Third Coast Midstream (AMID) SC 13E3 Going private transaction

Exhibit (c)(11)

Discussion Materials Prepared for The Conflicts Committee of the Board of Directors of American Midstream GP, LLC March 16, 2019 These materials have been prepared by Evercore Group L.L.C. (“Evercore”) for the Conflicts Committee of the Board of Directors of American Midstream GP, LLC (the “Conflicts Committee”), the general partner of American Midstream Partners, L.P., to whom such materials are directly addressed and delivered and may not be used or relied upon for any purpose other than as specifically contemplated by a written agreement with Evercore. These materials are based on information provided by or on behalf of the Conflicts Committee, from public sources or otherwise reviewed by Evercore. Evercore assumes no responsibility for independent investigation or verification of such information and has relied on such information being complete and accurate in all material respects. To the extent such information includes estimates and forecasts of future financial performance prepared by or reviewed with the management of the Partnership and/or other potential transaction participants or obtained from public sources, Evercore has assumed that such estimates and forecasts have been reasonably prepared on bases reflecting the best currently available estimates and judgments of such management (or, with respect to estimates and forecasts obtained from public sources, represent reasonable estimates). No representation or warranty, express or implied, is made as to the accuracy or completeness of such information and nothing contained herein is, or shall be relied upon as, a representation, whether as to the past, the present or the future. These materials were designed for use by specific persons familiar with the business and affairs of the Partnership. These materials are not intended to provide the sole basis for evaluating, and should not be considered a recommendation with respect to, any transaction or other matter. These materials have been developed by and are proprietary to Evercore and were prepared for the benefit and internal use of the Conflicts Committee. These materials were compiled on a confidential basis for use by the Conflicts Committee and not with a view to public disclosure or filing thereof under state or federal securities laws, and may not be reproduced, disseminated, quoted or referred to, in whole or in part, without the prior written consent of Evercore. These materials do not constitute an offer or solicitation to sell or purchase any securities and are not a commitment by Evercore or any of its affiliates to provide or arrange any financing for any transaction or to purchase any security in connection therewith. Evercore assumes no obligation to update or otherwise revise these materials. These materials may not reflect information known to other professionals in other business areas of Evercore and its affiliates. Evercore and its affiliates do not provide legal, accounting or tax advice. Accordingly, any statements contained herein as to tax matters were neither written nor intended by Evercore or its affiliates to be used and cannot be used by any taxpayer for the purpose of avoiding tax penalties that may be imposed on such taxpayer. Each person should seek legal, accounting and tax advice based on his, her or its particular circumstances from independent advisors regarding the impact of the transactions or matters described herein.

Table of Contents Section Executive Summary I Situation Analysis II Asset Overview III AMID Financial Projections IV Preliminary Valuation V A. Preliminary Valuation of Natural Gas Gathering & Processing B. Preliminary Valuation of Natural Gas Transportation C. Preliminary Valuation of Offshore Pipelines (Excl. Delta House) D. Preliminary Valuation of Delta House E. Preliminary Valuation of Bakken Crude Oil Gathering F. Preliminary Valuation of Silver Dollar Pipeline G. Preliminary Valuation of Cushing Terminal H. Preliminary Valuation of NGL JV Interests I. Preliminary Valuation of AMID Corporate G&A Expenses Illustrative AMID Unitholder Tax Analysis VI Appendix A. Weighted Average Cost of Capital B. Detailed Segment Financial Projections I. Executive Summary

Executive Summary Introduction ? Evercore Group L.L.C. (“Evercore”) is pleased to provide the materials herein to the Conflicts Committee (the “Conflicts Committee”) of the Board of Directors of American Midstream GP, LLC (the “General Partner”), the general partner of American Midstream Partners, LP (“AMID” or the “Partnership”), regarding the proposed acquisition by the General Partner, a subsidiary of ArcLight Energy Partners Fund V, L.P. (“ArcLight”), of all common units representing limited partner interests in AMID (each, a “Common Unit”) from the holders of such units other than Common Units held by ArcLight, the General Partner or their respective affiliates (the “Merger”) ? ArcLight currently owns 40,774,080 Common Units on an as-converted basis1 (51.3% of the total outstanding Common Units2) and ArcLight owns the 1.2% general partner interest and incentive distribution rights in AMID through the General Partner, ArcLight’s subsidiary ? In its September 27, 2018 offer letter (the “Initial Proposal”), ArcLight proposed to acquire each outstanding publicly-held Common Unit for $6.10 in cash (the “Initial Offer”) ? In its January 2, 2019 offer letter (the “Second Proposal”), ArcLight proposed to acquire each outstanding publicly-held Common Unit for $4.50 in cash (the “Second Proposal Consideration”) ? On February 1, 2019, ArcLight revised its offer proposing to acquire each outstanding publicly-held Common Unit for $4.85 in cash (the “Third Proposal Consideration”) ? On February 18, 2019, the Conflicts Committee and ArcLight reached an understanding for ArcLight to acquire each outstanding publicly-held Common Unit for $5.25 in cash (the “Consideration”) • The Consideration represents a 66.7% premium to AMID’s closing unit price as of January 3, 2019 prior to the announcement of the Second Proposal and a 31.3% premium to AMID’s closing unit price as of March 15, 2019 ? The Merger, pursuant to the Agreement and Plan of Merger by and among Anchor Midstream Acquisition, LLC, Anchor Midstream Merger Sub, LLC (“Merger Sub”), High Point Infrastructure Partners, LLC, the Partnership and the General Partner (the “Merger Agreement”), is to be structured as a merger between the Partnership and Merger Sub LLC with the Partnership surviving the merger, and requires approval by the Conflicts Committee, the ArcLight Investment Committee and the holders of a majority of the outstanding Common Units on an as-converted basis Source: Public filings 1. Represents 7,940,322 Series A-1 Convertible Preferred Units (“Series A-1 Units”) held by High Point Infrastructure Partners, LLC (“High Point”), convertible into 10,172,347 common units of AMID (“Common Units”), which are indirectly owned by Magnolia Infrastructure Partners, LLC (“Magnolia”), 3,401,875 Series A-2 Convertible Preferred Units (“Series A-2 Units”) held by Magnolia, convertible into 4,358,142 Common Units, 9,514,330 Series C Convertible Preferred Units (“Series C Units”) held by Magnolia Infrastructure Holdings, LLC (“Magnolia Holdings”), convertible into 9,527,650 Common Units, 1,329,987 Common Units issuable upon exercise of the warrant issued to Magnolia Holdings by American Midstream Partners, LP, dated April 25, 2016, 10,563,942 Common Units held by Magnolia Holdings, 1,349,609 Common Units held by American Midstream GP, LLC, which is approximately 77% owned by High Point and approximately 23% owned by AMID GP Holdings, LLC, which is approximately 93% owned by Magnolia Holdings, 618,921 Common Units held by Magnolia and 2,853,482 Common Units held by Busbar II, LLC, an affiliate of ArcLight 2. Assumes inclusion of the units issuable upon exercise of the warrant issued to Magnolia Holdings dated April 25, 2016; exclusion of these units results in adjusted ownership on an as-converted basis of 51.1% 1 Executive Summary Overview of Materials ? The materials herein include: ? An executive summary, including an overview of the Merger detailing summary proposed terms, an overview of AMID’s current summary organizational structure and an analysis of financial metrics implied by the Merger ? An overview of AMID’s current market situation ? An overview of AMID’s assets by business segment ? A review of the financial projections for AMID as provided by AMID management (the “AMID Financial Projections”) and a review of the assumptions utilized by AMID management in deriving such financial projections ? A preliminary valuation of AMID ? An illustrative review of the potential cash tax impact to unaffiliated unitholders resulting from the Merger 2

Executive Summary Overview of the Merger Evercore has been asked by the Conflicts Committee, whether, in Evercore’s opinion, as of the date of the Opinion opinion, the Consideration is fair, from a financial point of view, to the unaffiliated common unitholders of Requested: the Partnership ? American Midstream Partners, LP Counterparties ? American Midstream GP, LLC, a subsidiary of ArcLight Energy Partners Fund V, L.P. and the general partner of American Midstream Partners, LP ? ArcLight to acquire all publicly-owned Common Units from the holders of such units other than Merger Common Units held by ArcLight, the General Partner or their respective affiliates Summary ? AMID will cease to be a publicly-traded partnership ? Common Unit holders other than ArcLight, the General Partner and their respective affiliates Consideration (“Unaffiliated Unitholders”) will receive $5.25 in cash for each AMID common unit held ? Approval of the Conflicts Committee ? Requires approval from 50.0% of Common Unit unitholders on an as-converted basis (affiliates of Timing and Approvals ArcLight currently own 51.3% of LP units on an as-converted basis) ? HSR approval ? The Merger is expected to close in Q2 2019 assuming all required approvals are obtained Other ? The Merger is structured to be taxable to the Unaffiliated Unitholders 3 Executive Summary Current Summary AMID Partnership Structure As-Converted % of % of Entity Common Units LP Units Total Units ArcLight Energy Partners Fund V, LP ArcLight Energy Partners Fund V, LP1 2,853,482 3.6% 3.5% 2,853,482 Common Units1 Magnolia Infrastructure Holdings, LLC 21,421,579 27.0% 26.6% Magnolia Infrastructure Partners, LLC 4,977,063 6.3% 6.2% High Point Infrastructure Partners, LLC 10,172,347 12.8% 12.6% Magnolia Infrastructure Holdings, LLC American Midstream GP, LLC 1,349,609 1.7% 1.7% 10,563,942 Common Units ArcLight and Affiliate-Owned LP Units 40,774,080 51.3% 50.7% 9,514,330 Series C Units representing 9,527,650 Common Units American Midstream GP, LLC (GP Units) 980,889 1.2% 1,329,987 Common Units issuable upon exercise of warrant2 ArcLight and Affiliate-Owned Units 41,754,969 51.9% 93.0% Magnolia Infrastructure Partners, LLC Public 618,921 Common Units 3,401,875 Series A-2 Units representing 4,358,142 Common Units AMID GP Holdings, LLC Unitholders 38,664,860 High Point Infrastructure Partners, LLC3 Common Units 7,940,322 Series A-1 Units representing 10,172,347 Common Units 48.7% LP Interest 77.0% 23.0% American Midstream GP, LLC 1,349,609 Common Units 1.2% GP Interest, 1.7% LP Interest and 100% of IDRs 12.8% LP Interest American Midstream Partners, LP (“AMID”) 6.3% LP Interest Market Capitalization: $220.1 MM4 Preferred Equity: $324.6 MM5 Net Debt as of 12/31/2018: $1,014.6 MM5 27.0% LP Interest 100% Ownership American Midstream, LLC 100% Ownership 3.6% LP Interest Direct and Indirect Wholly- Source: Public filings, AMID management Owned Subsidiaries Note: Units outstanding provided by AMID management on March 14, 2019 1. Common units owned by Busbar II, LLC, a wholly-owned direct subsidiary of ArcLight Energy Partners Fund V, LP 2. Warrant issued to Magnolia Holdings by AMID dated April 25, 2016 3. High Point Infrastructure Partners, LLC is a portfolio company of ArcLight Capital Partners, LLC 4. Pricing as of March 15, 2019 5. Book value based on Preliminary December 31, 2018 balance sheet as provided by AMID management 4

Executive Summary Merger Analysis ($ in millions, except per unit amounts) Proposed Consideration $5.25 LP Units Outstanding1 (MM) 55.4 AMID LP Equity Value $290.9 Plus: AMID Net Debt2 1,132.4 Plus: Liquidation Value of Series A-1 Convertible Preferred Units 3 142.3 Plus: Liquidation Value of Series A-2 Convertible Preferred Units 4 60.9 Plus: Liquidation Value of Series C Convertible Preferred Units 5 137.2 Transaction Value $1,763.8 Premium Metric Unit Price as of September 27, 2018 (Unaffected Price prior to Initial Proposal) $5.75 (9%) 10-Day VWAP 5.99 (12%) 30-Day VWAP 6.28 (16%) 60-Day VWAP 6.91 (24%) Unit Price as of January 3, 2019 (Unaffected Price prior to Second Proposal) 3.15 67% 10-Day VWAP 3.85 36% 30-Day VWAP 4.31 22% 60-Day VWAP 5.01 5% Unit Price as of March 15, 2019 4.00 31% 10-Day VWAP 3.94 33% 30-Day VWAP 3.98 32% 60-Day VWAP 3.97 32% Transaction Value / 2018A EBITDA6 $159.1 11.1x (Transaction Value + 2019E Growth Capital Expenditures + Acquisitions) / 2019E EBITDA6 194.7 10.4 Price / DCF per LP Unit 2018A6 $0.70 7.5x 2019E 1.20 4.4 Source: AMID management, public filings, Bloomberg 1. As of June 30, 2019 and includes 980,889 general partner units and 381,149 LTIP units issued from March 2019 to June 2019 2. Net debt as of June 30, 2019 3. 7,940,322 Series A-1 convertible preferred units multiplied by the liquidation value of $17.50 per unit (adjusted for accrued 1Q19 and 2Q19 distributions and accrued interest on 1Q19 distribution) 4. 3,401,875 Series A-2 convertible preferred units multiplied by the liquidation value of $17.50 per unit (adjusted for accrued 1Q19 and 2Q19 distributions and accrued interest on 1Q19 distribution) 5. 9,514,330 Series C convertible preferred units multiplied by the liquidation value of $14.00 per unit (adjusted for accrued 1Q19 and 2Q19 distributions and accrued interest on 1Q19 distribution) 6. Pro forma for sale of refined product terminals to Sunoco LP 5 Executive Summary Evercore Evaluation Process ? In connection with its review of the Merger, Evercore has, among other things: ? Reviewed certain publicly available historical operating and financial information relating to the Partnership that we deemed relevant, including as set forth in the Partnership’s Annual Reports on Form 10-K for the year ended December 31, 2017, the Partnership’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2018, June 30, 2018 and September 30, 2018, and certain of the Partnership’s Current Reports on Form 8-K, in each case as filed with or furnished to the U.S. Securities and Exchange Commission by the Partnership since January 1, 2018; ? Reviewed certain non-public historical and projected financial and operating data and assumptions relating to the Partnership, as prepared and furnished to us by management of the Partnership; ? Discussed the past and current operations and current financial condition of the Partnership, and the historical and projected financial and operating data and assumptions relating to the Partnership, with management of the Partnership (including management’s views of the risks and uncertainties of achieving such projections); ? Reviewed publicly available research analyst estimates for the Partnership’s future financial performance on a standalone basis; ? Performed discounted cash flow analyses for the Partnership based on projected financial data and other data provided by management of the Partnership; ? Compared the financial performance of the Partnership and its stock market trading multiples with those of certain other publicly traded partnerships and companies that we deemed relevant; ? Compared the financial performance of the Partnership and the transaction multiples implied by the Merger with the financial terms and transaction multiples of certain historical transactions that we deemed relevant; ? Reviewed a draft of the Merger Agreement dated March 15, 2019; and ? Performed such other analyses and examinations, held such other discussions, reviewed such other information and considered such other factors that we deemed appropriate 6

II. Situation Analysis Situation Analysis Summary Market Data ($ in millions, except per unit amounts) Market Capitalization Balance Sheet and Credit Data As of March 15, 2019 As of December 31, 2018 Total Units Outstanding1 55.0 Cash and Marketable Securities $9.1 Common Unit Price $4.00 Short-Term Debt 523.0 Total Equity Value $220.1 Long-Term Debt 500.7 Plus: Preferred Equity2 324.6 Total Debt $1,023.7 Plus: Net Debt 1,014.6 Net Debt $1,014.6 Plus: Noncontrolling Interest 13.8 Plus: Noncontrolling Interest 13.8 Enterprise Value $1,573.2 Plus: Preferred Equity2 324.6 Plus: Partners’ Capital 105.5 FactSet Consensus AMID Financial Projections3 Net Book Capitalization $1,458.5 Metric Yield/Multiple Metric Yield/Multiple Distribution Yield Revolver Availability / Total Revolver Capacity $66.1 / $620.0 Current $— —% $— —% Net Debt / Net Book Cap 69.6% 2019E — —% — —% Net Debt / 2018A EBITDA 6.4x 2020E — —% — —% Net Debt / 2019E EBITDA 5.2 EV/EBITDA 2018 $186.2 8.4x $159.1 9.8x Current Ratings (Senior Unsecured): 2019E 178.7 8.8 194.7 8.0 Moody’s Caa2 2020E 187.2 8.4 214.1 7.3 S&P B Unit Price Performance General Partner Incentive Distribution Rights Quarterly Total Total Total Total $20.00 $2.50 Distr LP Quarterly Quarterly Distribution Total Quarterly Quarterly Annual Annual Distribution Distribution to GP LP Units Distribution Distribution Distribution Distribution $2.00 % to LP % to GP Range Within Range per LP Unit Outstanding to LPs to GP to LPs to GP e $15.00 bution i 98.7% 1.3% $— $0.4125 $— $— 54.1 $— $— $— $—50.7% 49.3% 0.4125 0.4125 — — 54.1 — — — — i c $1.50 50.7% 49.3% 0.4125 0.4125 — — 54.1 — — — —P r $10.00 50.7% 49.3% 0.4125 — — 54.1 — — — — $— $— $— $— Unit $1.00 $4.00 pe r % of Total Distributions to the GP NM $5.00 $0.50 Unit % of Total Distributions to the IDRs NM $— $—3/15/17 8/8/17 1/1/18 5/27/18 10/20/18 3/15/19 Distribution per Unit Unit Price Source: Company filings, AMID management and FactSet Note: Market data as of March 15, 2019 1. Includes 980,889 general partner units 2. Book value of preferred based on Preliminary December 31, 2018 balance sheet as provided by AMID management 3. AMID Financial Projections presented net of earnings attributable to non-controlling interests (“NCI”); multiples reflect Enterprise Value excluding NCI 7

Situation Analysis Summary Market Data (cont’d) AMID 8.5% Senior Notes due 2021 Trading Price / AMID Unit Price Yield to Worst $18.00 105.00 16.0% $16.00 14.2% 14.0% $14.00 100.00 12.0% $12.00 10.0% st $10.00 Price 95.00 8.0% t o Wor $8.00 eld 6.0% I $6.00 Y $4.00 90.00 4.0% $4.00 89.60 $2.00 2.0% $— 85.00 0.0% 3/15/18 5/27/18 8/8/18 10/20/18 1/1/19 3/15/19 3/15/2018 5/14/2018 7/14/2018 9/13/2018 11/13/2018 1/13/2019 3/15/2019 Price Yield to Worst AMID Revolving Credit Facility Cost of Borrowing1 Covenant Consolidated Total Leverage Ratio2 Maximum Consolidated total leverage per AMID credit agreement decreases from 6.5x 6.25x currently to 5.75x for the quarter 7.00% 5.8x 6.1x 6.1x ending June 30, 2019 6.1x 5.8x 5.8x 5.5x 6.61% 5.1x 6.50% 4.9x 4.9x 4.7x 4.7x 4.3x 6.00% 3.9x 3.7x 3.6x 3.5x 5.50% 5.00% 4.50% 4Q ‘18 1Q ‘19 2Q ‘19 3Q ‘19 4Q ‘19 1Q ‘20 2Q ‘20 3Q ‘20 4Q ‘20 4.00% 3/15/2018 5/14/2018 7/14/2018 9/13/2018 11/13/2018 1/13/2019 3/15/2019 AMID Financial Projections Source: Bloomberg, FactSet, AMID management AMID Financial Projections—With Divestitures per AMID Management Max Consolidated Total Leverage Ratio 1. Assumes 3-month LIBOR plus 4.00% 2. Total consolidated leverage ratio per Second Amendment to Second Amended and Restated Credit Agreement excludes non-recourse debt related to natural gas transportation as well as the convertible preferred units 3. Assumes sale of Chatom Bazor Ridge System for $5 million in April 2019, Bakken Crude Oil Gathering for $30 million in April 2019, Silver Dollar Pipeline for $125 million in June 2019, Lavaca System for $125 million in September 2019, Natural Gas Transportation for $200 million in November 2019 and Cushing Terminal for $30 million in December 2019 8 Situation Analysis Wall Street Research Summary Broker Research Summary: UBS (March 15, 2019) ? Neutral Rating (maintained from January 8, 2019) ? Price Target: $4.00 / unit (maintained from January 8, 2019) ? 2019E EBITDA: $178.7 million (reduced from $180.6 million as of January 8, 2019) Summary of AMID Broker Coverage 8 $20.00 6 $16.00 1 1 n gs Un ti 1 1 $12.00 i a R 4 2 t Price 1 $8.00 roker 2 B 1 2 4 2 $4.00 3 3 $4.00 $4.00 2 2 1 1 1 1 0 $0.00 Feb-17 May-17 Aug-17 Nov-17 Feb-18 May-18 Aug-18 Nov-18 Feb-19 Buy Hold Sell Price NTM Target Price Source: FactSet, Wall Street research, Bloomberg 9

