significant operating leverage SMLP Piceance Operations team has made significant improvement in Controllable Opex per Mcfe Regional pipelines re-contracting at lower rates improves drilling economics for area producers Significant customer diversity, which has offset lower activity levels from SMLP’s anchor customer 40+ customers, several of whom have limited non-Piceance drilling alternatives Area Strategy MVCs working as designed Create cash flow stability and provide a long-term bridge to a more attractive drilling environment Numerous active customers representing avenues for accretive growth Minimal capital requirements given existing infrastructure and capacity Long-term call option on the Mancos / Niobrara Near-Term Outlook Recent upstream A&D activity has transferred acreage from public companies with large opportunity set to private companies with focused opportunity set Customers currently operating three rigs behind SMLP gathering system Stacked nature of play (Mancos, Niobrara and Codell) offer incremental opportunity for future growth

SMLP’s location in the core of the Barnett has enabled it to maintain relatively flat volumes despite strong headwinds elsewhere in the basin DFW Midstream – Outperforming Basin Trends Since 2013, volume throughput on SMLP’s Barnett system has declined by a 5.3% CAGR During that same period, production volumes elsewhere in the Barnett have declined by 12.8% Attractive drilling economics and customer diversity have resulted in a consistent level of rig activity throughout the commodity price downturn Source: Texas Railroad Commission. Barnett Volumes Barnett Segment Adjusted EBITDA SMLP Basin (5.3)% (12.8)% CAGR: 0 1,000 2,000 3,000 4,000 5,000 6,000 2013 2014 2015 YTD - 2016 MMcf/d Non-SMLP Barnett Volumes SMLP Barnett Volumes $69 $61 $60 $55 $0 $10 $20 $30 $40 $50 $60 $70 $80 2013 2014 2015 LTM $s in millions MMcf/d Non-Summit Barnett Production 2013 4,965 2016 YTD 3,521 CAGR (12.8%) SMLP Barnett Volumes 2013 391 2016 YTD 341 CAGR (5.3%)

Basin Positioning – Barnett Area Positioning, Strategy & Outlook Natural gas gathering in the “core of the core” of the Barnett Geographic Footprint Area Positioning & Strategy System fully built-out with minimal maintenance capex requirements Continuous improvement in the reservoir System throughput has outperformed underwriting case (i.e. MVC levels) Improving per well EUR trend: 2009: 2.8 Bcf 2011: 3.2 Bcf Current: 4.5 Bcf Attractive basis given proximity to Henry Hub Significant customer diversity, which has offset lower activity levels from SMLP’s anchor customer 10 customers, several of whom have limited non-Barnett drilling alternatives Near-Term Outlook Identified DUCs to be completed across DFW system in 2H 2016 Recent A&D to drive infill drilling activity in 2017 Significant upside potential relative to further upstream A&D activity Maintain volume throughput in 300-350 MMcf/d range

IV. Engineering, Construction & Operations Leonard Mallett, EVP & COO

EC&O Structure a shift to a flatter organization, leveraging top performers and centralizing key functions Leonard Mallett Executive Vice President & Chief Operations Officer Rick Smith Vice President, Operations West Dakota Lee Vice President, Operations East Ken Bussell Vice President, Operations Controls Pat Brierley Vice President, Engineering Brian Raber Vice President, Technical Service Area Manager West Area Manager East I&E Manager West Corrosion West Area Manager ND & Hereford Director DFW Area Director Utica I & E Manager East Corrosion East Director Enterprise Tech SOCC Principal Analyst Supervisor SCADA Project Execution Project Engineering Project Control Director Measurement Director Mechanical Director Maintenance Area Manager ND The EC&O Team has ~250 talented and dedicated employees EC&O Team Composition West Operations Technical Services Control Center Engineering East Operations Operators Technicians Controllers Engineers Operators Plant & Pipeline Measurement Mechanical Instrumentation Electrical Corrosion System Controllers SCADA Analyst Project Management Process Engineer Cost Management Plant and Pipeline