Situation Analysis Historical Trading Performance $20.00 4,000 $16.00 D AMI A 3,000 C D E G T H I ra B F d ce $12.00 L n i Pri J K g t 2,000 o V n i l $8.00 u U m e M N O 1,000 0(00 AMID $4.00 Q s’ P ) $— —3/15/17 5/27/17 8/8/17 10/20/17 1/1/18 3/15/18 5/27/18 8/8/18 10/20/18 1/1/19 3/15/19 A • 3/20/17: Upsized credit facility from $750 million to $900 million K • 6/29/18: Amended credit facility agreement to reduce borrowing B • 6/2/17: Acquired Vioska Knoll gathering system for $32 million capacity by $200 million to $700 million upon consummation of C • 7/24/17: Entered definitive agreement to sell propane business to the sale of marine products terminals. Six of 19 lending banks SHV Energy N.V. for $170 million in cash asked for AMID to halt common unit and preferred distributions D • 8/8/17: Announced the acquisition of Panther assets for $52 million L • 7/27/18: Announced distribution reduction to $0.1031 per LP unit and entry into a JV agreement with Targa Midstream Services per quarter from $0.412, a 75% decrease creating Cayenne Pipeline, LLC M • 7/29/18: Southcross provides notice of termination of the E • 10/2/17: Acquired an additional 15.5% equity interest in Delta House Contribution Agreement from ArcLight for $125 million N • 9/28/18: Announced receipt of an unsolicited non-binding F • 10/30/17: Acquired an additional 17.0% interest in the Destin Pipeline proposal from ArcLight, pursuant to which ArcLight would acquire from ArcLight for $30 million all unaffiliated common units of AMID in exchange for $6.10 per G • 11/1/17: Announced acquisition of certain assets of Southcross common unit in cash Holdings, LP and proposed to merge with Southcross Energy O • 11/15/18: Entered into a definitive agreement to sell its refined Partners, LP (“Southcross”) in transactions valued at $815 million products terminal business to Sunoco, LP for $125 million H • 11/6/17: Announced the acquisition of the equity interests in Trans- P • 12/31/18: Amended credit agreement and announced elimination Union Interstate Pipeline from ArcLight for $48 million of distributions to common units and preferred units • I 12/14/17: Priced $125 million 8.5% Senior Notes due 2021 Q • 1/3/19: Announced receipt of the Second Proposal from ArcLight, • J 6/18/18: Entered into a definitive agreement to sell its marine pursuant to which ArcLight would acquire all unaffiliated common products terminals to institutional investors for $210 million units of AMID in exchange for $4.50 per common unit in cash Source: FactSet, S&P Capital IQ, filings, AMID management Note: Market data as of March 15, 2019 10 Situation Analysis Equity Ownership Summary – Excludes 1,329,987 Common Units Related to Warrants Summary Institutional Ownership Institution Units (000’s) Ownership % OppenheimerFunds Inc 6,319 8.0% Swank Capital LLC 2,379 3.0% Institutional/Other (Net of Prescott Group Capital Management 1,912 2.4% Retail, 25.5% Short Interest), 22.4% UBS AG 1,900 2.4% JPMorgan Chase & Co 911 1.2% MFP Investors LLC 775 1.0% Goldman Sachs Group Inc/The 593 0.7% Bank of America Corp 502 0.6% ClearBridge LLC 312 0.4% Creative Planning Inc 240 0.3% HITE Hedge Asset Management LLC 219 0.3% Cohen & Steers Inc 218 0.3% Neuberger Berman Group LLC 201 0.3% Morgan Stanley 200 0.3% ELCO Management Co LLC 168 0.2% Top 15 Institutional 16,851 21.3% Insiders, 52.1% Short Position2 688 0.9% Insider Ownership Unaffiliated Unitholders Holder Units (000’s) Ownership % Holder Units (000’s) Ownership % ArcLight Energy Partners Fund V, LP1 40,425 51.1% Institutional/Other (Net of Short Interest) 17,739 Management and Directors 790 1.0% Retail 20,135 Management and Directors 790 Total Insider 41,215 52.1% Total Unaffiliated Unitholders 38,665 48.9% Summary Holder Units (000’s) Ownership % Institutional/Other (Net of Short Interest) 17,739 22.4% Insiders 41,215 52.1% Retail 20,135 25.5% Total Units Outstanding 79,090 100.0% Source: Bloomberg, Public filings 1. Includes units held by ArcLight and its subsidiaries and affiliates, including 7,940,322 Series A-1 Units held by High Point, convertible into 10,172,347 Common Units, 3,401,875 Series A-2 Units held by Magnolia, convertible into 4,358,142 Common Units, 9,514,330 Series C Convertible Preferred Units held by Magnolia Holdings, convertible into 9,527,650 Common Units, 10,563,942 Common Units held by Magnolia Holdings, 1,349,609 Common Units held by American Midstream GP, LLC, 618,921 Common Units held by Magnolia, 2,853,482 Common Units held by Busbar II, LLC and approximately 980,889 General Partner units; excludes Magnolia Holdings’ 1,329,987 common units related to warrants 2. Short interest per Wall Street Market Data as of February 28, 2019 11

Situation Analysis Review of AMID’s Acquisitions / Divestitures ($ in millions) Acquisitions Date Transaction EBITDA Announced Acquiror / Seller Description Value Multiple 11/6/17 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 Trans-Union Interstate Pipeline, L.P. $48.0 6.5x 10/30/17 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 17% interest in the Destin Pipeline 30.0 6.3 10/2/17 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 15.5% interest in Delta House 125.4 7.1 8/8/17 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 Remaining interests in MPOG and AmPan (Panther Operating) 52.0 7.0 6/2/17 American Midstream Partners, LP / Genesis Energy LP Vioska Knoll gathering system 32.0 7.0 11/1/16 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 6.2% interest in Delta House 48.8 6.0 2 10/24/16 American Midstream Partners, LP / JP Energy Partners LP Crude oil pipelines; refined products terminals; NGL distribution 459.4 7.2 4/25/16 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 GoM offshore pipeline assets 225.0 6.0 8/10/15 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 12.9% interest in Delta House 162.0 5.0 10/14/14 American Midstream Partners, LP / Costar Midstream G&P assets in East Texas, Permian and Bakken 470.0 10.5 8/7/14 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 Eagle Ford gas gathering system 110.0 —7/14/14 American Midstream Partners, LP / DCP Midstream LLC 67% interest in MPOG 13.5 5.5 1/22/14 American Midstream Partners, LP / Penn Virginia Corp. Eagle Ford gas gathering system 100.0 12.5 12/10/13 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 Blackwater Midstream’s three multi-modal terminals 60.0 7.8 6/1/12 American Midstream Partners, LP / Quantum Resources Management, LLC 87.4% interest in Chatom Processing and Fractionation Plant 55.0 7.9 11/17/11 American Midstream Partners, LP / Marathon 50% interest in the Burns Point Gas Plant 38.0 — Mean 7.3x Median 7.0 Divestitures Date Transaction EBITDA Announced Acquiror / Seller Description Value Multiple 11/15/18 Sunoco LP / American Midstream Partners, LP Caddo Mills and North Little Rock refined products terminals $125.0 7.3x 6/18/18 Institutional Investors / American Midstream Partners, LP Harvey and Westwego marine products terminals 210.0 13.9 7/24/17 SHV Energy N.V. / American Midstream Partners, LP Propane marketing and services business 170.0 9.0 Mean 10.1x Median 9.0 Source: AMID management, press releases, Partnership filings, 1Derrick, IHS 1. Also includes affiliates of ArcLight Capital Partners, LLC 2. Includes run-rate synergies 12 III. Asset Overview

Asset Overview Overview of AMID’s Asset Base G&P Gas Transport Bakken Gathering Cushing Terminal NGL Pipelines ? Systems: 7 ? ~1.2 Bcfd FT and IT ? Miles: 47 ? Capacity: 3.0 MMBbl ? Pipeline Interests: 3 ? Miles: 1,300 volumes ? Capacity: 40 MBpd ? Tanks: 5 ? Ownership: 16.7%, 25.3% & 50.0% ? Processing Plants: 6 ? 98% firm volumes ? Dedicated Acres: ? Capacity: 180 MBpd ? Processing Capacity: ? 6.7 years weighted 27,500 ? Miles: 254 157 MMcfd average contract term ? Dedicated Acres: 2019E Gross Margin Contribution 100,000 Bakken 4% 2% 1%1% Crude Delta House 5% Gathering and Processing Gathering Offshore Pipelines Excl. Delta House Legend Natural Gas Transportation 10% 27% Silver Dollar Pipeline G&P NGL JV Interest Bakken Crude Oil Gathering Gas Transportation Trucking Silver Dollar Cushing Terminal 25% 25% Bakken Gathering Offshore Pipelines Delta House NGL Pipelines Cushing Terminal Terminal Truckyard Offshore Pipelines ? Systems: 5 Natural Gas ? Permian G&P Transportation Miles: 1,318 ? Capacity: 8.5 Bcfed Silver Dollar Gulf Coast G&P E. Texas G&P Silver Dollar Crude Gathering ? Miles: 161 Trucking1 Offshore Delta House ? Capacity: 130 MBpd NGL Pipeline Pipelines ? Dedicated Acres: ? Trucks: 71 S. Texas G&P Interests Delta House ? 35.65% Interest 350,000 ? Truckyards: 5 ? Capacity: 100 MBpd of ? Truckyard: 1 crude oil and 240 MMcfd of natural gas ? Trucks: 22 1. Trucking segment includes only South Texas and Panhandle trucking assets; West Texas trucking assets grouped with Silver Dollar Pipeline 13 Asset Overview Overview of AMID’s Asset Base (cont’d) Business / Summary of Assets Segment A ? Diversified mix of high-and low-pressure natural gas gathering systems located in the Permian, East Texas, Eagle Ford and Gulf Coast regions with 1,300 miles of pipeline Gathering & ? 6 processing plants with 157 MMcfd of capacity and 4 fractionation facilities with 18.7 MBpd of capacity Processing ? 3Q 2018 revenue was approximately 71% fixed fee and 29% POP ? Growth opportunities include Longview expansion and acquisition of interest in Pascagoula Plant B ? FERC-regulated interstate and intrastate natural gas pipelines with 3.0 Bcfd capacity spanning more than Natural Gas 650 miles Transportation ? Demand-based assets, 100% fixed-fee revenue with investment-grade counterparties ? Long-term firm transportation agreements C ? Offshore pipelines include over 1,300 miles of oil and gas pipelines underpinned primarily by long-term life of lease dedications by producers in the Gulf of Mexico (“GoM”) Offshore Pipelines ? Joint venture interests in Destin (67%) and Okeanos (67%) and own 100.0% of High Point, Panther and (excl. Delta House) Main Pass Oil Gathering (“MPOG”) ? Customer base is diversified and includes multiple investment-grade customers D ? 35.65% interest in the Delta House system, a fee-based, semi-submersible floating production system located in the Mississippi Canyon block of the deepwater GoM operated by LLOG Production Delta House ? Design capacity of 100 MBpd and 240 MMcfd of gas E ? AMID’s trucking assets in the Texas Panhandle and South Texas include five truckyards and 71 tractors, Trucking oriented to facilitate long-haul crude and NGL product transport to the Gulf Coast (Texas Panhandle + South Texas) Source: AMID management, public filings 14

Asset Overview Overview of AMID’s Asset Base (cont’d) Business / Summary of Assets Segment F ? FERC-regulated crude oil gathering system located in the Williston Basin Bakken Crude ? Includes approximately 47 miles of newly-constructed pipeline with diameters ranging from 4 to 10 inches Gathering & ? System volumes supported by a 10-year, fee-based acreage dedication from Encana Corporation Marketing (“Encana”) ? Pipeline interconnects with Andeavor High Plains Pipeline and Dakota Access Pipeline G Silver Dollar ? 161-mile crude gathering pipeline system with total system throughput capacity of 130 MBpd (including West ? Storage capacity of 140 MBbls Texas Trucking and ? Over 350,000 dedicated acres Marketing) ? One truckyard in San Angelo, Texas with 22 trucks H ? Crude oil storage facility located in Cushing, OK with aggregate capacity of 3.0 MMBbls ? Strategically located near the NYMEX WTI clearing location with close proximity to the Mississippi Lime Cushing Terminal Basin, Granite Wash and the SCOOP / STACK I NGL Pipeline ? AMID’s NGL pipeline interests in the Gulf Coast strategically located to transport nearly all NGL production Interests out of the Eastern GoM and include joint venture interests in Cayenne (50.0%), Wilprise (25.3%) and Tri-(Wilprise, States pipelines (16.7%) Tri-States, Cayenne) Source: AMID management, public filings 15 Asset Overview A Gathering & Processing ? AMID’s natural gas gathering and processing assets span a diversified set of U.S. basins and regions including the Permian, East Texas, Eagle Ford and Gulf Coast ? 1,300 miles of high- and low-pressure natural gas gathering systems with design capacity of 410 MMcfd ? Six processing plants with capacity to process 157 MMcfd ? Four fractionation facilities with 18.7 MBpd of capacity ? Average throughput declined in 2018 in part due to Burns Point Plant shutdown Gas Gathering and Processing Summary Pipeline Processing Average Throughput (MMcfd) Capacity Capacity System Region Location Length (miles) (MMcfd) (MMcfd)2 2017A 2018A Yellow Rose Permian Martin, Andrews and Dawson Counties, TX 34 low pressure / 25 high pressure 40 40 4.7 6.9 Longview East Texas Gregg, Rusk and Smith Counties, TX 643 50 50 14.9 14.7 Chapel Hill East Texas Smith County, TX 100 20 20 12.8 12.1 Lavaca Eagle Ford Lavaca and Gonzales Counties, TX 203 218—106.3 130.3 Bazor Ridge Jasper, Clarke, Wayne and Greene Counties, MS Gulf Coast 198 47 47 10.8 9.7 & Chatom1 and Washington County, AL Burns Point Gulf Coast St. Mary Parish, LA — 1652 52.6—Danville East Texas Gregg County, TX 97 35—15.4 15.2 Total 1,300 410 157 217.4 189.3 Fractionation / Stabilization Summary Fractionation Average Throughput (MBpd) Plant Region Location Capacity (Bpd) Broader System Capabilities 2017A 2018A Gathering; 50 MMcfd processing plants; stabilization unit (6,500 Bpd); Longview East Texas Gregg County, TX 8,500 5.9 6.4 storage tanks, NGL sales pipelines, truck rack Mesquite Permian Midland County, TX 7,000 Ability to treat and sell volumes via pipeline, truck and rail—2.6 Chatom East Texas Washington County, AL 1,900 Gathering; 25 MMcfd processing plant; 160 LTPD sulfur recovery unit 0.8 0.5 Chapel Hill East Texas Smith County, TX 1,250 Gathering; 20 MMcfd processing plant; 4,500 Bbl storage; truck racks 0.2 0.2 Total 18,650 6.9 9.7 1. Includes Glade Crossing 2. Burns Point plant capacity excluded from total due to maintenance issues shutting down plant operations in December 2017 16

Asset Overview A Gathering & Processing – Permian Asset Overview Asset Map ? The Yellow Rose Gathering and Processing System (“Yellow Rose”) AMID consists of approximately 34 miles of low-pressure gathering and Diamondback approximately 25 miles of high pressure gathering systems with an Ajax (FANG) NGL connection to West Texas Pipeline and a 40.0 MMcfd cryogenic ExL (FANG) processing plant with a 2,000 Bpd condensate stabilizer Encana SM Energy ? Plant completed in October 2014 FANG Rig Encana Rig ? SM Energy Rig Three field and two residue compressors (all owned) Mesquite Plant Yellow Rose ? 30,000 dedicated acres; key customers include Ajax Resources, Plant Inc. (“Ajax”) (recently acquired by Diamondback Energy (“Diamondback” or “FANG”), Encana Corporation (“Encana”) and SM Energy Co. (“SM Energy”) Anchor Customer: Diamondback ? On October 31, 2018, Diamondback closed ? Competes with EnLink Midstream Partners , L.P. (“EnLink) with on its acquisition of Ajax Resources for FANG and Ajax wells split-connected with AMID and EnLink; $1.25 billion however, EnLink’s 75 MMcfd West Plant has had operational ? 29,139 net acres (25,000 in Martin and issues requiring high levels of flaring Andrews counties) ? >450 net locations with an average ? Acquired in October 2014 with AMID’s acquisition of Costar lateral length of 9,300’ Midstream from Energy Spectrum Partners VI LP • 63% of locations in the top quartile of FANG’s current inventory ? (>100% IRRs) The Mesquite JV is a joint venture with EnLink that includes a rail ? ExL Petroleum bolt-on acquisition added terminal and fractionator near Midland, Texas and allows for receipt >3,600 net acres of 7,000 Bpd of off-spec condensate and NGLs to be treated and ? Diamondback is operating one rig in NW sold via pipeline, truck and rail Martin County as of February 2019 Source: AMID management, public filings, Diamondback investor presentation, DrillingInfo (3/11/19) 17 Asset Overview A Gathering & Processing – Permian (cont’d) ($ in millions, except per unit amounts) Yellow Rose System Utilization (MMcfd) Assumes 5-10 wells per year or a 0.5 to 1.0 rig rate 60.0 1.2 1.0 Diamondback 50.0 1 (MMcfd 40 40.0 40.0 0.8 ) 0.8 0.8 Volume 30.0 0.5 0.5 0.6Rig Forecast 20.0 17.0 17.4 17.3 0.4 13.2 7.3 7.7 6.6 8.0 10.0 4.7 6.0 0.2 — 0 2017A 1Q18A 2Q18A 3Q18A 4Q18A 2019E 2020E 2021E 2022E 2023E Yellow Rose Throughput (MMcfd) Yellow Rose Capacity (MMcfd) Diamondback Rig Forecast Asset EBITDA $9.0 $7.9 $8.0 $8.0 $6.5 $6.0 $4.0 $3.9 $3.9 $4.5 $3.9 $3.0 $3.8 $0.9 $0.7 $3.9 $4.1 $4.1 $0.3 $0.3 $0.0 $2.6 $0.1 $0.9 $0.1 $0.2 $0.5 $0.2 $0.6 $0.7 $— ($0.3) ($0.6) ($0.0) ($3.0) 2017A 1Q18A 2Q18A 3Q18A 4Q18A 2019E 2020E 2021E 2022E 2023E Yellow Rose Mesquite1 Source: AMID management, public filings, Diamondback investor presentation 1. Mesquite EBITDA represents AMID earnings defined as 70% of gross margins less 50% of operating expenses 18