2016 EC&O Highlights Multi-disciplined teams developed to improve focus, communications and overall costumer service by dedicating resources to key assets Substantial improvements to measurement governance Increasing capture rates for produced water on the SMLP system (up 107% year-over-year) Safety No significant injuries, vehicle accidents or spills Recently passed PHMSA audit in North Dakota Cost Control Technical Services Asset Teams 2Q 2016 Controllable Opex per Mcfe was the lowest it has been at SMLP in the past two years Over 7% lower than 2Q 2015 Controllable Opex per Mcfe Every penny of operating cost savings per Mcfe equates to approximately $6 million per year (based on 2Q 2016 operating results) Leveraging technical talent across the system by creating a centralized Technical Services group to employ a common approach to maintenance and problem solving

Asset Teams – Purpose and Structure Maximizing use of technical talent across Summit Maximizing asset efficiency, thereby reducing costs Provides role clarity across Operations teams Creates accountability within each asset team Standardizes training across the platform in technical areas Promotes communications and coordination Operations Manager I&E Mechanical Measurement Commercial Maintenance Engineering

Summit Investments / SMLP have invested ~ $1 billion of organic capex since 2013 Ability to do Heavy Development ~ $160 million of organic capex since 2013 DeBeque Processing Plant (2013-2014) Holms Mesa CS Expansion (2015) Ursa Expansion (2015) 20 MMcf/d Hereford Processing Plant Expansion (2014-2016) Piceance/DJ ~ $530 million of organic capex since 2013 Divide Gathering (2013-2015) Goliath Gathering (2013-2015) ~ 95 Mbbl Crude Oil Tankage (2014-2015) Stampede Lateral (2014-2015) Polar Gathering Base System & Expansion (2013-2016) Williston ~ $175 million of organic capex since 2013 Approximately 45 miles of large diameter pipeline Buckeye Dehy Station (2015) Thatcher Dehy Station (2015) Sand Hills Dehy Station (2016) ~ $630 million of OGC capital calls since 2013 Utica ~ $40 million of organic capex since 2013 500 MMcf/d system capacity expansion (Zinnia Loop – 2014) Marcellus ~ $55 million of organic capex since 2013 Beacon Expansion (2013-2014) CO2 Treater (2014) Spinner Connector (2015) Barnett

Williston Basin – Liquids Assets Crude Oil Storage Tanks LACT Units

Williston Basin – Pipeline Construction

Piceance / DJ Basins Processing Plants DeBeque Processing Plant Hereford Processing Plant

Piceance / DJ Basins – Pipeline Construction

Utica Shale - Sand Hills Dehy Station Construction

Utica Shale - Sand Hills Dehy Station Construction

System Integrity – Keeping the System Healthy Maintain first class operations staff Mechanical maintenance program yielding 99% on compressor and pump availability Operate all our own compression Comprehensive Pigging Program – Gas and Oil lines cleaned to improve efficiency and product quality Aerial Surveillance – conducted at least every 2 weeks, no third party damage One Calls – conducted over 14,000 one call responses YTD, 25,000 projected Gas Imaging – minimizing emissions, finding and fixing small leaks Received state award for emissions program in Colorado Corrosion Control – monitoring and maintaining the internal and external walls of pipe, valves, vessels, etc.

SOCC - Best Management Practices Summit Operations Control Center (“SOCC”) SOCC is manned 24 hours a day, seven days a week, 365 days a year SOCC monitors operations across the Summit operated assets State of the art facility that meets DOT “control room” standards All controller operators are qualified per control room management (“CRM”) standards On-site power generator dedicated solely to the SOCC to mitigate any area power outages Back-up business continuity center located 28 miles from SOCC Assures that we are able to continuously monitor and control Summit’s operations and assets in the event of an emergency SOCC – 24 / 7 / 365 Monitoring Field Operators by Location 59 Field Ops 99 Field Ops 43 Field Ops 9 Field Ops 10 Field Ops Summit Operations Control Center

Key EC&O Takeaways Safety and Environmental compliance is Summit’s top priority Year to date we’ve done an excellent job of cost control Major projects are executed on time and on budget, meeting customer's needs Strong EC&O Team is in place, ready and focused on safety, efficiency and growth