Asset Overview A Gathering & Processing – East Texas Asset Overview Asset Map Longview Gathering & Processing System ? The Longview Gathering and Processing System (“Longview”) in Gregg, Rusk and Smith Counties consists of 643 miles of high- and low-pressure gathering lines, two cryogenic processing plants with a design capacity of 50.0 MMcfd, one fractionation unit with 8,500 Bpd of capacity, a stabilization unit with 6,000 Bpd of off-spec condensate and NGL treating capacity, product storage tanks, NGL sales pipelines and a two-bay, semi-automated truck rack equipped to receive on- and off-spec NGLs and condensate ? Highly profitable legacy contracts providing for retention of a high AMID percentage of liquids Chapel Hill Plant ? Currently providing economic incentives to spur workover activity Longview Plant ? Competes with Midcoast Operating L.P. (“Midcoast”) in the area Exxon E. Texas Plant ? In April 2016, AMID announced the commencement of operations at the Rig East Texas Rail Facility, allowing for receipt and delivery of NGLs and Rail condensate by rail to the Longview Processing Plant System Utilization (MMcfd) ? Includes more than 8,900 feet of lead track with current capacity for more than 50 general purpose or pressure railcars Includes volume gains from workovers and 1-2 wells per year and deliver up to 4,500 Bpd of 80.0 on Longview and 1 well per year on Chapel Hill ? Ability to receive NGLs, including purity products and condensate, with similar capabilities for rail-to-truck 70.0 transloading 60.0 Chapel Hill Gathering & Processing System 43.6 43.5 44.0 44.4 43.1 42.3 42.1 42.7 43.0 40.3 ? Located near Smith County, Texas, the Chapel Hill Gathering and 40.0 Processing System (“Chapel Hill”) consists of 100 miles of gathering lines with 2,540 horsepower (“HP”) of compression, a 20.0 MMcfd cryogenic processing plant, a 1,250 Bpd fractionation unit, 190,000 gallons of product 20.0 storage capacity and truck racks to deliver propane, butane and natural gasoline —? Gathers casinghead gas and wet gas production from the Paluxy, Petit and Cotton Valley formations Source: AMID management, public filings, DrillingInfo (3/11/19) 19 Asset Overview A Gathering & Processing – Eagle Ford Asset Overview Asset Map PVAC Acreage ? The Lavaca System (“Lavaca”) consists of 203 miles of high- PVAC Rig pressure and low-pressure pipelines located in Gonzales and Lavaca System Lavaca Counties, Texas ? 218.0 MMcfd of gas gathering design capacity, 24,960 HP of leased compression and 3,215 HP of owned compression ? 70,000 dedicated acres; key customers include Penn Virginia Corporation (“PVAC”) and Devon Energy (“Devon”) ? In January 2014, AMID acquired 120 miles of the system from PVAC for $100.0 million at an implied 12.5x EV / EBITDA multiple ? PVAC entered into a fee-based gathering agreement covering a 70,000-acre dedication for 25 years System Utilization (MMcfd) ? In August 2014, AMID exercised its right-of-first-offer to 322.0 350.0 Assumes 55 wells connected 310.5 annually (3-rig pace) 286.5 acquire the Gonzales County full-well-stream gathering 260.1 system from ArcLight 300.0 229.2 ? AMID entered into a fee-based agreement with Forest Oil 250.0 183.5 Corporation 200.0 218.0 ? On December 13, 2018, AMID’s sale process for Lavaca 150.0 128.2 137.1137.1 118.7 ended with no definitive bids being received 106.3 100.0 ? Oil price decline 50.0 ? Uncertainty regarding closing of Denbury Resources Inc.’s (“Denbury” or “DNR”) announced acquisition of — PVAC Throughput (MMcfd) Capacity (MMcfd) Source: AMID management, public filings, Wall Street research, DrillingInfo (3/11/19) 20

Asset Overview A Gathering & Processing – Eagle Ford – PVAC Transaction The future of producer-driven volumes near AMID’s Eagle Ford position is in flux as the outcome of Denbury’s announced acquisition of PVAC remains unclear Transaction Overview Post-Announcement Share Price Performance ? On October 28, 2018, Denbury announced it had entered a 120.0% definitive merger agreement to acquire PVAC in a transaction valued at approximately $1.7 billion 100.0% 89.9% ? The proposed consideration includes: ? 12.4 shares of Denbury per share of PVAC and cash of 80.0% 78.1% 69.5% $25.86 per PVAC share, representing consideration of 60.0% $79.80 per share based on the closing price of Denbury common stock on October 26, 2018 40.0% 38.9% ? PVAC’s assets include: ? 84,700 net acres in Gonzales, Lavaca and DeWitt 20.0% Counties 10/28/18 11/20/18 12/13/18 1/5/19 1/28/19 2/20/19 3/15/19 ? >450 net locations and a 10-year drilling inventory with DNR PVAC 1 upside from Austin Chalk and Upper Eagle Ford Proposed Consideration S&P Oil & Gas E&P Index ? Described by Denbury as delivering “top tier operating Post-Announcement Merger Arbitrage Spread margins” 25.0% As of March 15, 2019, the merger arbitrage ? PVAC is operating three rigs in Lavaca County as of spread was -$5.78, or (11.0%) February 2019 and plans to drill 50 wells in 2019 20.0%? Select PVAC shareholders are pressuring the acquisition 15.0% regarding the quality of Denbury’s existing asset base, 10.0% expected synergies with PVAC and Eagle Ford EOR 5.0% potential (which EOG is currently pilot testing in close —% proximity to PVAC’s acreage) (5.0%) ? Mangrove Partners Master Fund, Ltd. is seeking votes (10.0%) (11.0%) against the merger and owns 11.4% of PVAC’s outstanding shares (15.0%) (20.0%) Source: AMID management, public filings, Wall Street research 10/28/18 11/20/18 12/13/18 1/5/19 1/28/19 2/20/19 3/15/19 1. Reflects shift in value of proposed consideration over time relative to PVAC’s share price as of the transaction announcement date of October 28, 2018 21 Asset Overview A Gathering & Processing – Gulf Coast Asset Overview1 Asset Map Chatom Gathering & Processing System ? The Chatom System (“Chatom”) consists of a 29-mile gathering system with 3,456 HP of compression, a 25.0 MMcfd cryogenic processing plant, a 1,900 Bpd NGL fractionation unit and a 160 long-ton per day sulfur recovery unit located in Washington County, AL ? Chatom gathers natural gas from onshore crude oil and natural gas wells in the Norphlet and Smackover formations in Alabama and Mississippi and has a truck rack and the capability to receive and fractionate NGLs ? AMID acquired an 87.4% interest in Chatom in July 2012 for $51 Bazor Ridge System million in cash from Quantum Resources Management, LLC at an Chatom System Plant estimated 7.3x EV / EBITDA multiple Active Rig ? Chatom is located approximately 15 miles from AMID’s Bazor Ridge Tellus Permit processing plant in Wayne County, Mississippi System Utilization Bazor Ridge Gathering & Processing System 50.0 47.0 ? The Bazor Ridge System (“Bazor”), located in Jasper, Clarke, Wayne 40.0 Benefit from six expected new wells and Greene Counties, Mississippi, includes: permitted by Tellus Operating Group, LLC on Bazor Ridge ? 169 miles of gas gathering pipeline ranging in diameter from three 30.0 to eight inches and three compressor stations with a combined 1,069 HP 20.0 11.3 12.8 14.0 13.9 13.7 13.4 10.8 9.1 10.9 7.5 ? 22.0 MMcfd sour natural gas treating and cryogenic processing plant with four inlets and one discharge compressor with 10.0 approximately 5,218 of combined HP —? Since 2016, Bazor has been used as a central gathering and compression facility while processing has been re-routed to Chatom Throughput (MMcfd) Capacity (MMcfd) Source: AMID management, public filings, DrillingInfo (3/11/19) 1. Burns Point Plant, a 165.0 MMcfd Plant jointly owned 50% by AMID and 50% by Enterprise Products Partners L.P. (“Enterprise”) has been shut down since December 2017 due to maintenance issues 22

Asset Overview B Natural Gas Transportation Asset Summary ? AMID’s natural gas transportation segment is supported by reservation-based contracts with volume driven by demand ? 6.4 -year weighted average contract life Average Transmission Design Reservation Volumes (MDth/d) 2018A System Miles Jurisdiction Compression (HP) Capacity (MDth/d) 2017A 2018A Utilization Midla / MLGT 110 Interstate / Intrastate 3,600 368 367 371 100% TransUnion 42 Interstate — 546 470 470 86% AlaTenn / Bamagas / Trigas 383 Interstate / Intrastate 3,665 710 307 301 42% Magnolia 116 Intrastate — 100 95 74 74% Total 651 7,265 1,724 1,240 1,215 72% Revenue by Customer / Demand Type Asset Map Industrials Legend 16.0% Utility AlaTenn 23.0% Bamagas / Trigas MLGT Midla Magnolia Trans-Union Marketers 20.0% Power 41.0% Source: AMID management, public filings 23 Asset Overview B Natural Gas Transportation (cont’d) Asset Overview Contract Terms ? Intrastate transmission system with approximately 54 miles of pipeline with diameters ranging 92% reservation from three-to-14 inches, a design capacity of 170 MMcfd, five receipt points and 19 delivery volumes points MLGT? Sources natural gas from interconnects with FGT Pipeline, Texas Eastern Transmission 3.5 -year average term Pipeline, Transco Pipeline and AMID’s Midla System to a Baton Rouge, Louisiana refinery owned and operated by ExxonMobil and several other industrial customers ? Interstate pipeline with approximately 370 miles of pipeline linking the Monroe Natural Gas Field in northern Louisiana and interconnections with the Transco Pipeline System and Gulf South Pipeline System to various power plants owned by Entergy Corporation (“Entergy”) serving local distribution companies and municipalities in Louisiana and Mississippi ? Northern portion of system, including the T-32 lateral, consists of four miles of high-pressure, 12-inch diameter pipeline with delivery to two power plants operated by Entergy by way of the T-32 Lateral and the Cleco Corporation Sterlington Plant by way of the Sterlington Lateral Midla? Mainline has design capacity of approximately 198 MMcfd and consists of approximately 170 miles of low-pressure, 22-inch diameter pipeline with laterals ranging in diameter from two to 16 inches with delivery to small local distribution companies (“LDCs”) under firm transportation contracts that automatically renew annually ? Southern portion of system, including interconnections with MLGT and other associated laterals, consists of two miles of high- and low-pressure, 12-inch diameter pipeline with delivery to industrial and LDC customers in the Baton Rouge market through contracts with several large marketing companies 87% reservation TransUnion? 42-mile, 30-inch diameter high-pressure FERC-regulated TransUnion natural gas interstate volumes pipeline has 546,000 Dth/d of capacity and services power and industrial customers ? AMID purchased 100% of the equity interests in November 2017 from affiliates of ArcLight for 14.2 -year average term total consideration of approximately $48 million, 6.5x EBITDA Source: AMID management, public filings 24

Asset Overview B Natural Gas Transportation (cont’d) Asset Overview Contract Terms ? Design capacity of 200 MMcfd and consists of 294 miles of pipeline with diameters ranging 91% reservation volumes AlaTenn from 3-to-16 inches and two compressor stations with 3,665 HP connected to 19 active delivery and four receipt points 3.8 -year average term ? FERC-regulated interstate natural gas pipeline that interconnects with Tennessee Gas Pipeline (“TGP”) and travels west to east delivering natural gas to industrial customers in northwestern Alabama as well as city gates of Decatur and Huntsville, Alabama Bamagas? Intrastate natural gas pipeline system with design capacity of 450 MMcfd and consists of 52 miles of high-pressure, 30-inch pipeline that travels west to east from an interconnection point with TGP in Colbert County, Alabama, to two power plants in Morgan County, Alabama, with 100% of the throughput contracted under long-term firm transportation agreements ? The Trigas System is an intrastate natural gas pipeline located in northwestern Alabama Trigas across three counties with approximately 60 MMcfd of capacity 50% reservation Magnolia? The Magnolia Gathering System is a 116-mile intrastate pipeline that gathers coal-bed volumes methane in Tuscaloosa, Greene, Bibb, Chilton and Hale Counties, Alabama and delivers to the Transco Pipeline System owned by The Williams Companies, Inc. ~1.0 -year average term Source: AMID management, public filings 25 Asset Overview B Natural Gas Transportation – Firm Contract Summary Pipeline Customer Rate ($/Dth/d) Term $0.034 13.7 years TransUnion $0.054 7.2 years Midla Small Utilities & Industrial ($0.280/ $0.560/ $0.810) 13.2 years $0.022 0.7 years $0.015 0.7 years LDC $0.090 0.7 years MLGT $0.085 0.7 years $0.025 8.7 years $0.090 4.7 years $0.140 0.7 years Large Utilities $0.093 Various AlaTenn Small Utilities $0.110 Various Industrials $0.090 Various MEC ($0.070/ $0.040) 1.7 years Bamagas / Trigas DEC ($0.070/ $0.040) 1.7 years Industrials $0.125 9.7 years Magnolia Marketers $0.103 0.7 years 26

Asset Overview B Natural Gas Transportation – 2018A Summary by Pipeline ($ in millions) 2018A Volumes (Dth/d) 500,000 477,231 7,203 470,028 400,000 375,394 31,949 343,445 300,000 200,173 200,000 200,173 106,342 92,439 100,000 7,689 27,615 15,028 3,761 27,446 98,653 73,649 169 1,961 3,248 1,288 —TransUnion Midla MLGT AlaTenn Bamagas Trigas Magnolia Firm Reservation Interruptible Marketing Physical Throughput 2018A Gross Margin $10.0 $8.8 $8.5 $8.0 $6.5 $2.5 $1.2 $5.4 $0.1 $5.3 $4.3 $6.0 $3.8 $0.2 $0.3 $0.6 $4.0 $1.2 $0.3 $1.9 $6.1 $0.1 $5.1 $2.0 $3.7 $3.9 $2.7 $0.2 $2.8 $— ($0.0) $0.2 $0.0 ($2.0) ($3.9) ($4.0) ($6.0) TransUnion Midla MLGT AlaTenn Bamagas Trigas Magnolia Firm Reservation Interruptible Marketing Other1 Source: AMID management 1. Other revenue include imbalance revaluation, non-cash revenue recognition, management fee revenue, facility fees and other revenue 27 Asset Overview B Natural Gas Transportation – Forecast Summary ($ in millions) Volume Forecast (Dth/d) 1,300,000 1,282,443 1,280,000 15,028 1,260,000 1,240,000 52,059 1,218,219 1,218,219 1,218,219 1,220,000 1,192,936 15,370 15,370 15,370 1,200,000 1,188,422 12,130 12,130 12,130 1,180,000 15,368 15,370 12,130 1,160,000 14,630 1,215,356 1,140,000 1,190,719 1,190,719 1,190,719 1,120,000 1,158,424 1,165,436 1,100,000 1,080,000 2018A 2019E 2020E 2021E 2022E 2023E Firm Reservation Interruptible Marketing Gross Margin Forecast $40.0 2018A to 2019E margin decline driven by interruptible volume and non-recurring marketing fuel gains in 2018A $36.1 $32.8 $33.7 $33.7 $35.0 $31.1 $2.1 $2.1 $7.5 $29.8 $2.0 $1.4 $1.5 $1.5 $30.0 $2.8 $0.5 $0.5 $1.1 $2.2 $1.4 $0.5 $2.3 $0.5 $25.0 $1.8 $0.6 $20.0 $15.0 $25.9 $26.4 $28.9 $29.6 $29.6 $24.5 $10.0 $5.0 $— 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management Firm Reservation Interruptible Marketing Other 1 1. Other revenue include imbalance revaluation, non-cash revenue recognition, management fee revenue, facility fees and other revenue 28

Asset Overview C Offshore Pipelines (excl. Delta House) Legend Destin High Point Okeanos West Delta 109 Main Pass Cayenne Empire Gloria / Lafitte Montegut Toca Source: AMID management 29 Asset Overview C Offshore Pipelines (excl. Delta House) System Summaries Destin Okeanos High Point1 MPOG Panther Pipelines2 Location Onshore / Offshore Offshore Onshore / Offshore Offshore Onshore / Offshore Product Natural Gas Natural Gas Natural Gas / Crude Oil Crude oil Natural Gas / Crude Oil 663 miles of FERC- 255 miles of FERC- 100 miles of FERC- regulated and non-FERC- 100 miles of oil gathering 200 miles of oil and gas Facilities regulated pipelines regulated pipelines regulated gathering pipelines pipelines pipelines Pipeline 24-, 30- and 36-inch 20- and 24-inch 12-to-26-inch 8-to-10-inch 2-to-30 inch FGT Gulfstream / Shell Zydeco / Bridgeline / Delivery Destin Toca MP69 Pascagoula Burns Point Commercial Summaries Initial Total Percent Percent Dedication FERC Current Acquired Ownership of Fields Operator Regulated ROFR Partner Destin 66.7% 66.7% Yes AMID No No Enbridge Okeanos 49.7% 66.7% Yes AMID Yes Yes Enbridge HPGT 100.0% 100.0% Yes AMID Yes N/A N/A HPGG 100.0% 100.0% Yes AMID No N/A N/A MPOG 67.0% 100.0% Yes AMID No N/A N/A Panther Pipelines 100.0% 100.0% No AMID No N/A N/A Source: AMID management, public filings 1. Includes High Point Gas Transmission (HPGT), High Point Gas Gathering (HPGG), Gloria, Lafitte, Chalmette and Vioska Knoll gathering systems 2. Panther provides crude oil and natural gas transportation services from the South Marsh Island area offshore to an onshore station near Henry Hub in Vermillion Parish, LA 30

Asset Overview C Offshore Pipelines (excl. Delta House) – Destin / Okeanos Asset Overview ? Originating offshore in the GoM, the Destin Pipeline (“Destin”) is a FERC-regulated, 255-mile natural gas transport system with total capacity of 1.2 Bcfd operated by AMID ? Destin interconnects with four producing platforms and six producer-operated laterals ? Destin’s 120-mile 24- and 36-inch diameter offshore portion terminates at the Pascagoula Processing Plant and extends 135 Destin miles north in Mississippi with 30- to 36-inch pipeline and is the sole delivery point for merchant-quality gas from the plant ? Contracted volumes on Destin are based on life-of-field dedication, dedicated volumes over a given period, or interruptible volumes as capacity permits ? AMID owns a 66.7% interest in Destin, having acquired a 49.7% interest in 2016 (along with the Tri-States and Wilprise pipelines) for $225 million and an incremental 17% for $30 million in October 2017 ? Throughput driven by industrial, power and utility demand in Florida, Alabama and Mississippi ? In conjunction with its April 2016 acquisition of Destin, Tri-States and Wilprise, AMID purchased a 66.7% interest in the Okeanos system (“Okeanos”) from affiliates of ArcLight for $27.4 million in cash Okeanos? 100 miles of 20- and 24-inch natural gas gathering pipeline that connects two producer platforms (Thunder Horse and Na Kika) and one lateral to the Destin Main Pass 260 platform (“MP260”) in the Mississippi Canyon region of the GoM ? 1.0 Bcfd of design capacity meeting capacity requirements for platforms currently connected and has existing capacity to accommodate third-party volumes via subsea tie-backs or new export lines ? Contracted volumes on Okeanos are based on life-of-field dedications from producers ? Enbridge, Inc. holds the minority interest in Okeanos Destin-Okeanos Throughput (MMBtud) 2,500 2,000 1,500 2,200 1,000 1,168 1,107 1,157 1,140 1,254 1,313 1,223 1,180 500 1,035 1,076 — 2017A 1Q 2018A 2Q 2018A 3Q 2018A 4Q 2018A 2019E 2020E 2021E 2022E 2023E Throughput Capacity 2019E increase in volumes driven by increased volumes flowing from the High Point system Source: AMID management, public filings 31 Asset Overview C Offshore Pipelines (excl. Delta House) – Contract Summary Pipeline / Platform / Field Shipper Rates Term MP260 Okeanos (Thunder Horse) BP $0.24 FT-2 Okeanos (Thunder Horse) Exxon $0.15 FT-2 Okeanos (Na Kika) All $0.24 FT-2 Okeanos (Thunder Hawk) Murphy $0.24 FT-2 Destin Okeanos (Thunder Hawk) Fieldwood $0.15 FT-2 HPGG VK Native Platforms Various $0.18 IT HPGT MP 289 Reversal Various $0.06 IT Delta House LLOG/Others $0.15 FT-2 Marlin & Horn Mtn. Anadarko $0.24 FT-2 Pompano Talos $0.24 FT-2 MP281 & MP83 Enven/W&T $0.24 FT-2 Onshore Destin GS/BP/Chevron $0.065 FT 2-year1 Na Kika (BP Operated) / 8 producing blocks E. Anstey/Fourier/Ariel/Kepler/Isabela BP $0.25 Life of Lease Coulomb Shell $0.25 Life of Lease Santa Cruz / Santiago Fieldwood $0.25 Life of Lease Okeanos Thunder Horse (BP Operated) / 6 producing blocks Thunder Horse BP (75%) $0.25 Life of Lease Thunder Horse Exxon (25%) $0.15 Life of Lease N. Thunder Horse BP $0.25 Life of Lease Thunder Hawk (Fieldwood Operated) / 3 producing blocks MC698 (Big Bend) Fieldwood $0.15 Life of Lease MC782 (Dantzler) Fieldwood $0.25 Life of Lease MC734 (Thunder Hawk) ENI/Murphy $0.25 Life of Lease Source: AMID management, public filings 1. Represents average contract term 32

Asset Overview C Offshore Pipelines (excl. Delta House) – High Point Asset Overview ? The 663-mile High Point system (“High Point”) with total pipeline capacity of 1,120 MMcfd consists of natural gas and liquids pipeline assets which gather natural gas from onshore and offshore areas in southeast Louisiana and the GoM ? Its onshore footprint is located in Plaquemines and St. Bernard Parish, Louisiana and its offshore footprint consists of the following GoM zones: Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound ? High Point gathers natural gas at more than 63 receipt points that connect to hundreds of wells targeting various geological zones in water depths up to 1,000 feet and delivers natural gas to the Toca Gas Processing Plant, operated by Enterprise, where it is processed and residue gas is sent to an unaffiliated interstate system owned by Kinder Morgan, Inc. ? High Point includes both FERC-regulated transmission assets (High Point Gas Transmission) and non-jurisdictional gathering assets (High Point Gas Gathering, Gloria, Lafitte and Chalmette Systems) High Point? The Gloria Gathering System (“Gloria”) consists of approximately 138 miles of pipeline with diameters ranging from 3-to- 16 inches and four compressors with 2,962 HP ? AMID’s Lafitte System (“Lafitte”) consists of approximately 40 miles of gathering pipeline, with diameters ranging from 4-to-12 inches and a design capacity of 71 MMcfd • Originating onshore, it terminates at the Alliance Refinery (owned by Phillips 66) in Plaquemines Parish, LA ? AMID is the sole supplier of natural gas to the Alliance Refinery pursuant to a contract that expires in 2026 ? The Chalmette System (“Chalmette”) is located in St. Bernard Parish and has a design capacity of 125 MMcfd ? High Point also includes Vioska Knoll Gathering System (“VKGS”), consisting of natural gas and crude oil gathering lines of varying diameters and the platform at VK817, purchased from Genesis Energy in 2017 for $32.0 million in cash High Point Throughput (MMBtud) 1,200 1,120 800 400 360 319 346 316 297 348 345 338 311 282 —2017A 1Q 2018A 2Q 2018A 3Q 2018A 4Q 2018A 2019E 2020E 2021E 2022E 2023E Throughput Capacity Source: AMID management, public filings 33 Asset Overview C Offshore Pipelines (excl. Delta House) – Contract Summary Pipeline / Platform / Field Shipper Rates Term High Point Gas Transmission (FERC-regulated) MP108 W&T $0.07 Life of Lease BS51 Upstream $0.15 Life of Lease Other platforms Various $0.29 IT High Point Gas Gathering (non-FERC-Regulated) MP108 W&T $0.25 Life of Lease BS51 Upstream $0.15 Life of Lease Platforms flowing into HPGT Various $0.25 IT Point Ram Powell (Anchor Field) Talos $0.15 Life of Lease Ram Powell (Stonefly) LLOG $0.225 Life of Lease Medusa Murphy $0.20 Life of Lease High MP252 (Bud/Tahoe) W&T $0.10 Life of Lease MP259 Fieldwood $0.85 Life of Lease VK786 (Petronius) Various $0.19 Life of Lease VK817 (Platform Fees) Walter/LLOG $2 MM1 Annual MP 289 Reversal Various $0.04 IT Gloria, Lafitte, Chalmette (non-FERC-Regulated) Production Platforms BP $0.24 FT-2 Alliance Refinery (delivery) Exxon $1 MM1 FT-2 Chevron Oak Point (delivery) All $0.28 FT-2 Meraux Refinery Valero $0.04 FT-2 Source: AMID management, public filings 1. Represents annual rate 34

Asset Overview C Offshore Pipelines (excl. Delta House) – MPOG and Panther Pipelines Asset Overview ? The Main Pass Oil Gathering System (“MPOG”) is a 100-mile crude oil gathering system located off the Southeast coast of Louisiana in the GoM MPOG? Total design capacity of approximately 160,000 Bpd and currently operated by AMID’s wholly-owned subsidiary, Panther Operating Company, LLC ? Majority of volumes generated by life-of-lease contracts from a large, primarily investment-grade customer base ? In July 2014, AMID acquired a 67% interest in MPOG from an affiliate of DCP Midstream, LLC for approximately $13.5 million or approximately 5.0x to 6.0x NTM EBITDA ? In August 2017, AMID acquired Panther (including all outstanding equity interests in MPOG) for $52 million ? Located in Southern Louisiana and GoM, the American Panther system (“Panther Pipelines”) consists of approximately 200 Pipelines miles of crude oil, natural gas and salt water onshore and offshore GoM pipelines ? The system has a natural gas design capacity of 475 MMcfd and crude oil and saltwater capacity of 27.0 MBpd ? In August 2017, AMID acquired the Panther pipeline assets for approximately $60.9 million, including the Tiger Shoals / HGGS (AmPan), Quivira, Panther Operating Services and Matagorda systems Panther? Originating offshore in Eugene Island Block 24 and terminating onshore in St. Mary Parish, LA, the Quivira Gathering System consists of 34 miles of pipeline ? Key customers include Cox Operating, LLC and Fieldwood Energy, LLC, with contract terms ranging from one year to 13 years MPOG and Panther Crude Oil Throughput (MBpd) Panther Pipeline Gas Throughput (MMBtud) 200 500 150 400 2019E volume increase due to new volumes 187 475 300 from Contango Oil and Gas Company 100 200 50 100 140 142 33 36 35 42 39 36 33 30 112 128 115 104 27 27 59 61 60 64 — — 2017A 1Q 2Q 3Q 4Q 2019E 2020E 2021E 2022E 2023E 2017A 1Q 2Q 3Q 4Q 2019E 2020E 2021E 2022E 2023E 2018A 2018A 2018A 2018A 2018A 2018A 2018A 2018A Throughput Capacity Throughput Capacity Source: AMID management, public filings 35 Asset Overview C Offshore Pipelines (excl. Delta House) – Contract Summary Asset Map Rates Main Pass Oil Gathering Pipeline / Platform / Field Shipper Term Gathering ($/Bbl) MPOG Marlin (Native) Anadarko $0.81 Life of Lease Marlin (Crown & Anchor) LLOG $1.45 Life of Lease Oil Neptune (Swordfish) Fieldwood $0.92 Life of Lease Pass Virgo W&T $0.82 Life of Lease Main MP281 Enven $1.09 Life of Lease MP270 Castex $2.52 Life of Lease MP133 Arena $1.42 Life of Lease Rates / Pipeline / Platform / Field Shipper Term Panther Pipelines Fees Tiger Shoals / HGGS (AMPAN) AMPAN (Cox Guaranteed Revenue) Cox $12 MM1 2023 Pipelines AMPAN (Mezzanine Processing) Cox 6% POL 2029 Quivira EL24 Cox $0.14 2031 Panther EL11 Contango $0.11 2023 Panther Operating Services HIPS Pipeline $2 MM1 2021 VGS Pipeline $1 MM1 1 year Matagorda (50/50 JV with Prism) Small Utility & One Industrial Various <$1 MM1 Annual Source: AMID management, public filings 1. Represents annual rate 36

Asset Overview D Delta House Asset Overview Delta House Facility ? AMID owns a 35.65% interest in the Delta House system (“Delta House”), a fee-based, semi-submersible floating production system located in the Mississippi Canyon block of the deepwater GoM ? Operated by LLOG Exploration (“LLOG”), a private oil and gas company founded in 1977 and headquartered in Covington, Louisiana ? 75% exploration success rate from 2017 to October 2018 ? In 2017, received the Offshore Technology Conference’s Distinguished Achievement Award in recognition of Delta House ? 12 wells online with life-of-lease dedication for production handling and a fixed fee-based structure on oil and gas export pipelines ? Nameplate capacity of 100,000 Bpd oil and 240 MMcfd of natural gas ? Directly connected to the Destin Pipeline AMID’s Delta House Acquisition History 12.9% 12.9% 13.9% 20.1% 1.0% 6.2% 87.1% 86.1% 15.5% 79.9% 64.4% Date Announced: August 10, 2015 April 25, 2016 November 1, 2016 October 2, 2017 Transaction Terms: 12.9% interest for $162.0 MM 1.0% interest for $10.0 MM 6.2% interest for $48.8 MM 15.5% interest for $125.4 MM Implied Valuation: $1,255.8 MM $1,000.0 MM $787.1 MM $809.0 MM Existing Ownership Addition to Ownership Non-AMID Ownership Source: AMID management, public filings 37 Asset Overview D Delta House System Map Otis Niedermeyer Delta House FPS Odd Job Marmalard Legend Anchor Prospect Secondary Prospect Son of Bluto II Source: AMID management, public filings 38

Asset Overview D Delta House Forecast ($ in millions) Volumes 120 350 ? Distributions increase in 2019E as debt 100.0 Debt Service Costs service costs cease as the term loan is 300 d) 100 repaid in Q3 2018 89 88 240.0 77 81 77 250Natural 80 75 G ut (MBp s a hp 63 200 60 56 Throu 47 150 gh Oil Throug 38 tpu ? Full capacity reached in 2019E as 40 de 100 M(M Capacity Reached anchor prospects connect BWOLF and Cru 20 ) cfd Red Zinger tie-in wells 50 — —2017A1Q18A2Q18A3Q18A4Q18A2019E 2020E 2021E 2022E 2023E Crude Oil Volumes (MBpd) Natural Gas Volumes (MMcfd)? Rates step down from $4.50 / Boe to Crude Oil Capacity (MBpd) Natural Gas Capacity (MMcfd) Rate Step-Down $1.50 / Boe when cumulative production reaches 164.4 MBoe AMID’s 35.65% Interest in Total Revenue (projected February 2020) $120.0 $100.0 $89.3 $83.4 $80.0 $8.0 $8.0 Firm Transport ? Monthly fixed rate of $1.87 million $17.6 $16.4 $58.6 $56.7 expires in July 2022 $60.0 $49.8 $8.0 $8.0 $43.7 $0.3 $10.4 $8.0 $40.0 $4.7 $35.1 $18.5 $2.4 $27.6 $63.7 $18.7 $25.8 $59.1 $17.6 $1.7 $15.6 $2.9 $20.0 $40.3 $19.2 $12.2 ? 2021E well connect assumed at a lower type $11.6 $23.0 $21.2 $17.1 $13.7 curve and rate of $1.50 / Boe $11.1 $11.3 $— Tie-Backs 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E ? 2022E well connect assumed at a higher type Anchor FPS – $4.50 / BOE Anchor FPS – $1.50 / BOE curve and rate of $1.50 / Boe Variable Gathering Fixed Gathering Additional Tie-Back – $1.50 / BOE Source: AMID management 39 Asset Overview E Trucking (Texas Panhandle + South Texas) Asset Overview Asset Map ? AMID’s trucking assets (excluding the West Texas trucking assets categorized with the Silver Dollar Perryton, TX Pipeline) include five truckyards and 71 tractors located in South Texas and the Texas Panhandle ? Texas Panhandle tractors being re-deployed to South Texas and Silver Dollar in Q1 2019 Crude Truckyards ? Three truckyards located in Pearsall, Yoakum and Victoria in South Texas Marion, TX Yoakum, TX ? 20 operational trucks with one spare Legend ? Employees and contractors include 26 drivers, two Pearsall, TX Victoria, TX mechanics and one dispatcher Crude truckyard ? One truckyard located in Perryton, Texas in the Liquids truckyard Panhandle ? 20 operational trucks with one spare Volumes (MBpd) ? Employees and contractors include 27 drivers, two mechanics and one dispatcher Decline in 2019E ? Note: Texas Panhandle operations closing in Q1 from shutdown of 2019 and trucks being redeployed in South Texas Texas Panhandle 19.2 operations and 16.0 16.4 16.4 16.4 16.4 and to Silver Dollar 14.7 2.6 redeployment of 2.4 2.4 2.4 2.4 2.4 Liquids Truckyard assets to South 2.1 0.8 Texas and 9.4 ? One truckyard in Marion, Texas in South Texas Permian 6.4 ? 28 operational trucks with one spare 12.8 14.0 14.0 14.0 14.0 ? Employees and contractors include 28 drivers, two 6.2 7.2 mechanics and one dispatcher 2017A 2018A 2019E 2020E 2021E 2022E 2023E South Texas Crude Texas Panhandle Crude Liquids Trucking Source: AMID management, public filings 40

Asset Overview F Bakken Crude Gathering & Marketing Asset Overview Asset Map ? Located in McKenzie and Williams Counties in the Williston Basin, AMID’s FERC-regulated Bakken crude oil gathering system (“Bakken”) consists of: ? 47 miles of 10”, 8”, 6” and 4” pipeline with 40,000 Bpd of capacity ? Commenced operations in October 2015 ? Truck facility used to receive volumes has 10,000 Bpd of capacity and began operating in November 2015 • LACT design with 81 current receipt points ? System holds a 10-year, fee-based, 27,500 acre dedication from Newfield (recently acquired by Encana) ? Sour crude treating (resuming in Q3 2019) ? Pipeline interconnects include: ? Andeavor’s High Plains Pipeline with 15 MBpd contractual and 24 MBpd theoretical capacity ? Dakota Access Pipeline’s 28.8 MBpd contractual capacity Volume (MBpd) 16.3 Legend 14.9 12.5 12.5 AMID System 6.8 10.4 9.2 6.2 Encana 7.3 4.0 5.2 DAPL Pipeline 3.5 4.3 2.9 Andeavor Pipeline 8.5 9.5 8.7 5.6 7.3 6.1 DAPL Interconnect 4.4 Andeavor Interconnect 2017A 2018A 2019E 2020E 2021E 2022E 2023E Trucking Facility Gathered Trucked Source: AMID management, public filings 41 Asset Overview G Silver Dollar (including West Texas Trucking and Marketing) Asset Overview Asset Map ? 161-mile pipeline system purchased in March 2017 as part of AMID’s acquisition of JP Energy Partners LP (“JPEP”) ? Since acquisition, AMID has added approximately 100 miles of pipeline and 100 MBbls of storage capacity to original assets ? Total system throughput capacity of 130 MBpd and storage capacity of approximately 140 MBbls providing operational and market flexibility ? Interconnects to three third-party, long-haul pipelines including a Plains Interconnect to Midland at Owens Station, an Oxy Clineshale Interconnect to Colorado City at Oxy Barnhart Station and the Longhorn Interconnect to East Houston at Magellan Barnhart Station ? 350,000+ net acres committed by more than 30 producers AMID targeting the Spraberry and Wolfcamp formations within a Interconnect 10-mile pipeline connect Truckyard ? Gather from 15 producers including EP Energy Corporation Rig (“EP”), Discovery Natural Resources LLC, Approach Resources, Inc., Henry Energy LP, Hunt Energy Enterprises and Earthstone Energy, Inc. ? Recently commissioned a new pipeline connection for Discovery Natural Resources West Texas Trucking ? Interconnectivity potential with long haul pipelines to ? Truckyard in San Angelo, TX Corpus Christi ? Originally purchased by JPEP in October 2013 from ? 21 operational trucks with one spare ? 31 drivers, two mechanics and one dispatcher employed Wildcat Midstream Mesquite, LLC and Approach ? Eliminating some third party trucking costs by shifting Midstream Holdings, LLC for $212.8 million in cash some Texas Panhandle trucking assets to Silver Dollar Source: AMID management, public filings, DrillingInfo (3/11/19) 42

Asset Overview G Silver Dollar (including West Texas Trucking and Marketing) (cont’d) Volumes (MBpd) 120.0 95.7 99.1 100.0 90.8 82.4 21.2 21.2 80.0 21.2 21.2 60.0 56.1 15.5 40.0 29.5 32.5 74.6 77.9 69.7 0.0 1.7 61.2 20.0 40.5 29.5 30.8 —2017A 2018A 2019E 2020E 2021E 2022E 2023E Gathered Trucking Well Connects by Producer 120.0 100.2 98.3 97.3 94.9 100.0 12.2 12.2 12.2 12.2 3.0 3.0 3.0 3.0 80.0 2.0 6.1 3.0 3.0 7.0 6.1 6.1 4.0 15.0 13.1 12.2 4.0 60.0 47.9 35.3 30.4 30.4 30.4 8.0 40.0 6.0 3.0 20.0 19.0 24.3 24.3 24.3 24.3 9.1 2.8 6.1 6.1 6.1 6.1 —2019E 2020E 2021E 2022E 2023E Approach EP Discovery Henry Hunt Earthstone Sequitur Other Source: AMID management, public filings 43 Asset Overview H Cushing Terminal Asset Overview Asset Map ? Located in Cushing, Oklahoma, with aggregate shell capacity of approximately 3.0 MMBbls, consisting of five 600,000 barrel Mississippian Lime above-ground crude oil storage tanks ? Storage tanks were built in 2009 and are located on the western side of a terminal owned by Enterprise STACK Cushing ? Capable of receiving approximately 18,000 barrels of crude oil Granite Wash per hour or delivering 8,000 barrels of crude oil per hour SCOOP ? Terminal is operated by TEPPCO Partners, LP, a wholly-owned subsidiary of Enterprise, under a 50-year lease ? Connectivity to major receipt (Enbridge, Plains) and delivery (Seaway, Magellan and Osage) pipelines ? 653 work is underway and expected to be completed by 2H 2019 ? Generates crude oil storage revenues by charging a fixed monthly take-or-pay fee per barrel of shell capacity ? Crude futures modestly contango at present Asset Summary Cushing Terminal Site Location Cushing, OK Product Crude Oil Capacity (MBbls) 3,000 Facilities 5 above-ground storage tanks Transportation Modes Pipeline Key Customers Crude marketer and trader Source: AMID management, public filings 44

Asset Overview H Cushing Terminal (cont’d) Cushing Storage Overview Cushing Inventories versus Capacity ? The North American crude oil market is currently in 100,000 contango, which has led to growth in crude oil storage at Cushing and selling forward of growing quantities of 77,228 80,000 crude oil ? Inventories at Cushing were at an all-time high of 69,420 ls 60,000 46,8511 MBbls on April 7, 2017 and declined to a three-year low Bb 61% of Capacity M of 21,803 MBbls on August 3, 2018 40,000? Cushing inventories have since rebounded marginally, 20,000 increasing weekly since August 3, 2018—? Crude oil inventory declined by 672 MBbls to 46,851 Mar-11 May-12 Jul-13 Aug-14 Oct-15 Nov-16 Jan-18 Feb-19 in early March 2019 after having increased for four Capacity (MBbls) Crude Oil Stock (MBbls) consecutive weeks by approximately 4 MBbls to 47,523 MBbls WTI Forward Price vs. Current ($58.52 2) Projected WTI Forward 12-Month Spread2 $1.50 $1.43 $1.00 $0.50 $0.92 $-$0.68 $(0.50) $0.30 $(1.00) $(1.50) $(2.00) 1-Month 3-Month 6-Month 12-Month Apr-19 Sep-19 Mar-20 Sep-20 Mar-21 Sep-21 Apr-22 Source: EIA, Bloomberg 1. As of March 8, 2019 2. As of March 15, 2019 45 Asset Overview I NGL Pipeline Interests AMID’s NGL pipeline interests flow nearly 100% of the total Y-grade volumes in the Eastern GoM Asset Overview Asset Map ? AMID owns a 50.0% interest in the Cayenne System (“Cayenne”) Williams with Targa Resources Corporation (“Targa”) owning the remainder Mobile Bay Cayenne? Cayenne commenced operations in late December 2017 BRF ? 63-mile pipeline transporting Y-grade NGLs from the 750 MMcfd Venice Gas Processing Plant (“Venice”) to Enterprise’s pipeline at Pascagoula Toca, Louisiana for delivery to Enterprise’s Norco Fractionator Sorrento ? 15-year commitments by Targa and Enterprise from Venice Norco ? Initial capacity of 40,000+ Bpd with the ability to throughput 50,000+ Bpd; 2018 volumes exceeding projections ? AMID acquired a 16.7% interest in the Tri-States system (“Tri- Venice States”) in April 2016 ? FERC-regulated 161-mile 12- and 16-inch NGL pipeline Legend Cayenne ? 80,000 Bpd of transport capacity and operated by Enterprise Tri-States ? Receives NGLs from the Pascagoula Plant, the Williams Mobile Bay Wilprise Tri-States Plant and the DCP Mobile Bay Plant and terminates at Kenner Plant Junction, feeding Enterprise’s Norco fractionation facility and two NGL pipelines including the Wilprise Pipeline (“Wilprise”) ? In April 2016, AMID acquired a 25.3% interest in the Wilprise system Wilprise operated by Enterprise ? FERC-regulated 30-mile NGL pipeline originating at the Kenner Junction and terminating in Sorrento, LA where volumes flow via pipeline to the Baton Rouge Fractionator (“BRF”) operated by Enterprise ? 60,000 Bbld of transport capacity Source: AMID management, public filings 1. BRF ownership only 46