V. Health, Safety, Environmental & Regulatory Affairs Brock Degeyter, EVP, General Counsel & Chief Compliance Officer

Summit’s dedication to health, safety, environmental and regulatory compliance is industry-leading within the midstream sector Currently employ 25 professionals with full-time focus on safety and compliance and an additional 8 field operator safety representatives (OSRs), which equates to 10% of its entire workforce devoted to regulatory compliance Field-based OSRs are responsible for implementing Summit’s core safety principles in each of our geographical area Compliance Training & Contractor Safety Manager Eastern Health & Safety Manager Western Health & Safety Manager Pipeline Compliance Manager Integrity Manager Mountaineer/Utica Safety Specialist GRG Sr. Health & Safety Specialist GIS Technician GIS Technician GRG/RRG/Hereford Health & Safety Specialist Polar/Divide/Bison Health & Safety Specialist Brock Degeyter Executive Vice President , General Counsel & Chief Compliance Officer Zachary Covar VP Health, Safety, Environmental & Regulatory Affairs Director of Health, Safety & Regulatory Affairs HSER—Fully Developed Team of Qualified Professionals Director of Environmental & Permitting RRG & Bison Env Compliance Specialist GRG & Polar Env Compliance Specialist DFW, Utica, MTN, NIO Env Compliance Specialist WBU Permitting Permit Manager EBU Permitting Permit and Regulatory Manager SMLP Air Quality Specialist ND Environmental Remediation Manager

Safety Culture: 9 Core Safety Principles Each of Summit’s employees and contractors is responsible for adhering to our 9 Core Safety Principles

Safety Culture: Enterprise-Wide Commitment Employee Safety: Safety Meetings are held (at least) monthly in each regional office and are led by our local safety representatives A member of the HSER management team attends the field safety meetings as a means of reinforcing Summit’s corporate commitment to building safety culture HSER management, operations management, field safety representatives and OSRs meet quarterly to review safety culture surveys Safety manager holds weekly incident review meetings that drive the agendas of the monthly safety meetings, addressing trending safety issues Safety metric performance and safety-culture surveys are a component of every Summit employee's annual review and compensation matrix Summit’s Total Recordable Incident Rate (“TRIR”) is markedly lower than the industry average (1.85 vs 2.0) Contractor Safety: Responsible Contractor Management Program ISNET & “Responsible Contractor” Certification Summit is also a member of a Field Auditing Network (FAN), which allows Summit to systematically evaluate the effectiveness of certain of its contractors’ safety programs and leverage industry-leading safety management practices Comprised of 14 large Up-Mid-Downstream companies FAN members perform hundreds of contractor (subcontractor) audits each year

VI. Financial Overview Matt Harrison, EVP & CFO

Growing and Diversifying SMLP’s Business Represents reportable segment Adjusted EBITDA Based on historical average daily volume on an Mcfe basis; Assumes oil and water are converted at a 6:1 Mcf to barrel ratio Key Observations Large and Diversified Customer Base Exposure to Multiple Basins(1) Diversified Across Commodity(2) SMLP has continued to grow and diversify its business across multiple facets Generated EBITDA growth of 22% per year since 2013, diversifying across several basins With the expansion into North Dakota during 2013, Summit successfully diversified into oil and water gathering services Summit has an established, large and diversified customer base across its footprint 2013 – 6/30/2016 CAGR: 22% 4% 10% 40% 46% 7% 27% 3% 50% 13% 9% 23% 14% 42% 23% 7% 19% 20% 37% 17% 2016 Average % Gas Volumes: 74% Piceance / DJ Basins Utica Shale Barnett Shale Williston Basin Marcellus Shale Large U.S. Independent Producer 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 % of Total Volumes % Gas % Liquids $173 $223 $263 $286 $0 $50 $100 $150 $200 $250 $300 2013 2014 2015 LTM Segment Adjusted EBITDA