Asset Overview I NGL Pipeline Interests (cont’d) Volumes (MBpd) 140.0 120.9 123.8 120.6 117.1 120.0 112.1 104.5 32.9 31.9 31.9 100.0 36.7 28.2 87.8 25.0 80.0 34.0 55.1 57.1 60.0 55.9 50.4 54.8 53.7 40.0 53.8 20.0 33.9 33.9 30.0 32.8 29.1 25.8 — 2017A 2018A 2019E 2020E 2021E 2022E 2023E Cayenne (50.0% Ownership) Tri States (16.7% Ownership) Wilprise (25.3% Ownership) Source: AMID management, public filings 47 IV. AMID Financial Projections

AMID Financial Projections AMID Financial Projections – Assumptions ? The AMID Financial Projections utilized herein by Evercore incorporate the following AMID management assumptions: ? 2018A actuals ? Revenue / Expenses: • 2018A – 2023E revenue and expenses per 2019 budget and AMID’s five-year forecast • $1.50 / Boe fee for Nearly Headless Nick additional tie-in well at Delta House, representing the anchor producer rate per AMID management • $4.3 million of G&A savings in 2019E and $9.3 million of G&A savings in 2020E – 2023E ? Growth Projects: • Expansion of Longview facility for $70.0 million • Incremental compression for AlaTenn for $6.5 million • The Bamagas Ascend connection for $1.6 million ? Acquisitions: • Acquisition of the Pascagoula Gas Plant for $36.3 million in April 2019 ? Financing Assumptions: • Revolving credit facility maturing on September 5, 2019 is extended at the same terms • Refinancing of 8.50% 2021 Senior Notes at the same terms—Also, per management, 2021 Senior Notes assumed to be registered and remain at 8.50% interest rate • Excess cash flow utilized to repay revolving credit facility ? Distribution policy • No common cash distributions after Q3 2018 and preferred equity distributions PIK Source: AMID management 48 AMID Financial Projections AMID Financial Projections – Assumptions ? Set forth below are the pricing assumptions incorporated in the AMID Financial Projections: Years Ending December 31, 2018A 2019E 2020E 2021E 2022E 2023E Natural Gas $/MMBtu $3.16 $2.74 $2.73 $2.65 $2.66 $2.73 Crude Oil $/Bbl 64.77 55.61 56.50 55.12 54.17 53.78 Mont Belvieu NGLs Ethane $/Gal $0.33 $0.30 $0.28 $0.27 $0.27 $0.27 Propane $/Gal 0.88 0.66 0.64 0.63 0.63 0.64 Isobutane $/Gal 1.09 0.80 0.73 0.72 0.71 0.70 Normal Butane $/Gal 1.02 0.79 0.72 0.72 0.72 0.71 Pentanes + $/Gal 1.43 1.15 1.15 1.11 1.10 1.09 Condensate $/Gal 1.43 1.15 1.15 1.11 1.10 1.09 Strip Pricing as of March 15, 2019 Henry Hub Natural Gas $/MMBtu $3.14 $2.91 $2.77 $2.65 $2.67 $2.76 WTI Crude Oil $/Bbl 64.82 58.28 58.76 56.78 55.30 54.59 Source: AMID management 49

AMID Financial Projections AMID Financial Projections – Assumptions (cont’d) Business / Segment AMID Financial Projections A ? 55 wells annually connected to the Lavaca system ? 5 – 10 wells connected annually to the Yellow Rose system, resulting in run-rate volumes of 17 MMcfd Gathering & Processing ? 1 – 2 wells connected annually to the Longview system ? 1 well connected annually to the Chapel Hill system B ? 1.2 Bcfd of firm transportation ? Midla / MLGT rate increase on Natchez lateral to $17.64 per Dth/ month in April 2019 from current rate of $8.82 Dth/month and an Natural Gas Transportation additional increase to $26.47 Dth/month in April 2021 ? Additional compression installed at AlaTenn in 2019 at project cost of $6.5 million and incremental EBITDA of $1.0 million C ? 10.0% annual decline in volumes Offshore Pipelines ? 12 days of hurricane downtime per year (excl. Delta House) ? 5.0% unplanned downtime in addition to known platform turnarounds D ? Includes new tie back to BWOLF, Red Zinger and two additional new tiebacks (including Nearly Headless Nick) in 2021 & 2022, the first at a lower type curve, the second at a higher type curve with both at the anchor producer rate of $1.50 / Boe per AMID Delta House management ? 2019 volumes based upon production data provided by LLOG reduced by 5% for unplanned downtime and 12 hurricane days ? 2020E – 2023E production profile based upon Nov-18 NSAI P50 reserves study E ? 2019E South Texas volume of 12.8 MBpd, 2020E – 2023E volume of 14.0 MBpd ? 2019E liquids trucking volume of 2.4 MBpd, 2020E – 2023E volume of 2.4 MBpd Trucking ? Elimination of Texas Panhandle trucking in January 2019 (Texas Panhandle + South Texas) Source: AMID management 50 AMID Financial Projections AMID Financial Projections – Assumptions (cont’d) Business / Segment AMID Financial Projections F ? Volume reaches peak of 9.5 MBpd gathered and 6.8 MBpd trucked in 2020E Bakken Crude Gathering & ? 16.6% annual decline in volumes beginning in January 2021E Marketing G ? The following well connect schedule 2019E 2020E 2021E 2022E 2023E Approach 2.8 6.1 6.1 6.1 6.1 Silver Dollar EP 9.1 24.3 24.3 24.3 24.3 (including West Texas Trucking Discovery 19.0 35.3 30.4 30.4 30.4 Henry 3.0 4.0 15.0 13.1 12.2 and Marketing) Hunt 6.0 4.0 6.1 6.1 6.1 Earthstone 8.0 7.0 3.0 3.0 3.0 Sequitur — 2.0 3.0 3.0 3.0 Other — 12.2 12.2 12.2 12.2 Wells Connected 47.9 94.9 100.2 98.3 97.3 H ? Maintenance underway and is scheduled to be completed in 2H 2019 Cushing ? Revenue reduced at Cushing until maintenance completed in 2H 2019 Terminal I ? 33.9 MBpd throughput at Cayenne through July 2020, 1% monthly decline in volumes thereafter NGL JV Interests ? 2% annual decline in Tri-State volumes beginning in January 2021 ? 1% monthly decline in Wilprise volumes beginning in January 2021 (Wilprise, Tri-States, Cayenne) Source: AMID management 51

AMID Financial Projections Identified Growth Opportunities (Included in AMID Financial Projections) ($ in millions) Implied Run-Incremental Incremental Rate EBITDA Project Description Growth Capex EBITDA Multiple ? Improve proportion of on-spec processing and rail volumes 2019 $43.0 $ – – Longview ? Build additional truck / rail sales outlets 1 2020 27.0 6.8 10.4x Expansion ? Secure Y-grade volumes via pipe and increase fractionation capacity and capabilities for purity products 2021 – 11.6 6.1x ? In August 2018, AMID announced an agreement with 2019 $36.3 $4.8 7.5x Acquisition of Enterprise for a 25% stake in the Pascagoula gas plant Interest in ? Comprises three trains with approximately 1.5 Bcfd of 2020 – 7.1 5.1x 2 processing capacity Pascagoula ? Conditions include completion of modifications to certain Gas Plant facilities on the High Point system 2021 – 6.7 5.4x ? Potential to add incremental compression 2019 $6.5 $0.1 NM AlaTenn 2020 – 0.7 9.5x 3 Compression 2021 – 1.0 6.5x Bamagas – ? Lateral pipeline connection to Ascend 2019 $0.7 $0.4 3.7x 4 Ascend 2020 – 0.6 2.6x Connection 2021 – 0.7 2.4x Source: AMID management, public filings 52 AMID Financial Projections Gathering & Processing ($ in millions) Volume (MMcfd) Asset EBITDA 385.6 $68.6 $71.8 $73.1 361.5 $59.7 334.5 299.4 247.0 $38.6 164.9 189.0 $24.5 $11.0 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Total Capital Expenditures1 Free Cash Flow $106.7 $42.7 $45.1 $36.2 $1.7 $58.0 ($4.1) ($10.6) $35.1 $32.4 $29.1 $28.1 $15.1 2017A 2018A 2019E 2020E 2021E 2022E 2023E ($68.2) 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 1. 2019E capital expenditures include Longview Expansion, acquisition of interest in the Pascagoula Plant and well connects to Lavaca and Yellow Rose 53

AMID Financial Projections Natural Gas Transportation ($ in millions) Volume (BBtud) Asset EBITDA 2018A to 2019E EBITDA decline driven by interruptible volume and non-recurring marketing fuel gains in 2018A 1.26 $27.9 1.24 $25.2 $26.0 $26.0 1.20 1.20 1.20 $22.3 $23.5 1.17 1.18 $18.3 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Total Capital Expenditures Free Cash Flow $23.0 $22.5 $22.5 $20.8 $35.4 $18.9 $10.6 $11.7 $4.9 $4.6 $4.4 $3.5 $3.5 ($17.1) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 54 AMID Financial Projections Offshore Pipelines (excluding Delta House) ($ in millions) Volume (MMBtud) Asset EBITDA1 1.74 1.80 1.69 1.61 1.49 1.46 $81.7 $78.4 $75.1 $70.6 $65.0 $57.8 2018A 2019E 2020E 2021E 2022E 2023E 2018A 2019E 2020E 2021E 2022E 2023E Total Capital Expenditures1 Free Cash Flow1 2 $26.0 $72.8 $66.6 $64.5 $59.3 $56.1 $52.2 $11.7 $4.4 $4.4 $4.4 $4.4 2018A 2019E 2020E 2021E 2022E 2023E 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 1. Pro rata for AMID’s 66.7% interest in Okeanos and Destin 2. Includes distributions from Okeanos and Destin based on preceding quarter’s free cash flow 55

AMID Financial Projections Delta House ($ in millions) Volume (MBoed) Asset EBITDA (35.65%) 1 $89.3 $85.9 118.7 118.1 106.7 110.9 104.6 102.3 $58.3 $56.4 81.0 72.5 $49.6 $43.5 65.5 $34.9 $27.4 $25.5 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E Class A Distributions2 (35.65% interest) Production significantly curtailed through $86.7 2Q 2018 due to remedial work on third party upstream infrastructure $63.5 $47.7 $43.7 $44.3 $40.2 $34.4 $27.9 $24.3 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E Source: AMID management 1. Inclusive of deferred revenue 2. Includes change in working capital and deferred revenue 56 AMID Financial Projections Trucking (South Texas + Liquids) ($ in millions) Volume (MBoed) Asset EBITDA 19.2 16.0 16.4 16.4 16.4 16.4 14.7 ($1.0) ($1.0) ($1.0) ($1.0) ($1.1) ($1.1) ($1.9) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Free Cash Flow ($1.1) ($1.0) ($1.0) ($1.0) ($1.0) ($1.1) ($1.9) 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management Note: 2017A, 2018A and January 2019E includes Texas Panhandle operations 57

AMID Financial Projections Bakken Crude Gathering & Marketing ($ in millions) Volume (MBoed) Asset EBITDA 16.3 14.9 $4.4 12.5 12.5 $3.8 $3.6 6.8 6.2 10.4 9.2 $2.9 4.0 5.2 7.3 $2.1 4.3 3.5 2.9 9.5 $1.3 8.5 8.7 $0.7 7.3 6.1 4.4 5.6 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Volumes Gathered (MBpd) Volumes Trucked (MBpd) Total Capital Expenditures Free Cash Flow $2.7 $4.3 $3.7 $3.5 $2.8 $2.0 $1.2 $0.1 $0.1 $0.1 $0.1 $0.1 $0.1 ($1.7) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 58 AMID Financial Projections Silver Dollar (including West Texas Trucking and Marketing) ($ in millions) Volume (MBoed) Asset EBITDA 99.1 95.7 90.8 82.4 $22.7 21.2 $22.0 $22.1 21.2 21.2 $19.3 21.2 56.1 $16.8 $16.1 15.5 32.5 $10.0 29.5 77.9 1.7 69.7 74.6 61.2 40.5 29.5 30.8 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Volumes Gathered (MBpd) Volumes Trucked (MBpd) Total Capital Expenditures Free Cash Flow $22.3 $14.1 $14.8 $21.5 $21.7 $13.1 $10.6 $6.2 $6.2 $2.0 $0.5 $0.4 $0.4 ($4.8) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 59

AMID Financial Projections Cushing Terminal ($ in millions, except per unit amounts) Available Storage Capacity (MMbls) Asset EBITDA / Rate per Barrel $10.0 $0.25 $8.0 $0.20 $0.20 3.0 3.0 3.0 3.0 $0.20 $0.20 M $8.0 $0.20 2.6 M) 2.4 ($ $6.0 R A EBITD at $4.5 $4.5 $4.5 $4.5 $0.15 e ($ $0.12 $0.10 1.3 $4.0 / et s Bbl As $0.10 ) $2.0 $1.0 $— $0.05 2017A 2018A 2019E 2020E 2021E 2022E 2023E ($1.1) ($2.0) $—2017A 2018A 2019E 2020E 2021E 2022E 2023E Total Capital Expenditures Free Cash Flow $3.8 $3.4 $8.0 $4.5 $4.5 $4.5 $4.5 ($2.4) $— $— $— $— $— ($4.9) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 60 AMID Financial Projections NGL Pipeline Interests (Wilprise, Tri-States, Cayenne) ($ in millions) Volume (MBoed) Asset EBITDA1 120.9 123.8 120.6 117.1 $15.8 112.1 104.5 $15.3 $15.4 $13.8 $14.2 87.8 $13.2 $8.1 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Distributions1 $15.7 $15.5 $15.2 $14.4 $13.4 $11.1 $7.3 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 1. Pro rata for AMID’s 25.3% ownership of Wilprise, 16.7% ownership of Tri-States and 50.0% ownership of Cayenne 61

AMID Financial Projections Summary Financial Overview – AMID Financial Projections ($ in millions) Asset EBITDA / Adjusted EBITDA / Pro Forma Adjusted EBITDA (2018A only) $264.0 / $214.1 $249.8 / $194.7 $4.5 $252.4 / $202.5 $245.8 / $195.8 $15.7 $4.5 $15.2 $4.4 $15.5 $4.5 $229.1 / $179.1 $223.8 / $184.0 / $159.1 $3.6 $14.4 $10.0 $19.3 $3.8 $4.5 $2.9 $22.0 $13.4 $25.1 $22.3 $23.5 $22.1 $2.1 $11.1 $25.2 $22.7 $1.3 $26.0 $16.1 $38.6 $26.0 $27.9 $59.7 $68.6 $24.5 $71.8 $73.1 $86.7 $63.5 $40.2 $47.7 $44.3 $34.4 $79.6 $75.5 $74.5 $66.1 $60.9 $53.9 1 1 2018A 2019E 2020E 2021E 2022E 2023E 1 Offshore Pipelines (Includes Distributions from Destin and Okeanos) Distributions from Delta House Natural Gas Gathering and Processing Natural Gas Transportation Silver Dollar Pipeline Bakken Crude Oil Gathering NGL Pipeline JV Distributions Terminals Trucking Source: AMID Management 1. Distribution based on preceding quarter’s free cash flow 62 AMID Financial Projections Summary Financial Overview – AMID Financial Projections (cont’d) ($ in millions, except for per unit amounts) Capital Expenditures & Acquisitions Distributable Cash Flow / DCF per LP Unit 2018A-2023E CAGR: 19.6% $129.5 $124.1 $121.9 $108.2 $151.0 $98.3 $69.2 $95.2 $79.9 $41.5 $37.6 $36.6 2018A 2019E 2020E 2021E 2022E 2023E 2018A 2019E 2020E 2021E 2022E 2023E DCF per LP Unit1, 2 $0.70 $1.21 $1.51 $1.41 $1.34 $1.07 Consolidated Debt / Pro Forma Adjusted EBITDA1 6.7x 5.8x 5.0x 4.9x 4.5x 3.5x 4.5x 2.8x 2.5x 2.7x 2.7x 2.9x 3.2x 3.0x 2.5x 2.2x 1.8x 1.6x 2018A 2019E 2020E 2021E 2022E 2023E Senior Secured Unsecured Source: AMID Management 1. Pro forma for sale of refined products terminals to Sunoco, LP and assumes cash proceeds used to repay revolving credit facility and fund growth capital expenditures 2. Assumes conversion of Series A-1, Series A-2 and Series C Preferred Units convert into 23,359,144 common units and 698,994 common units are issued per quarter beginning in Q4 2018 for accrued and unpaid distributions on an as-converted basis 63