Conservative Financial Strategy Strong balance sheet and liquidity enables SMLP to execute its growth strategy Targeting long-term leverage ratio of 3.5x – 4.0x $529 million of borrowing availability at June 30, 2016 under $1.25 billion revolver 2Q 2016 distribution of $0.575 per unit Distribution coverage ratio of 1.25x for 2Q 2016 Moody’s Corporate Family Rating of B1 (Stable Outlook); rating affirmed on June 17, 2016 S&P Corporate Family Rating of B+ (Stable Outlook); rating affirmed on February 26, 2016 Revolving Credit Facility 7.50% Senior Notes B/B2 5.50% Senior Notes B/B2 Long-Term Debt Maturities $529 million of availability at 6/30/16 under $1.25 billion revolver Actual ($s in millions) Jun-16 Cash and Cash Equivalents $7 Total Debt: Revolving Credit Facility (Due Nov. 2018) $721 7.50% Senior Notes (Due July 2021) 300 5.50% Senior Notes (Due August 2022) 300 Capital Leases 1 Total Debt $1,322 Partners' Capital: Common Limited Partner Capital $1,074 General Partner Interests 28 Noncontrolling interest 11 Total Partners' Capital $1,113 Total Capitalization $2,435 Distribution Coverage Ratio (Quarterly) 1.25x Covenant Compliance EBITDA (LTM) $292 Credit Metrics Debt / EBITDA 4.5x Debt / Total Capitalization 54.3% Committed Liquidity Cash & Cash Equivalents $7 Revolver Availability 529 Total Liquidity $536 $721 $300 $300 $529 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2016 2017 2018 2019 2020 2021 2022 $ in Millions

Proven Track Record of Growth, Diversification and Scalability Consistent Ratings Despite Improved Scale and Diversification (1) Market Statistic for historical periods as of 12/31 each year. (2) Current Adjusted EBITDA reflects the mid-point of 2016 guidance. Market capitalization as of 8/5/2016. While credit ratings remained unchanged (1) (2) $163 $208 $235 $280 $433 $518 $375 $536 $1,066 $1,308 $788 $1,502 2013 2014 2015 Current Adjusted EBITDA Liquidity Market capitalization / B- Caa1 / CCC+ Baa1 BBB+ / Baa2 / BBB Baa3 / BBB- Ba1 / BB+ Ba2 / BB Ba3 / BB- B1 / B+ B2 / B B3 / B- Caa1 / CCC+ Baa1 BBB+ / Baa2 / BBB Baa3 / BBB- Ba1 / BB+ Ba2 / BB Ba3 / BB- B1 / B+ B2 / B B3 / B- Caa1 / CCC+ Baa1 BBB+ / Baa2 / BBB Baa3 / BBB- Ba1 / BB+ Ba2 / BB Ba3 / BB- B1 / B+ B2 / B B3 / B- Caa1 / CCC+ Baa1 BBB+ / Baa2 / BBB Baa3 / BBB- Ba1 / BB+ Ba2 / BB Ba3 / BB- B1 / B+ B2 / B B3

1H 2016 Financial Review Adjusted EBITDA(1,2) Capital Expenditures(1) Adjusted Distributable Cash Flow Volume Gathered Excludes acquisition capital expenditures. Includes contributions to equity method investees. EBITDA adjustments include adjustments related to MVC shortfall payments and unit-based compensation expense. Adjusted EBITDA includes transaction costs. These unusual and non-recurring expenses are settled in cash. For a reconciliation of adjusted EBITDA and adjusted distributable cash flow to their nearest comparable GAAP financial measures, please see “Non-GAAP Reconciliations.” Mbbl/d $123 $148 $166 $104 $0 $30 $60 $90 $120 $150 $180 2013 2014 2015 1H 2016 $MM $163 $208 $235 $142 $0 $40 $80 $120 $160 $200 $240 2013 2014 2015 1H 2016 $MM $250 $879 $358 $107 $0 $200 $400 $600 $800 $1,000 2013 2014 2015 1H 2016 $MM 1,139 1,423 1,498 1,518 11 41 68 91 0 20 40 60 80 100 0 400 800 1,200 1,600 2013 2014 2015 1H 2016 MMcf/d Gas (MMcf/d) Liquids (Mbbl/d)

Financing the Deferred Payment The 2016 Drop Down structure allows SMLP to “pick its spots” to finance the Deferred Payment Ability to opportunistically access the debt and equity capital markets with proceeds used to prepare the balance sheet for the Deferred Payment in 2020 SMLP intends to structure the consideration mix of debt and equity to target the following pro forma metrics: 4.0x leverage 1.10x – 1.20x distribution coverage While the Deferred Payment structure reduces SMLP’s financing risk, by providing additional time and optionality to pre-fund, it does not eliminate the risk entirely The financing and capital markets risks are further mitigated given that the Deferred Payment may include equity issued directly to the GP for up to 100% of the consideration

2016 Financial Guidance Guidance Range FY 2016 ($ in millions) Low High Adjusted EBITDA $270.0 $290.0 Distribution Coverage 1.15x 1.25x Growth Capex $135.0 $180.0 Maintenance Capex $15.0 $20.0 Total Capex $150.0 $200.0 SMLP will take a measured approach with regard to DPU growth in 2016. In the near-term, SMLP intends to focus on building distribution coverage and strengthening its balance sheet

VII. Investment Considerations – Why Own SMLP Marc Stratton, Senior Vice President & Treasurer

SMLP Units Poised to Benefit From a Continued Market Rebound Historical AMZ Distribution Yield and Long-Term Treasury Yields Historical SMLP and AMZ Distribution Yields 10.2% 7.1% 3.1% Current AMZ Yield (1) SMLP Yield Spread Spread Range (2) Avg. Spread Average Spread Since SMLP IPO: 0.9% 7.1% 1.5% 5.6% Current 10-Year U.S. Treasury Yield AMZ Yield (1) Spread Spread Range (2) Avg. Spread Average Spread Since SMLP IPO: 4.3% Broader MLP market, as defined by the AMZ, continues to trade at significantly elevated spreads relative to long-term treasury yields SMLP continues to trade at significantly elevated spreads relative to long-term AMZ yields SMLP is well position for a continued “reversion to the mean,” both from a broader market and relative valuation perspective Source: U.S. Treasury, Alerian MLP Index and SNL Financial. Data for the Alerian MLP index only available through 7/29/2016 per the Alerian MLP Index website. Range based on one standard deviation above and below the long term average spread. 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Yield / Spread to Long - Term Treasury -5.00% 0.00% 5.00% 10.00% 15.00% 20.00% Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Distribution Yield / Spread to AMZ

Below Median “Attractive Price” Relative to Selected G&P MLPs Source: SNL Financial and Wall Street equity research; Market data as of 8/5/2016. Peers include: AM, AMID, CEQP, CNNX, DPM, ENLK, ENBL, RMP, PTXP and WES. Includes sub-set of selected G&P peers – Includes peers 2, 3 and 4. Distribution growth based on consensus estimates for 2016E to 2020E CAGR. Date based on period of consistent yield information available for sub-set of selected G&P peers. Historical SMLP and G&P(1) Distr. Yields (7) Adjusted Total Enterprise Value (“TEV”) (6) Distribution Yield and Growth (2) Adj. TEV / 2016E EBITDA Above Median Below Median Above Median 2016E Coverage(5): 1.44x 1.71x 1.37x 1.23x 1.32x 1.07x 1.14x 1.17x 1.20x 1.70x (7) Below Median Above Median 10.2% 9.3% 0.9% Current Selected G&P Peer Avg. Yield (1) SMLP Yield Spread Spread Range (4) Avg. Spread Average Spread Since 7/25/2014(3): (0.1)% (4) Range based on one standard deviation above and below the long term average spread. (5) Distribution coverage represents 2016E distribution coverage per consensus estimates. (6) Adjusted TEV includes estimated GP value based on the GP cash flow and LP distribution yield. (7) SMLP adjusted TEV includes an adjustment for the deferred payment based on current 2016E EBITDA contribution of the Drop Down assets. 1.54x 15.9x 14.1x 14.0x 12.7x 12.2x 12.1x 11.6x 11.3x 11.0x 10.6x 8.2x 6.0x 8.0x 10.0x 12.0x 14.0x 16.0x 18.0x Peer 5 Peer 1 Peer 2 Peer 7 Peer 4 Peer 10 Peer 3 Peer 9 SMLP Peer 8 Peer 6 Adjusted TEV / 2016E EBITDA $13.6 $11.0 $9.0 $7.6 $5.5 $3.6 $3.1 $1.7 $1.3 $1.1 $0.8 $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 $16.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 SMLP Peer 7 Peer 8 Peer 9 Peer 10 Adjusted TEV 3.7% 4.3% 5.9% 6.7% 7.5% 9.1% 9.2% 9.7% 10.2% 11.4% 13.8% 18% 18% 11% 11% 10% 0% 0% 2% 4% 9% 1% 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% 18.0% 20.0% Peer 5 Peer 7 Peer 9 Peer 1 Peer 10 Peer 2 Peer 4 Peer 3 SMLP Peer 6 Peer 8 Current Yield -8.0% -3.0% 2.0% 7.0% 12.0% 17.0% 22.0% Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Distribution Yield / Spread to Selected G&P Peers