AMID Financial Projections AMID Financial Projections ($ in millions, except per unit metrics) For the Years Ending December 31, CAGR 2018A 2019E 2020E 2021E 2022E 2023E 2018A—2023E Offshore Pipelines (Distributions from Destin and Okeanos)1 $79.6 $75.5 $74.5 $66.1 $60.9 $53.9 Distributions from Delta House1 40.2 86.7 63.5 47.7 44.3 34.4 Natural Gas Gathering and Processing 24.5 38.6 59.7 68.6 71.8 73.1 Natural Gas Transportation 27.9 22.3 23.5 25.2 26.0 26.0 Silver Dollar Pipeline 16.1 10.0 19.3 22.0 22.1 22.7 Bakken Crude Oil Gathering 1.3 3.6 4.4 3.8 2.9 2.1 NGL Pipeline JV Distributions1 11.1 15.2 15.7 15.5 14.4 13.4 Terminals 25.1 (1.1) 4.5 4.5 4.5 4.5 Trucking (1.9) (1.1) (1.0) (1.0) (1.0) (1.0) Asset EBITDA $223.8 $249.8 $264.0 $252.4 $245.8 $229.1 0.5% Less: Corporate G&A (56.4) (55.0) (49.8) (49.8) (49.8) (49.8) Less: Delta House Distribution Support 17.7 — — — — — Less: Other (1.1) (0.1) (0.1) (0.1) (0.1) (0.1) Adjusted EBITDA $184.0 $194.7 $214.1 $202.5 $195.8 $179.1 (0.5%) Less: Refined Products and Marine Terminals EBITDA (24.9) — — — — — Pro Forma Adjusted EBITDA $159.1 $194.7 $214.1 $202.5 $195.8 $179.1 2.4% Less: Interest Expense (73.8) (76.4) (73.3) (67.2) (62.4) (59.3) Less: Preferred Distributions (25.1) — — — — —Less: Maintenance Capital Expenditures (16.0) (19.9) (11.3) (11.2) (11.5) (11.5) Pro Forma Distributable Cash Flow $44.2 $98.3 $129.5 $124.1 $121.9 $108.2 19.6% Distributable Cash Flow $69.2 $98.3 $129.5 $124.1 $121.9 $108.2 Distributed Cash Flow Common Units—Public $25.1 $— $— $— $— $—Common Units—Parent 8.2 — — — — —GP 0.4 — — — — — Distributed Cash Flow $33.8 $— $— $— $— $— Current IDR Tier 1.3% 1.3% 1.3% 1.3% 1.3% 1.3% % to GP 1.3% 1.3% 1.3% 1.3% 1.3% 1.3% GP IDRs $— $— $— $— $— $—Weighted Average LP Units Outstanding 54.0 54.7 55.1 55.4 55.7 66.3 Weighted Average LP Units Outstanding – As Converted2 60.0 80.4 83.5 86.6 89.6 102.9 DCF / LP Unit3 $1.26 $1.66 $1.99 $1.94 $1.91 $1.61 5.0% Distribution per LP Unit 0.62 — — — — — NA DCF / LP Unit – As Converted2 3 $0.70 $1.21 $1.51 $1.41 $1.34 $1.07 8.7% Distribution per LP Unit 0.62 — — — — — NA LP Coverage 2.04x NA NA NA NA NA Total Coverage 2.05 NA NA NA NA NA Source: AMID Management 1. Distribution based on preceding quarter’s free cash flow 2. Assumes conversion of Series A-1, Series A-2 and Series C Preferred Units convert into 23,359,144 common units and 698,994 common units are issued per quarter beginning in Q4 2018 for accrued and unpaid distributions on an as-converted basis 3. Pro forma for sale of refined products terminals to Sunoco, LP 64 AMID Financial Projections AMID Financial Projections (cont’d) ($ in millions) For the Years Ending December 31, 2018A 2019E 2020E 2021E 2022E 2023E Sources Distributable Cash Flow Surplus / (Shortfall) $98.3 $129.5 $124.1 $121.9 $108.2 Asset Sales — — — — — Cash from Balance Sheet — — — — — Total Sources $98.3 $129.5 $124.1 $121.9 $108.2 Uses Growth Capital Expenditures $94.8 $68.6 $30.4 $26.1 $25.1 Acquisition of Pascagoula Gas Plant 36.3 — — — —Sale of Blackwater Tax Payment 23.7 — — — —Amortization of Non-Recourse Debt 4.0 4.2 6.3 6.5 6.7 Other Expenses 13.6 2.7 1.8 1.4 1.3 Change in Revolver (73.2) 54.2 85.7 88.2 75.5 Cash to Balance Sheet 0.0 0.0 0.0 0.0 0.0 Other (0.9) (0.1) (0.0) (0.2) (0.4) Total Uses $98.3 $129.5 $124.1 $121.9 $108.2 Capitalization Cash $9.1 $9.1 $9.1 $9.1 $9.1 $9.1 Revolving Credit Facility 514.8 588.0 533.8 448.1 359.9 284.4 Midla / TransUnion Notes 87.8 83.7 79.6 73.3 66.7 60.0 8.500% Senior Notes 425.0 425.0 425.0 425.0 425.0 425.0 Letter of Credit 39.0 39.0 39.0 39.0 39.0 39.0 Net Debt $1,057.5 $1,126.7 $1,068.4 $976.3 $881.6 $799.4 Credit Metrics1 Total Consolidated Debt / Pro Forma Adjusted EBITDA 6.7x 5.8x 5.0x 4.9x 4.5x 4.5x Net Consolidated Debt / Pro Forma Adjusted EBITDA 6.6 5.8 5.0 4.8 4.5 4.5 Senior Secured / Pro Forma Adjusted EBITDA 3.2 3.0 2.5 2.2 1.8 1.6 First Lien Leverage 3.2x 3.2x 2.6x 2.3x 1.9x 1.7x Total Covenant Leverage 5.8 5.5 4.7 4.5 4.2 4.2 Source: AMID Management 1. Pro forma for sale of refined products terminals to Sunoco, LP and assumes cash proceeds used to repay revolving credit facility and fund growth capital expenditures 65

V. Preliminary Valuation Preliminary Valuation Summary Valuation – AMID Common Unit ($ in millions, except per unit amounts) For Reference Only Total Partnership Sum of the Parts Peer Trading Analysis Peer Trading Analysis MLP Premiums Paid Discounted Cash Flow Discounted Cash Flow Precedent M&A Analysis Analysis Analysis 2019E 2020E 2019E 2020E $20.00 Implied MLP Premiums Paid based on September 27, 2018 Consideration: $5.25 per Common Unit Implied MLP Premiums Paid based on January 3, 2019 $15.00 $10.00 $8.09 $8.12 $7.08 $6.06 $6.34 $5.52 $5.75 $5.00 $3.47 $1.67 $1.00 $— $0.42 $— $— $— $— $— $— ($5.00) Adjusted 2019E EBITDA Adjusted 2019E EBITDA Adjusted 2020E EBITDA Adjusted 2019E EBITDA Adjusted 2019E EBITDA Adjusted 2019E EBITDA Adjusted 2020E EBITDA $194.7 $194.7 $214.1 $194.7 $194.7 $194.7 $214.1 Adjusted 2023E EBITDA Adjusted 2023E EBITDA Adjusted 2020E EBITDA $179.1 $179.1 $214.1 66

Preliminary Valuation Valuation Methodologies ? The following sets forth the methodologies utilized by Evercore in its preliminary valuation of AMID Common Units, each assuming a June 30, 2019 closing date Methodology Description Metrics/Assumptions ? Values AMID common units based on the concept of the ? Discounted the projected cash flows to June 30, 2019 time value of money ? EBITDA exit multiple of 9.0x to 11.0x ? Utilizing the AMID Financial Projections herein, Evercore: ? Perpetuity growth rate of 1.75% to 2.25% Total ? Utilized varying WACC discount rates and ? WACC of 8.5% to 9.5% based on capital asset pricing model (“CAPM”) for natural Partnership applied various perpetuity growth rates to derive gathering processing and offshore partnerships and companies Discounted after-tax valuation ranges for AMID ? Unitholder effective tax rate of 29.6% (80.0% at 37.0% top bracket) from 2019E to Cash Flow ? Calculated terminal values based on a range of 2023E and a terminal value tax rate of 37.0% Analysis multiples of EBITDA as well as assumed ? For the terminal value, tax depreciation assumed to be equal to maintenance perpetuity growth rates capital expenditures ? Values AMID common units based on current market ? Enterprise value / EBITDA multiples applied to 2019E and 2020E adjusted EBITDA enterprise value multiples of relevant EBITDA of selected for all EBITDA excluding Delta House Total Partnership comparable natural gas gathering and processing and ? Enterprise value / EBITDA multiples applied to 2025E Delta House EBITDA, based Peer Group offshore partnerships and companies on stepdown in anchor rate from $4.50 per Boe to $1.50 per Boe in 2020E, Trading Analysis expiration of fixed gathering revenues in 2022E and peak production of second tie-in well in 2025E; Delta House cash flows from June 30, 2019E to 2024E in excess of 2025E cash flow levels discounted at 8.5% WACC ? Values AMID common units based on the sum of the ? Discounted the projected cash flows to June 30, 2019 valuation of each business unit and corporate liabilities ? WACC based on CAPM for partnerships and companies with similar assets Sum of the Parts implied by the discounted cash flow of each business unit ? Unitholder effective tax rate of 29.6% (80.0% at 37.0% top bracket) from 2019E to Discounted Cash and the company as a whole 2023E and a terminal value tax rate of 37.0% Flow Analysis ? For the terminal value, tax depreciation assumed to be equal to maintenance capital expenditures Sum of the Parts ? Values AMID common units based on the sum of the ? Enterprise value / EBITDA multiples applied to 2019E and 2020E EBITDA Precedent M&A valuation of each business unit and corporate liabilities Analysis implied by historical transactions of similar assets ? Values AMID common units based on the sum of the ? Enterprise value / EBITDA multiples applied to 2019E and 2020E EBITDA Sum of the Parts valuation of each business unit and corporate liabilities Peer Group implied by the current market enterprise value multiples of Trading Analysis relevant EBITDA for partnerships and companies with similar assets For Premiums Paid ? Values AMID common units based on historical premiums ? Median 30-Day, 60-Day and 90-Day premiums paid applied to relevant unit prices Reference Only Analysis ? paid in (i) MLP buy-ins and (ii) MLP mergers since 2011 67 Preliminary Valuation Summary Valuation – Total Partnership Analysis – AMID Common Unit Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis 2019E 2020E $15.00 $11.00 $7.08 $7.00 $6.06 $3.00 $1.67 $— $— $— ($1.00) ($5.00) 8.5% – 9.5% WACC 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth All Assets Other than Delta House: All Assets Other than Delta House: Multiple: Rate: 2019E EBITDA Multiple: 2020E EBITDA Multiple: 9.0x – 11.0x 1.75% – 2.25% 9.0x – 11.0x 7.5x – 9.5x Delta House: Delta House: 2025E EBITDA Multiple: 8.5x—10.5x 2025E EBITDA Multiple: 7.5x—10.5x June 30, 2019E – December 31, 2024E Cash Flow in Excess of 2025E Cash Flow Discounted at Midpoint 8.5% WACC Source: AMID Management 68

Preliminary Valuation Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to analyze AMID’s discounted cash flows: ? Discounted the projected cash flows to June 30, 2019 ? EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections assuming no asset sales ? Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) ? Mid-point discount rate of 9.0% utilizing WACC based on CAPM ? Terminal value based on a (i) 9.0x to 11.0x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate • Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 69 Preliminary Valuation Total Partnership – Discounted Cash Flow Analysis ($ in millions, except per unit amounts) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth Adjusted EBITDA $103.4 $214.1 $202.5 $195.8 $179.1 $179.1 $179.1 Less: Tax Depreciation and Amortization (1,690.9) (79.9) (41.5) (37.6) (29.3) (11.5) EBIT ($1,587.6) $134.2 $161.0 $158.3 $149.8 $167.6 Less: Cash Taxes — (6.4) (7.6) (7.5) (7.1) (62.0) EBIAT ($1,587.6) $127.8 $153.3 $150.8 $142.7 $105.6 Plus: Tax Depreciation and Amortization 1,690.9 79.9 41.5 37.6 29.3 11.5 Less: Growth Capital Expenditures (58.2) (68.6) (30.4) (26.1) (25.1) —Less: Maintenance Capital Expenditures (8.2) (11.3) (11.2) (11.5) (11.5) (11.5) Unlevered Free Cash Flow $37.0 $127.8 $153.3 $150.8 $135.4 $105.6 EBITDA Multiple / Perpetuity Growth Rate 10.0x 2.0% Terminal Value $1,791.2 $1,538.4 PV of Terminal Value @ 9.0% Discount Rate $1,215.4 $1,043.9 Plus: PV of Unlevered Free Cash Flow @ 9.0% Discount Rate 494.9 Implied Enterprise Value $1,710.3 $1,538.8 Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (142.3) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (60.9) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (137.2) Total Common Equity Value $237.5 $65.9 Estimated Total Units Outstanding as of June 30, 20191 55.4 Value per LP Unit $4.29 $1.19 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 8.0x 9.0x 10.0x 11.0x 12.0x 1.75% 1.75% 2.00% 2.25% 2.25% 8.0% $0.83 $3.12 $5.40 $7.69 $9.98 8.0% $4.48 $4.48 $5.45 $6.50 $6.50 WACC 8.5% 0.36 2.60 4.84 7.08 9.32 WACC 8.5% 2.34 2.34 3.16 4.04 4.04 9.0% (0.10) 2.09 4.29 6.48 8.67 9.0% 0.50 0.50 1.19 1.94 1.94 9.5% (0.55) 1.60 3.75 5.90 8.04 9.5% (1.11) (1.11) (0.52) 0.12 0.12 10.0% (0.99) 1.12 3.22 5.33 7.43 10.0% (2.53) (2.53) (2.01) (1.46) (1.46) 1. As of June 30, 2019 and includes 980,889 general partner units and 381,149 LTIP units issued from March 2019 to June 2019 70

Preliminary Valuation Peer Group Trading ($ in millions, except per unit or share amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/15/19 Value Value 2019E 2020E Current 2019E Growth Return Natural Gas Gathering and Processing CNX Midstream Partners LP $14.61 $948.9 $1,490.1 7.0x 6.0x 9.9% 10.7% 8.8% 18.7% Crestwood Equity Partners LP 34.15 2,432.2 4,977.9 10.4 9.2 7.0% 7.0% 3.6% 10.6% DCP Midstream Partners, LP 31.14 4,554.0 10,640.4 8.9 7.8 10.0% 10.0% 1.6% 11.7% Enable Midstream Partners, LP 14.59 6,321.1 10,991.1 9.6 9.5 8.7% 8.7% 3.7% 12.4% Hess Midstream Partners LP 22.33 1,243.6 1,223.3 11.0 9.2 6.6% 7.3% 11.3% 17.9% Noble Midstream Partners LP 37.25 1,482.1 2,774.6 10.3 7.5 6.3% 7.1% 17.7% 24.0% Summit Midstream Partners, LP 9.33 781.0 2,647.1 8.5 8.1 24.7% 24.7% NM NM Targa Resources Corp. 40.04 9,295.0 15,918.1 12.9 10.2 9.1% 9.1% 2.6% 11.7% Mean 9.8x 8.4x 10.3% 10.6% 7.0% 15.3% Median 10.0 8.6 8.9% 8.9% 3.7% 12.4% Offshore Pipelines Plains All American Pipeline, L.P. $24.30 $17,655.9 $29,090.9 10.6x 10.5x 4.9% 5.4% 9.6% 14.5% Genesis Energy, L.P. 22.62 2,771.8 6,955.5 10.0 9.5 9.5% 9.7% 0.5% 10.0% Shell Midstream Partners, L.P. 19.24 4,394.0 6,327.2 8.6 7.4 8.3% 8.9% 4.4% 12.7% Mean 9.7x 9.1x 7.6% 8.0% 4.8% 12.4% Median 10.0 9.5 8.3% 8.9% 4.4% 12.7% Source: FactSet, Public filings 71 Preliminary Valuation Total Partnership – Peer Group Trading Analysis ($ in millions, except per unit amounts) 2019E Summary Results Adjusted 2019E EBITDA $194.7 Less: 2019E Class A Distributions from Delta House (86.7) Run Rate 2019E Adjusted EBITDA $107.9 Relevant EBITDA Multiple 9.0x—11.0x Implied Enterprise Value (All Assets Other than Delta House) $971.3—$1,187.2 2025E Delta House EBITDA1 $25.5 Relevant EBITDA Multiple 8.5x—10.5x Implied Delta House Enterprise Value $216.8—$267.8 A Plus: Present Value of Delta House Cash Flows from June 30, 2019E to December 31, 2024E in excess of 2025E Cash Flows at 8.5% 110.3 Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (142.3) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (60.9) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (137.2) Total Common Equity Value ($174.4)—$92.4 Estimated Total Units Outstanding as of June 30, 20192 55.4 Value per LP Unit ($3.15)—$1.67 2020E Summary Results Adjusted 2020E EBITDA $214.1 Less: 2020E Class A Distributions from Delta House (63.5) Run Rate 2020E Adjusted EBITDA $150.6 Relevant EBITDA Multiple 7.5x—9.5x Implied Enterprise Value (All Assets Other than Delta House) $1,129.5—$1,430.7 2025E Delta House EBITDA1 $25.5 Relevant EBITDA Multiple 7.5x—10.5x Implied Delta House Enterprise Value $191.3—$267.8 A Plus: Present Value of Delta House Cash Flows from June 30, 2019E to December 31, 2024E in excess of 2025E Cash Flows at 8.5% 110.3 Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (142.3) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (60.9) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (137.2) Total Common Equity Value ($41.8)—$335.9 Estimated Total Units Outstanding as of June 30, 20192 55.4 Value per LP Unit ($0.75)—$6.06 1. Inclusive of deferred revenue 2. As of June 30, 2019 and includes 980,889 general partner units and 381,149 LTIP units issued from March 2019 to June 2019 72

Preliminary Valuation A Present Value of Incremental Class A Delta House Cash Flows ($ in millions) For the Six Months Ending December 31, For the Years Ending December 31, 2019E 2020E 2021E 2022E 2023E 2024E Cash Flows Attributable to Class A Holders (35.65%) $40.9 $63.7 $48.0 $44.5 $34.6 $27.9 Less: 2025E Class A Cash Flows (35.65%) (12.1) (24.3) (24.3) (24.3) (24.3) (24.3) Incremental Cash Flow $28.7 $39.5 $23.7 $20.2 $10.4 $3.6 Present Value of 2019E – 2025E Cash Flow in Excess of 2025E Cash Flow @ 8.5% Discount Rate $110.3 73 Preliminary Valuation Summary – Sum of the Parts – Discounted Cash Flow Analysis ($ in millions, except for per unit amounts) AMID Management Assumptions Divestiture Sale EBITDA Exit Perpetuity Growth Resulting Enterprise Value Range Implied 2018A EBITDA Multiple Price Assumption WACC Range Multiple Range Rate Range Low High Low High Natural Gas Gathering and Processing 7.5% – 8.5% 9.0x – 11.0x 0.75% – 1.25% $471.3 $656.9 12.2x 1—17.0x 1 $130.0 2 Natural Gas Transportation 10.0% – 11.0% 10.0 – 11.0 1.75% – 2.25% 165.5 255.7 5.9—9.2 200.0 Offshore Pipelines excl. Delta House 8.0% – 9.0% 8.5 – 10.5 (1.00%) – 1.00% 441.8 628.1 5.4—7.7 Delta House 8.0% – 9.0% 2.0 – 4.0 (11.00%) – (9.00%) 258.6 315.6 4.0 3—4.9 3 Bakken Crude Oil Gathering 12.0% – 13.0% 8.5 – 10.5 1.75% – 2.25% 17.9 24.5 13.8—18.9 30.0 Silver Dollar Pipeline 9.5% – 10.5% 8.5 – 10.5 1.75% – 2.25% 150.1 205.7 9.3—12.8 125.0 Cushing Terminal 10.0% – 11.0% 7.5 – 8.5 1.75% – 2.25% 31.7 38.3 N.M.—N.M. 30.0 NGL JV Interests 8.0% – 9.0% 12.0 – 13.0 1.75% – 2.25% 130.1 173.3 9.4—12.5 Crude Oil Trucking4 — 5.0 N.M.—N.M. Total Enterprise Value (Pre Corporate G&A) $1,667.0 $2,303.2 6.9x 9.5x Less: Value of Corporate G&A 8.3% – 9.3% 9.2x – 10.9x 1.75% – 2.25% (424.1) (524.5) Total Enterprise Value $1,242.9 $1,778.7 5.1x—7.3x Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (142.3) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (60.9) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (137.2) Total Common Equity Value ($229.9) $305.9 Estimated Total Units Outstanding as of June 30, 20195 55.4 Value per LP Unit ($4.15) $5.52 Incremental Value of Divestitures6 ($363.3) ($92.7) Estimated Total Units Outstanding as of June 30, 20195 55.4 For Incremental Value per LP Unit ($6.56) ($1.67) Reference Only Value per LP Unit Adjusted for Divestitures ($10.70) $3.85 Note: Blended weighted average WACC and EBITDA multiple from peer trading comps (excluding Delta House) applied to value of corporate G&A valuation 1. Based on 2019E EBITDA 2. Assumes divestiture of Chatom Bazor Ridge and Lavaca for $130.0 million 3. Based on 4Q 2018 annualized EBITDA 4. Assumes liquidation value of zero to $5.0 million 5. As of June 30, 2019 and includes 980,889 general partner units and 381,149 LTIP units issued from March 2019 to June 2019 6. Assumes $242.5 to $354.0 million valuation for Chatom Bazor Ridge and Lavaca based on the impact of the sale of Chatom Bazor Ridge and Lavaca on the valuation of Natural Gas Gathering and Processing resulting from the Discounted Cash Flow Analysis 74