98% of revenue is fee-based 3.4 Tcfe of remaining MVCs through 2026 provide downside protection Provides for stable cash flow and limited direct commodity price exposure Fee-Based Contract Portfolio SMLP – Key Takeaways Visible cash flow growth a function of SMLP’s contract portfolio, diversified operations and capital position 2016 Drop Down provides SMLP with scale and further diversification by basin, commodity, customer and service Positions SMLP in the core of the Utica with assets that are at the beginning of their development lifecycle, providing SMLP the opportunity to participate in the growth of the basin Provides SMLP with the opportunity to pursue additional development projects in the Utica across the condensate, liquids-rich and dry gas windows 2016 Drop Down Assets bring $400 - $500 million of visible growth capex through 2019 Visible Organic Growth From Drop Down Assets Allows SMLP to “pick its spots” to finance the Deferred Payment Ensures SMLP only pays a 6.5x multiple on the actual 2018 / 2019 average EBITDA of the assets The GP retains the development and performance risk of the assets during the deferral period Drop Down Offers Structural Benefits & Protections Strong Capital Position 2Q 2016 distribution coverage ratio of 1.25x 4.50x leverage ratio as of June 30, 2016 $529 million of revolver borrowing capacity as of June 30, 2016

NYSE: SMLP www.summitmidstream.com

VIII. Appendix: Non-GAAP Reconciliations

2Q 2016 MVC Shortfall Payments ($s in 000s) MVC Billings Gathering Revenue Adjustments to MVC Shortfall Payments Net Impact to Adjusted EBITDA Net change in deferred revenue related to MVC shortfall payments: Utica Shale - - - - Williston Basin - - - - Piceance/DJ Basins 3,999 2,762 1,237 3,999 Barnett Shale - 677 (677) - Marcellus Shale - - - - Total net change $3,999 $3,439 $560 $3,999 MVC shortfall payment adjustments: Utica Shale - - - - Williston Basin - - 4,261 4,261 Piceance/DJ Basins 281 281 6,219 6,500 Barnett Shale 244 244 95 339 Marcellus Shale 923 923 - 923 Total MVC shortfall payment adjustments $1,448 $1,448 $10,575 $12,023 Total $5,447 $4,887 $11,135 $16,022 ($s in 000s) MVC Billings Gathering Revenue Adjustments to MVC Shortfall Payments Net Impact to Adjusted EBITDA Net change in deferred revenue related to MVC shortfall payments: Utica Shale - - - - Williston Basin 235 - 235 235 Piceance/DJ Basins 7,959 5,484 2,475 7,959 Barnett Shale - 677 (677) - Marcellus Shale - - - - Total net change $8,194 $6,161 $2,033 $8,194 MVC shortfall payment adjustments: Utica Shale - - - - Williston Basin - - 7,562 7,562 Piceance/DJ Basins 565 565 12,498 13,063 Barnett Shale 508 508 184 692 Marcellus Shale 1,719 1,719 - 1,719 Total MVC shortfall payment adjustments $2,792 $2,792 $20,244 $23,036 Total $10,986 $8,953 $22,277 $31,230 Three Months Ended June 30, 2016 Six Months Ended June 30, 2016