Preliminary Valuation Summary – Sum of the Parts – Precedent M&A Analysis ($ in millions, except for per unit amounts) AMID Management Assumptions Divestiture Sale 2019E EBITDA 2020E EBITDA Resulting Enterprise Value Range1 Implied 2018A EBITDA Multiple Price Assumption Multiple Range Multiple Range Low High Low High Natural Gas Gathering and Processing 7.0x – 9.0x 7.0x – 9.0x $234.3 $447.7 6.1x 2—11.6x 2 $130.0 3 Natural Gas Transportation 9.0 – 11.0 9.0 – 11.0 186.8 236.0 6.7—8.5 200.0 Offshore Pipelines excl. Delta House 6.0 – 8.0 6.0 – 8.0 421.9 573.1 5.2—7.0 Delta House4 258.6 315.6 4.0 5—4.9 5 Bakken Crude Oil Gathering 7.0 – 9.0 7.0 – 9.0 19.2 34.9 14.7—26.8 30.0 Silver Dollar Pipeline 7.0 – 9.0 7.0 – 9.0 56.3 135.5 3.5—8.4 125.0 Cushing Terminal 8.0 – 10.0 32.5 40.7 N.M.—N.M. 30.0 NGL JV Interests 10.0 – 12.0 10.0 – 12.0 145.8 179.7 10.5—13.0 Crude Oil Trucking6 — 5.0 N.M.—N.M. Total Enterprise Value (Pre Corporate G&A) $1,355.5 $1,968.0 5.6x—8.1x Less: Value of Corporate G&A 7.4x – 9.3x 7.4x – 9.3x (337.1) (498.9) Total Enterprise Value $1,018.4 $1,469.1 4.2x—6.0x Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (142.3) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (60.9) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (137.2) Total Common Equity Value ($454.4) ($3.7) Estimated Total Units Outstanding as of June 30, 20197 55.4 Value per LP Unit ($8.20) ($0.07) Incremental Value of Divestitures8 ($154.2) $84.5 Estimated Total Units Outstanding as of June 30, 20197 55.4 For Incremental Value per LP Unit ($2.78) $1.53 Reference Only Value per LP Unit Adjusted for Divestitures ($10.98) $1.46 Note: Blended weighted average WACC and EBITDA exit multiple (excluding Delta House) applied to value of corporate G&A valuation 1. Future enterprise value and capital expenditures discounted to the present value using midpoint of WACC range for each segment utilized in the Discounted Cash Flow analyses 2. Based on 2019E EBITDA 3. Assumes divestiture of Chatom Bazor Ridge and Lavaca for $130.0 million 4. Based on Discounted Cash Flow Analysis 5. Based on 4Q 2018 annualized EBITDA 6. Assumes liquidation value of zero to $5.0 million 7. As of June 30, 2019 and includes 980,889 general partner units and 381,149 LTIP units issued from March 2019 to June 2019 8. Assumes $135.6 million to $222.3 million valuation for Chatom Bazor Ridge and Lavaca based on impact of the sale of Chatom Bazor Ridge and Lavaca on the valuation of Natural Gas Gathering and Processing resulting from Precedent M&A Analysis 75 Preliminary Valuation Summary – Sum of the Parts – Peer Trading Analysis – 2019E ($ in millions, except for per unit amounts) AMID Management Assumptions Divestiture Sale 2019E EBITDA Resulting Enterprise Value Range Implied 2018A EBITDA Multiple Price Assumption Multiple Range Low High Low High Natural Gas Gathering and Processing 9.0x – 11.0x $347.1 $424.3 9.0x 1—11.0x 1 $130.0 2 Natural Gas Transportation 10.0 – 11.0 223.4 245.8 8.0—8.8 200.0 Offshore Pipelines excl. Delta House 8.5 – 10.5 621.1 767.2 7.6—9.4 Delta House3 258.6 315.6 4.0 4—4.9 4 Bakken Crude Oil Gathering 8.5 – 10.5 24.0 29.6 18.4—22.8 30.0 Silver Dollar Pipeline 8.5 – 10.5 84.7 104.6 5.3—6.5 125.0 Cushing Terminal5 7.5 – 8.5 33.7 38.2 N.M.—N.M. 30.0 NGL JV Interests 12.0 – 13.0 183.4 198.7 13.2—14.4 Crude Oil Trucking6 — 5.0 N.M.—N.M. Total Enterprise Value (Pre-Corporate G&A) $1,776.0 $2,128.9 7.3x—8.7x Less: Value of Corporate G&A 9.2x – 10.9x (508.2) (600.4) Total Enterprise Value $1,267.8 $1,528.5 5.2x—6.3x Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (142.3) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (60.9) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (137.2) Total Common Equity Value ($205.1) $55.7 Estimated Total Units Outstanding as of June 30, 20197 55.4 Value per LP Unit ($3.70) $1.00 Incremental Value of Divestitures8 ($138.3) ($43.1) Estimated Total Units Outstanding as of June 30, 20197 55.4 For Incremental Value per LP Unit ($2.49) ($0.78) Reference Only Value per LP Unit Adjusted for Divestitures ($6.20) $0.23 Note: Blended weighted average WACC and EBITDA exit multiple (excluding Delta House) applied to value of corporate G&A valuation 1. Based on 2019E EBITDA 2. Assumes divestiture of Chatom Bazor Ridge and Lavaca for $130.0 million 3. Based on Discounted Cash Flow Analysis 4. Based on 4Q 2018 annualized EBITDA 5. Cushing Terminal Valuation is based on 2020E EBITDA 6. Assumes liquidation value of zero to $5.0 million 7. As of June 30, 2019 and includes 980,889 general partner units and 381,149 LTIP units issued from March 2019 to June 2019 8. Assumes $192.4 million to $235.1 million valuation for Chatom Bazor Ridge and Lavaca based on the impact of the sale of Chatom Bazor Ridge and Lavaca on the valuation of Natural Gas Gathering and Processing in the 2019E Peer Trading Analysis 76

Preliminary Valuation Summary – Sum of the Parts – Peer Trading Analysis – 2020E ($ in millions, except for per unit amounts) AMID Management Assumptions Divestiture Sale 2020E EBITDA Resulting Enterprise Value Range Implied 2018A EBITDA Multiple Price Assumption Multiple Range Low High Low High Natural Gas Gathering and Processing 8.0x – 10.0x $477.7 $597.1 12.4x 1—15.5x 1 $130.0 2 Natural Gas Transportation 9.0 – 11.0 211.4 258.3 7.6—9.3 200.0 Offshore Pipelines excl. Delta House 7.5 – 10.5 572.6 801.6 7.0—9.8 Delta House3 258.6 315.6 4.0 4—4.9 4 Bakken Crude Oil Gathering 8.0 – 10.0 34.9 43.6 26.8—33.5 30.0 Silver Dollar Pipeline 8.0 – 10.0 154.3 192.9 9.6—12.0 125.0 Cushing Terminal 7.5 – 8.5 33.7 38.2 N.M.—N.M. 30.0 NGL JV Interest 10.0 – 12.0 158.1 189.8 11.4—13.7 Crude Oil Trucking5 — 5.0 N.M.—N.M. Total Enterprise Value (Pre Corporate G&A) $1,901.2 $2,442.0 7.8x—10.0x Less: Value of Corporate G&A 8.1x – 10.5x (405.2) (521.2) Total Enterprise Value $1,496.0 $1,920.9 6.1x—7.9x Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (142.3) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (60.9) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (137.2) Total Common Equity Value $23.2 $448.0 Estimated Total Units Outstanding as of June 30, 20196 55.4 Value per LP Unit $0.42 $8.09 Incremental Value of Divestitures7 ($326.2) ($165.8) Estimated Total Units Outstanding as of June 30, 20196 55.4 For Incremental Value per LP Unit ($5.89) ($2.99) Reference Only Value per LP Unit Adjusted for Divestitures ($5.47) $5.09 Note: Blended weighted average WACC and EBITDA exit multiple (excluding Delta House) applied to value of corporate G&A valuation 1. Based on 2019E EBITDA 2. Assumes divestiture of Chatom Bazor Ridge and Lavaca for $130.0 million 3. Based on Discounted Cash Flow Analysis 4. Based on 4Q 2018 annualized EBITDA 5. Assumes liquidation value of zero to $5.0 million 6. As of June 30, 2019 and includes 980,889 general partner units and 381,149 LTIP units issued from March 2019 to June 2019 7. Assumes $246.6 million to $308.3 million valuation for Chatom Bazor Ridge and Lavaca based on the impact of the sale of Chatom Bazor Ridge and Lavaca on the valuation of Natural Gas Gathering and Processing in the 2020E Peer Trading Analysis 77 Preliminary Valuation Precedent MLP Buy-ins and Midstream Mergers For Reference Only Selected MLP Buy-ins Premium1 Date 1-Day 30-Day 60-Day 90-Day Announced Acquiror(s) / Target Consideration Prior Spot VWAP VWAP VWAP 02/05/19 SunCoke Energy, Inc. / SunCoke Energy Partners, L.P. Stock-for-Unit 9.3% 31.2% 26.5% 18.9% 07/10/18 ArcLight Energy Partners Fund VI, L.P. / TransMontaigne Partners L.P. Cash-for-Unit 13.5% 8.6% 8.2% 10.2% 11/08/18 Western Gas Equity Partners, LP / Western Gas Partners, LP Unit-for-Unit 7.6% 13.8% 9.3% 5.9% 10/22/18 EnLink Midstream, LLC / EnLink Midstream Partners, LP Unit-for-Unit 1.1% (0.6%) 1.5% 5.8% 10/19/18 Valero Energy Corporation / Valero Energy Partners LP Cash-for-Unit 6.0% 11.9% 10.9% 10.2% 10/09/18 Antero Midstream GP LP / Antero Midstream Partners LP Cash/Stock-for-Unit 18.6% 6.6% 7.3% 8.2% 10/08/18 Navios Maritime Acquisition Corp. / Navios Maritime Midstream Partners, LP2 Stock-for-Unit 9.3% 4.8% (1.4%) (5.8%) 08/01/18 Energy Transfer Equity, L.P. / Energy Transfer Partners, L.P. Unit-for-Unit 11.2% 19.2% 22.3% 27.4% 05/17/18 The Williams Companies, Inc. / Williams Partners L.P.3 Stock-for-Unit 13.6% 5.8% 1.0% 3.4% 05/17/18 Enbridge Inc. / Enbridge Energy Partners, L.P. Stock-for-Unit 13.9% 15.9% 10.4% 0.8% 05/17/18 Enbridge Inc. / Spectra Energy Partners, LP Stock-for-Unit 20.8% 18.7% 13.7% 7.6% 03/26/18 Tallgrass Energy GP, LP / Tallgrass Energy Partners, L.P.4 Stock-for-Unit 0.1% 6.4% 9.2% 8.7% 01/02/18 Archrock, Inc. / Archrock Partners, L.P. Stock-for-Unit 23.4% 27.7% 21.6% 18.6% 06/02/17 World Point Terminals, Inc. / World Point Terminals, LP Cash-for-Unit 5.8% 3.4% 3.2% 3.5% 05/18/17 Energy Transfer Partners, LP / PennTex Midstream Partners, LP Cash-for-Unit 20.1% 19.9% 22.6% 24.4% 03/02/17 VTTI B.V. / VTTI Energy Partners LP Cash-for-Unit 6.0% 6.8% 14.2% 13.5% 02/01/17 ONEOK, Inc. / ONEOK Partners, L.P. Stock-for-Unit 25.8% 22.4% 26.2% 29.0% 01/27/17 Enbridge Energy Co, Inc. / Midcoast Energy Partners, L.P. Cash-for-Unit (8.6%) 5.4% 11.3% 5.8% Median 10.3% 10.2% 10.7% 8.4% Mean 11.0% 12.7% 12.1% 10.9% Selected Midstream Mergers Premium1 Date 1-Day 30-Day 60-Day 90-Day Announced Acquiror(s) / Target Consideration Prior Spot VWAP VWAP VWAP 04/26/18 EQT Midstream Partners, LP / Rice Midstream Partners LP Unit-for-Unit 9.8% 12.5% 6.1% 2.9% 08/29/17 Zenith Energy U.S., L.P. / Arc Logistics Partners LP Cash-for-Unit 15.2% 12.3% 12.1% 12.2% 08/14/17 Andeavor Logistics LP / Western Refining Logistics, LP Unit-for-Unit 6.4% NA NA NA Median 9.8% 12.4% 9.1% 7.5% Source: Bloomberg, FactSet, public filings Mean 10.5% 12.4% 9.1% 7.5% 1. VWAP premiums paid are calculated by dividing the value of the offer, defined as the exchange ratio multiplied by the closing price of the acquiror’s shares / units on the last trading day prior to announcement plus any cash received, by the 30, 60 or 90 trading day VWAP of the target as calculated from the last undisturbed trading day prior to the announcement 2. VWAP premiums paid are calculated by dividing the value of the offer, defined as the exchange ratio multiplied by the closing price of the acquiror’s shares on the last trading day prior to announcement by the 30, 60 or 90 trading day VWAP of the target as calculated from the last trading day prior to the announcement 3. VWAP premiums paid is calculated by dividing the value of the offer, defined as the exchange ratio multiplied by the closing price of WMB’s shares on the last trading day prior to announcement by the 30, 60 or 90 trading day VWAP of the target as calculated from March 15, 2018, or after the FERC announcement of MLP income tax recovery disallowance 4. VWAP premiums paid is calculated by the 30, 60 or 90 trading day VWAP of acquiror divided by the 30, 60 or 90 trading day VWAP of the target multiplied by the exchange ratio 78

Preliminary Valuation Premiums Paid Analysis For Reference Only Premiums Paid 1-Day Spot 30-Day VWAP 60-Day VWAP 90-Day VWAP AMID Common Unit Price $5.75 $6.28 $6.91 $7.49 of Historical MLP Merger Premium Range (8.6%) – 25.8% (0.6%) – 27.7% (1.4%) – 26.2% (5.8%) – 29.0% As 2018 Implied AMID Common Unit Price Range $5.26 – $7.24 $6.25 – $8.02 $6.82 – $8.73 $7.05 – $9.66 Median MLP Merger Premium 10.3% 10.2% 10.7% 8.4% September 27, Median Implied Transaction Price $6.34 $6.93 $7.65 $8.12 1-Day Spot 30-Day VWAP 60-Day VWAP 90-Day VWAP of AMID Common Unit Price $3.15 $4.31 $5.01 $5.31 As 2019 Historical MLP Merger Premium Range (8.6%) – 25.8% (0.6%) – 27.7% (1.4%) – 26.2% (5.8%) – 29.0% January 3, Implied AMID Common Unit Price Range $2.88 – $3.96 $4.29 – $5.51 $4.94 – $6.32 $5.00 – $6.85 Median MLP Merger Premium 10.3% 10.2% 10.7% 8.4% Median Implied Transaction Price $3.47 $4.76 $5.54 $5.75 Source: Bloomberg 79 A. Preliminary Valuation of Natural Gas Gathering & Processing

Preliminary Valuation of Natural Gas Gathering and Processing Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $800.0 $700.0 $656.9 $597.1 $600.0 $500.0 $447.7 $471.3 $477.7 $424.3 $400.0 $347.1 $300.0 $234.3 $200.0 $100.0 $— 7.5% – 8.5% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 9.0x – 11.0x 0.75% – 1.25% 7.0x – 9.0x 7.0x – 9.0x 9.0x – 11.0x 8.0x – 10.0x 80 Preliminary Valuation of Natural Gas Gathering and Processing Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to analyze AMID natural gas gathering and processing assets’ discounted cash flows: ? Discounted the projected cash flows to June 30, 2019 ? EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections, assuming no asset sales ? Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) ? Mid-point discount rate of 8.0% utilizing WACC based on CAPM ? Terminal value based on a (i) 9.0x to 11.0x EBITDA exit multiple and (ii) 0.75% to 1.25% perpetuity growth rate • Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 81

Preliminary Valuation of Natural Gas Gathering and Processing Discounted Cash Flow Analysis ($ in millions) For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $23.2 $59.7 $68.6 $71.8 $73.1 $73.1 $73.1 Less: Tax Depreciation and Amortization (602.3) (58.0) (32.4) (29.1) (22.5) (3.0) EBIT ($579.1) $1.7 $36.2 $42.7 $50.7 $70.1 Less: Cash Taxes — (0.1) (1.7) (2.0) (2.4) (25.9) EBIAT ($579.1) $1.7 $34.5 $40.7 $48.3 $44.2 Plus: Tax Depreciation and Amortization 602.3 58.0 32.4 29.1 22.5 3.0 Less: Growth Capital Expenditures (42.4) (55.0) (29.4) (26.1) (25.1) —Less: Maintenance Capital Expenditures (1.2) (3.0) (3.0) (3.0) (3.0) (3.0) Unlevered Free Cash Flow ($20.3) $1.7 $34.5 $40.7 $42.7 $44.2 EBITDA Multiple / Perpetuity Growth Rate 10.0x 1.0% Terminal Value $731.2 $637.4 PV of Terminal Value @ 8.0% Discount Rate $517.1 $450.8 Plus: PV of Unlevered Free Cash Flow @ 8.0% Discount Rate 74.8 Implied Enterprise Value $591.9 $525.6 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 8.0x 9.0x 10.0x 11.0x 12.0x 0.50% 0.75% 1.00% 1.25% 1.50% 7.0% $508.8 $562.7 $616.7 $670.6 $724.5 7.0% $581.1 $602.6 $625.8 $651.1 $678.6 CC 7.5% 498.5 551.3 604.1 656.9 709.7 CC 7.5% 534.1 552.3 571.8 592.9 615.8 WA 8.0% 488.5 540.2 591.9 643.6 695.4 WA 8.0% 493.4 509.0 525.6 543.4 562.7 8.5% 478.7 529.4 580.0 630.7 681.3 8.5% 457.9 471.3 485.6 500.9 517.2 9.0% 469.2 518.8 568.4 618.0 667.6 9.0% 426.7 438.3 450.7 463.9 477.9 82 Preliminary Valuation of Natural Gas Gathering and Processing Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Low Growth Natural Gas Gathering and Processing Date Transaction EBITDA Announced Acquiror / Target (Seller) Value Multiple 11/2018 Elevate Midstream Partners / Orion Pipeline NA 7.6x 11/2016 Tesoro Logistics LP / Williston G&P Assets (Whiting Oil and Gas Corp.) $700.0 6.7 11/2016 CONE Midstream Partners LP / 25% Additional Interest in Anchor Systems (CONSOL Energy Inc. and Noble Energy, Inc.) 248.0 7.5 07/2016 Sanchez Production Partners LP / 50% interest in Carnero Gathering, LLC (Sanchez Energy Corporation) 44.4 6.3 09/2015 Sanchez Production Partners LP / Pipeline, Gathering and Compression Assets in Western Catarina (Sanchez Energy Corporation) 345.8 9.4 08/2015 Azure Midstream Partners, LP / Azure ETG, LLC gathering and processing system (Azure Midstream Energy, LLC) 83.0 6.2 03/2014 Summit Midstream Partners, LP / Red Rock Gathering Company, LLC (Summit Midstream Partners, LLC) 305.0 8.6 05/2013 MarkWest Energy Partners, L.P. / Granite Wash Gathering and Processing Assets (Chesapeake Energy Corporation) 245.0 8.2 02/2013 Western Gas Partners, LP / 33.75% Interest in Liberty and Rome Gas Gathering Systems (Anadarko Petroleum Corporation) 490.0 7.6 08/2012 Eagle Rock Energy Partners / Sunray and Hemphill processing plants and associated 2,500 mile gathering system (BP America Production Co.) 227.5 9.5 All Transactions Mean 7.7x Median 7.6 Summary Results 2019E EBITDA $38.6 Plus: Adjustment for Full Year Effect of Acquisition of Pascagoula Plant 1.6 Relevant 2019E EBITDA $40.2 Relevant EBITDA Multiple 7.0x—9.0x Implied Enterprise Value as of December 31, 2019E $281.3—$361.6 Implied Enterprise Value Range on June 30, 2019E @ 8.0% Discount Rate $275.9 $354.7 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 8.0% Discount Rate ($41.6) Implied Enterprise Value Range—2019E EBITDA $234.3—$313.2 2020E EBITDA $59.7 Plus: Adjustment for Full Year Effect of Longview Expansion 4.8 Relevant 2020E EBITDA $64.5 Relevant EBITDA Multiple 7.0x—9.0x Implied Enterprise Value as of December 31, 2020E $451.8—$580.8 Implied Enterprise Value Range on June 30, 2019E @ 8.0% Discount Rate $418.3 $537.8 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 8.0% Discount Rate ($90.1) Implied Enterprise Value Range—2020E EBITDA $328.1—$447.7 Implied Enterprise Value Range $234.3 $447.7 Source: Public filings, Wall street research 83