Non-GAAP Reconciliations Includes amortization of favorable and unfavorable gas gathering contracts reported in other revenues. Reflects our proportionate share of Ohio Gathering Adjusted EBITDA, based on a one-month lag. Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments, and (ii) our inclusion of future expected annual MVC shortfall payments. In connection with the decline in commodity prices during the fourth quarter of 2014, we reevaluated the carrying value, including goodwill, of the Bison Midstream gathering system and recognized a goodwill impairment for the decline in the fair value of the underlying reporting unit relative to its carrying value. Includes $203.4 million impairment for Polar & Divide in 2015 and $45.5 million for Grand River in 2015. Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on the $300.0 million 5.5% senior notes is paid in cash semi-annually in arrears on February 15 and August 15 until maturity in August 2022. Interest on the $300.0 million 7.5% senior notes is paid in cash semi-annually in arrears on January 1 and July 1 until maturity in July 2021. Year Ended December 31, ($s in 000s) 2016 2015 2015 2014 2013 Net Income (Loss) ($50,555) ($2,396) ($222,228) ($47,368) $47,008 Add: Interest expense 16,035 15,599 59,092 48,586 21,314 Income tax expense 360 - - 854 729 Depreciation and amortization (1) 28,092 26,231 105,903 91,822 72,264 Less: Interest income - 1 2 4 5 Income tax benefit - 263 603 - - EBITDA ($6,068) $39,171 ($57,838) $93,890 $141,310 Add: Proportional adjusted EBITDA for equity method investees (2) 12,725 6,552 33,667 6,006 - Adjustments related to MVC shortfall payments (3) 11,135 10,935 (11,902) 26,565 17,025 Unit-based and noncash compensation 1,994 1,988 7,017 5,841 4,242 Deferred purchase price obligation expense 17,465 - - - - Loss on asset sales 74 24 42 442 113 Long-lived asset impairment 569 - 9,305 5,505 - Goodwill impairment (4) - - 248,851 54,199 - Less: Income (loss) from equity method investees (34,471) (3,486) (6,563) (16,712) - Gain on asset sales - 238 214 - - Impact of purchase price adjustment - - - 1,185 - Adjusted EBITDA $72,365 $61,918 $235,491 $207,975 $162,690 Add: Cash interest received - - 2 4 5 Cash taxes received - - - - - Less: Cash interest paid 6,300 4,867 59,302 38,453 13,170 Senior notes interest adjustment (5) 9,750 9,750 (1,421) 6,733 12,125 Cash taxes paid - - - - 660 Maintenance capital expenditures 5,291 2,444 12,681 18,082 16,129 Distributable cash flow $51,024 $44,857 $164,931 $144,711 $120,611 Three Months Ended June 30,

Reconciliation of EBITDA to Adjusted Distributable Cash Flow Reflects our proportionate share of Ohio Gathering adjusted EBITDA, based on a one-month lag. Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments, and (ii) our inclusion of future expected annual MVC shortfall payments. Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on the $300.0 million 5.5% senior notes is paid in cash semi-annually in arrears on February 15 and August 15 until maturity in August 2022. Interest on the $300.0 million 7.5% senior notes is paid in cash semi-annually in arrears on January 1 and July 1 until maturity in July 2021. Three Months Ended June 30, Variance ($s in 000s) 2016 2015 $ % Adjusted Distributable Cash Flow: EBITDA ($6,068) $39,171 ($45,239) (115%) Add: Proportional adjusted EBITDA for equity method investees (1) 12,725 6,552 6,173 94% Adjustments related to MVC shortfall payments (2) 11,135 10,935 200 2% Unit-based and noncash compensation 1,994 1,988 6 0% Deferred purchase price obligation expense 17,465 - 17,465 n/a Loss on asset sales 77 24 53 221% Long-lived asset impairment 569 - 569 n/a Less: Income (loss) from equity method investees (34,471) (3,486) (30,985) 889% Gain on asset sales 3 238 Adjusted EBITDA $72,365 $61,918 $10,447 17% Add: Cash interest received - 1 (1) (100%) Less: Cash interest paid 6,300 4,867 1,433 29% Senior notes interest adjustment (3) 9,750 9,750 - 0% Maintenance capital expenditures 5,291 2,444 2,847 116% Distributable cash flow $51,024 $44,857 $6,167 14% Add: Transaction costs 122 822 (700) (85%) Adjusted distributable cash flow $51,146 $45,679 $5,467 12% Distributions declared $41,045 $40,479 $566 1% Distribution coverage ratio 1.25x *