Preliminary Valuation of Natural Gas Gathering and Processing Peer Group Trading Analysis ($ in millions, except per unit or share amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/15/19 Value Value 2019E 2020E Current 2019E Growth Return Natural Gas Gathering and Processing CNX Midstream Partners LP $14.61 $948.9 $1,490.1 7.0x 6.0x 9.9% 10.7% 8.8% 18.7% Crestwood Equity Partners LP 34.15 2,432.2 4,977.9 10.4 9.2 7.0% 7.0% 3.6% 10.6% DCP Midstream Partners, LP 31.14 4,554.0 10,640.4 8.9 7.8 10.0% 10.0% 1.6% 11.7% Enable Midstream Partners, LP 14.59 6,321.1 10,991.1 9.6 9.5 8.7% 8.7% 3.7% 12.4% Hess Midstream Partners LP 22.33 1,243.6 1,223.3 11.0 9.2 6.6% 7.3% 11.3% 17.9% Noble Midstream Partners LP 37.25 1,482.1 2,774.6 10.3 7.5 6.3% 7.1% 17.7% 24.0% Summit Midstream Partners, LP 9.33 781.0 2,647.1 8.5 8.1 24.7% 24.7% NM NM Targa Resources Corp. 40.04 9,295.0 15,918.1 12.9 10.2 9.1% 9.1% 2.6% 11.7% Mean 9.8x 8.4x 10.3% 10.6% 7.0% 15.3% Median 10.0 8.6 8.9% 8.9% 3.7% 12.4% Summary Results 2019E EBITDA $38.6 Relevant EBITDA Multiple 9.0x—11.0x Implied Enterprise Value Based on 2019E EBITDA $347.1—$424.3 2020E EBITDA $59.7 Relevant EBITDA Multiple 8.0x—10.0x Implied Enterprise Value Based on 2020E EBITDA $477.7—$597.1 Source: FactSet, Public filings 84 B. Preliminary Valuation of Natural Gas Transportation

Preliminary Valuation of Natural Gas Transportation Summary Valuation ($ in millions) Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $350.0 $325.0 $300.0 $275.0 $255.7 $258.3 $250.0 $245.8 $236.0 $225.0 $223.4 $200.0 $211.4 $186.8 $175.0 $150.0 $165.5 $125.0 $100.0 $75.0 $50.0 10.0% – 11.0% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 10.0x – 11.0x 1.75% – 2.25% 9.0x – 11.0x 9.0x – 11.0x 10.0x – 11.0x 9.0x – 11.0x 85 Preliminary Valuation of Natural Gas Transportation Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to analyze AMID natural gas transportation assets’ discounted cash flows: ? Discounted the projected cash flows to June 30, 2019 ? EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections ? Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) ? Mid-point discount rate of 10.5% utilizing WACC based on CAPM ? Terminal value based on a (i) 10.0x to 11.0x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate • Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 86

Preliminary Valuation of Natural Gas Transportation Discounted Cash Flow Analysis ($ in millions) For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $11.3 $23.5 $25.2 $26.0 $26.0 $26.0 $26.0 Less: Tax Depreciation and Amortization (215.5) (4.6) (4.4) (3.5) (2.8) (3.5) EBIT ($204.2) $18.9 $20.8 $22.5 $23.2 $22.5 Less: Cash Taxes — (0.9) (1.0) (1.1) (1.1) (8.3) EBIAT ($204.2) $18.0 $19.8 $21.4 $22.1 $14.2 Plus: Tax Depreciation and Amortization 215.5 4.6 4.4 3.5 2.8 3.5 Less: Growth Capital Expenditures (3.8) (1.1) (0.9) — — —Less: Maintenance Capital Expenditures (1.6) (3.5) (3.5) (3.5) (3.5) (3.5) Unlevered Free Cash Flow $5.9 $18.0 $19.8 $21.4 $21.4 $14.2 EBITDA Multiple / Perpetuity Growth Rate 10.5x 2.00% Terminal Value $273.4 $170.4 PV of Terminal Value @ 10.5% Discount Rate $174.4 $108.7 Plus: PV of Unlevered Free Cash Flow @ 10.5% Discount Rate 68.5 Implied Enterprise Value $242.9 $177.2 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 9.5x 10.0x 10.5x 11.0x 11.5x 1.75% 1.75% 2.00% 2.25% 2.25% 9.5% $234.3 $243.0 $251.6 $260.3 $269.0 9.5% $193.8 $193.8 $198.3 $203.0 $203.0 C AC 10.0% 230.3 238.8 247.2 255.7 264.2 C AC 10.0% 183.2 183.2 187.1 191.2 191.2 W 10.5% 226.3 234.6 242.9 251.2 259.5 W 10.5% 173.8 173.8 177.2 180.8 180.8 11.0% 222.5 230.6 238.7 246.9 255.0 11.0% 165.5 165.5 168.4 171.5 171.5 11.5% 218.7 226.6 234.6 242.6 250.6 11.5% 157.9 157.9 160.5 163.3 163.3 87 Preliminary Valuation of Natural Gas Transportation Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Non-FERC Natural Gas Transportation Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 1/2019 NEXUS Gas Transmission, LLC (Enbridge Inc.; DTE Energy Company) / Generation Pipeline LLC $160.0 14.4x 8/2015 NextEra Energy Partners, LP / NET Midstream (ArcLight Capital Partners) 2,000.0 13.3 3/2014 Southcross Energy Partners LP / 50 miles of natural gas pipelines near Corpus Christi, Texas (Onyx Midstream LP) 40.0 7.0 4/2010 Regency Energy Partners / 7.0% of Haynesville Joint Venture (GE Energy Financial Services) 92.0 9.9 11/2009 American Midstream Partners, LP. / Enbridge Pipelines (Midla) LLC and Enbridge Pipelines (AlaTenn) LLC 151.0 11.2 Median 10.6x Mean 10.4 Precedent Transactions – FERC-Regulated Natural Gas Transportation Transaction Transaction Date Value Value / Announced Acquiror / Target (Seller) ($MM) EBITDA 2/2018 Tallgrass Energy GP / 25.01% interest in Rockies Express Pipeline LLC (Tallgrass Development LP) $1,044.0 6.4x 6/2017 TC Pipelines / 49.3% interest in Iroquois Gas Transmission System, LP and 11.8% interest in Portland Natural Gas Transmission (TransCanada Corp.) 765.0 10.9 4/2017 Tallgrass Energy Partners, LP / 24.99% interest in Rockies Express Pipeline LLC (Tallgrass Development, LP) 1,043.5 6.6 10/2016 Dominion Midstream Partners / Questar Pipeline LLC (Dominion Resources) 1,725.0 10.0 7/2016 Southern Company / 50% Interest in Southern Natural Gas Pipeline System (Kinder Morgan) 2,075.0 10.4 5/2016 Tallgrass Energy Partners, LP / 25% interest in Rockies Express Pipeline LLC (Sempra U.S. Gas and Power) 1,084.0 6.9 11/2015 Kinder Morgan, Inc. and Brookfield Infrastructure Partners LP / Natural Gas Pipeline Company of America LLC (Myria Holdings, Inc.) 3,400.0 13.1 8/2015 Dominion Midstream Partners, LP / 26% interest in Iroquois Gas Transmission System, LP (National Grid and New Jersey Resources Corp.) 286.5 9.8 5/2015 GE Energy Financial Services and Caisse de dépôt et placement du Québec / Southern Star Central Corp (Morgan Stanley Infrastructure) 1,550.2 11.6 4/2015 Dominion Midstream Partners, LP / Dominion Carolina Gas Transmission, LLC (Dominion Resources, Inc.) 495.0 13.0 2/2015 TC Pipelines, LP / 30% interest in Gas Transmission Northwest LLC (TransCanada Corporation) 446.0 10.4 12/2014 Dominion Resources, Inc. / Carolina Gas Transmission (SCANA Corporation) 492.9 13.0 10/2014 TC Pipelines, LP / 49.9% interest in Portland Natural Gas Transmission System (TransCanada Corp.) 233.0 10.1 10/2014 TC Pipelines, LP / 30% interest in Bison Pipeline LLC (TransCanada Corporation) 215.0 10.2 4/2014 El Paso Pipeline Partners, LP / 50% interest in Ruby Pipeline and Gulf LNG and 47.5% interest in Young Gas Storage (Kinder Morgan , Inc.) 2,000.0 9.0 7/2013 EQT Midstream Partners, LP / Sunrise Pipeline, LLC (EQT Corporation) 540.0 9.9 5/2013 TC PipeLines, LP / 45% interest in Gas Transmission Northwest LLC and Bison Pipeline LLC (TransCanada Corporation) 1,050.0 11.0 8/2012 Morgan Stanley Infrastructure Partners / Remaining 60% interest in Southern Star Central Corp (General Electric) 975.0 9.0 8/2012 Tallgrass Energy Partners, LP / Interstate Gas Transmission, Trailblazer Pipeline Co., Casper-Douglas, West Frenchie Draw & 50% interest in REX (Kinder Morgan, Inc.) 3,300.0 8.3 8/2012 Kinder Morgan Energy Partners, LP / Tennessee Gas Pipeline & 50% interest in El Paso Natural Gas (Kinder Morgan, Inc.) 6,220.0 8.0 7/2011 Energy Transfer Partners, LP / 50% interest in Citrus Corp. (Energy Transfer Equity, LP) 2,000.0 10.9 4/2011 TC Pipelines / 25% interest in Gas Transmission Northwest LLC (TransCanada Corporation) 405.0 9.5 4/2011 TC Pipelines / 25% interest in Bison Pipeline LLC (TransCanada Corporation) 200.0 12.5 Median 10.1x Mean 9.9 Source: Public filings, Wall street research 88

Preliminary Valuation of Natural Gas Transportation Precedent M&A Transaction Analysis ($ in millions) Summary Results 2019E EBITDA $22.3 Relevant EBITDA Multiple 9.0x—11.0x Implied Enterprise Value as of December 31, 2019E $201.1—$245.8 Implied Enterprise Value Range on June 30, 2019E @ 10.5% Discount Rate $196.1 $239.7 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 10.5% Discount Rate ($3.7) Implied Enterprise Value Range—2019E EBITDA $192.4—$236.0 2020E EBITDA $23.5 Relevant EBITDA Multiple 9.0x—11.0x Implied Enterprise Value as of December 31, 2020E $211.4—$258.3 Implied Enterprise Value Range on June 30, 2019E @ 10.5% Discount Rate $191.3 $233.8 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 10.5% Discount Rate ($4.4) Implied Enterprise Value Range—2020E EBITDA $186.8—$229.3 Implied Enterprise Value Range $186.8 $236.0 Source: Public filings, Wall street research 89 Preliminary Valuation of Natural Gas Transportation Peer Group Trading Analysis ($ in millions, except per unit / share amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/15/19 Value Value 2019E 2020E Current 2019E Growth Return Natural Gas Transportation EQT Midstream Partners, LP $44.09 $9,146.8 $14,240.9 10.2x 8.2x 10.1% 10.6% 5.6% 15.7% Enable Midstream Partners, LP 14.59 6,321.1 10,991.1 9.6 9.5 8.7% 8.7% 3.7% 12.4% TC PipeLines, LP 35.36 2,572.9 4,719.9 10.5 10.4 7.4% 7.4% —% 7.4% Tallgrass Energy, LP 24.05 6,739.8 9,936.2 10.2 11.1 8.6% 9.0% 5.4% 14.1% The Williams Companies, Inc. 27.56 33,498.7 57,116.7 11.3 10.6 5.5% 5.5% 9.9% 15.4% Mean 10.4x 10.0x 8.1% 8.2% 4.9% 13.0% Median 10.2 10.4 8.6% 8.7% 5.4% 14.1% Summary Results 2019E EBITDA $22.3 Relevant EBITDA Multiple 10.0x—11.0x Implied Enterprise Value Based on 2019E EBITDA $223.4—$245.8 2020E EBITDA $23.5 Relevant EBITDA Multiple 9.0x—11.0x Implied Enterprise Value Based on 2020E EBITDA $211.4—$258.3 90

C. Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $1,000.0 $900.0 $801.6 $800.0 $767.2 $700.0 $628.1 $600.0 $573.1 $621.1 $572.6 $500.0 $400.0 $441.8 $421.9 $300.0 $200.0 Other Offshore Pipelines Destin – Okeanos $100.0 $— 8.0% – 9.0% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 8.5x – 10.5x (1.0%) – 1.0% 6.0x – 8.0x 6.0x – 8.0x 8.5x – 10.5x 7.5x – 10.5x 91

Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to analyze AMID offshore pipeline assets’ discounted cash flows: ? Discounted the projected cash flows to June 30, 2019 ? EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections ? Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) ? Mid-point discount rate of 8.5% utilizing WACC based on CAPM ? Terminal value based on a (i) 8.5x to 10.5x EBITDA exit multiple and (ii) (1.00%) to 1.00% perpetuity growth rate • Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 92 Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Discounted Cash Flow Analysis – Okeanos and Destin ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth 1 EBITDA $37.8 $65.8 $56.7 $51.9 $44.7 $41.6 $44.7 Less: Tax Depreciation and Amortization (423.1) (0.6) (0.6) (0.6) (0.5) (0.6) EBIT ($385.4) $65.2 $56.1 $51.3 $44.2 $44.1 Less: Cash Taxes — (3.1) (2.7) (2.4) (2.1) (16.3) EBIAT ($385.4) $62.1 $53.5 $48.8 $42.1 $27.8 Plus: Tax Depreciation and Amortization 423.1 0.6 0.6 0.6 0.5 0.6 Less: Growth Capital Expenditures — — — — — —Less: Maintenance Capital Expenditures (0.3) (0.6) (0.6) (0.6) (0.6) (0.6) Less: Change in Working Capital (0.2) 1.4 0.4 1.0 1.2 —Less: Change in Deferred Revenue (1.5) (3.1) (3.1) (3.1) (3.1) (3.1) Unlevered Free Cash Flow $35.7 $60.4 $50.8 $46.8 $40.2 $24.7 EBITDA Multiple / Perpetuity Growth Rate 8.5x —% Terminal Value $353.9 $290.9 PV of Terminal Value @ 8.5% Discount Rate $245.2 $201.5 Plus: PV of Unlevered Free Cash Flow @ 8.5% Discount Rate 199.5 Implied Enterprise Value $444.7 $401.0 Implied Enterprise Value (AMID’s 66.7% Share) $296.6 $267.5 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 7.5x 8.5x 9.5x 10.5x 11.5x (2.0%) (1.0%) —% 1.0% 2.0% 7.5% $285.9 $305.9 $326.0 $346.0 $366.1 7.5% $258.3 $274.1 $294.2 $320.5 $356.3 AC C 8.0% 281.6 301.2 320.9 340.5 360.1 C AC 8.0% 248.5 262.5 280.0 302.5 332.5 W 8.5% 277.4 296.6 315.8 335.1 354.3 W 8.5% 239.7 252.1 267.5 286.9 312.3 9.0% 273.3 292.1 311.0 329.8 348.6 9.0% 231.6 242.7 256.3 273.2 295.0 9.5% 269.3 287.7 306.2 324.6 343.1 9.5% 224.2 234.2 246.2 261.0 279.9 1. GAAP EBITDA adjusted by change in deferred revenue 93

Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Offshore Gathering (Excluding Corridor Pipelines) Date Transaction EBITDA Announced Acquiror / Target (Seller) Value Multiple 10/2018 BP Midstream Partners LP / Interest in Mardi Gras Transportation System Company LLC, URSA Oil Pipeline Company LLC and KM-Phoenix Holdings LLC (BP p.l.c.) $486.0 9.4x 05/2018 Shell Midstream Partners, L.P. / Amberjack Pipeline Company LLC (Shell) 1,220.0 8.0 10/2017 American Midstream Partners, LP / 17% Interest in Destin Pipeline (ArcLight Capital Partners, LLC) 30.0 6.3 10/2017 American Midstream Partners, LP / 15.5% interest in Delta House (ArcLight Capital Partners, LLC) 125.4 7.1 08/2017 American Midstream Partners, LP / Remaining Interest in MPOG and AmPan (ArcLight Capital Partners, LLC) 52.0 7.0 06/2017 American Midstream Partners, LP / Vioska Knoll gathering system (Genesis Energy LP) 32.0 7.0 05/2017 Shell Midstream Partners, LP / The Delta, Na Kika and Refinery Gas pipelines (Shell Pipeline Company) 630.0 8.4 11/2016 American Midstream Partners, LP / 6.2% in Delta House (ArcLight Capital Partners, LLC) 48.8 6.0 09/2016 Shell Midstream Partners, L.P. / 20.0% interest in Mars Oil Pipeline Company and 49.0% interest in Odyssey Pipeline L.L.C. (Shell Pipeline Company LP) 350.0 8.4 11/2015 Shell Midstream Partners, L.P. / 100.0% Interest in Auger Pipeline System and Lockport Crude Terminal (Shell Pipeline Company LP) 390.0 8.6 07/2015 Shell Midstream Partners, L.P. / 36.0% interest in Poseidon Oil Pipeline Company, LLC (Shell Oil Products US) 350.0 9.5 04/2016 American Midstream Partners, LP / GoM offshore pipeline assets (ArcLight Capital Partners, LLC) 225.0 6.0 08/2015 American Midstream Partners, LP / 12.9% Interest in Delta House (ArcLight Capital Partners, LLC) 162.0 5.0 10/2011 Genesis Energy, L.P. / 28% interest in Poseidon Oil Pipeline Company, LLC, 29% interest in Odyssey Pipeline LLC and 23% interest in the Eugene Island Pipeline System (Marathon Oil Corporation) 179.0 8.0 06/2007 Williams Partners L.P. / 20.0% interest in Discovery Producer Services LLC (Williams) 78.0 7.1 Mean 7.5x Median 7.1 Source: Public filings, Wall street research 94 Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Precedent M&A Transaction Analysis – Okeanos and Destin ($ in millions) Summary Results 2019E EBITDA $62.0 Less: Change in Deferred Revenue (3.1) Relevant 2019E EBITDA $59.0 Relevant EBITDA Multiple 6.0x—8.0x Implied Enterprise Value as of December 31, 2019E $353.9—$471.8 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $346.7 $462.3 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 8.5% Discount Rate $— Implied Enterprise Value Range—2019E EBITDA $346.7—$462.3 2020E EBITDA $65.8 Less: Change in Deferred Revenue (3.1) Relevant 2020E EBITDA $62.8 Relevant EBITDA Multiple 6.0x—8.0x Implied Enterprise Value as of December 31, 2020E $376.6—$502.2 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $347.1 $462.8 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 8.5% Discount Rate $— Implied Enterprise Value Range—2020E EBITDA $347.1—$462.8 Implied Enterprise Value Range $346.7—$462.8 Implied Enterprise Value Range (AMID’s 66.7% Share) $231.3 $308.7 95

Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Peer Group Trading Analysis – Okeanos and Destin ($ in millions, except per unit amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/15/19 Value Value 2019E 2020E Current 2019E Growth Return Offshore Pipelines Plains All American Pipeline, L.P. $24.30 $17,655.9 $29,090.9 10.6x 10.5x 4.9% 5.4% 9.6% 14.5% Genesis Energy, L.P. 22.62 2,771.8 6,955.5 10.0 9.5 9.5% 9.7% 0.5% 10.0% Shell Midstream Partners, L.P. 19.24 4,394.0 6,327.2 8.6 7.4 8.3% 8.9% 4.4% 12.7% Mean 9.7x 9.1x 7.6% 8.0% 4.8% 12.4% Median 10.0 9.5 8.3% 8.9% 4.4% 12.7% Summary Results 2019E EBITDA $62.0 Less: Change in Deferred Revenue (3.1) Relevant 2019E EBITDA $59.0 Relevant EBITDA Multiple 8.5x—10.5x Implied Enterprise Value Based on 2019E EBITDA $501.3—$619.3 Implied Enterprise Value (AMID’s 66.7% Share) $334.4—$413.0 2020E EBITDA $65.8 Less: Change in Deferred Revenue (3.1) Relevant 2020E EBITDA $62.8 Relevant EBITDA Multiple 7.5x—10.5x Implied Enterprise Value Based on 2020E EBITDA $470.8—$659.1 Implied Enterprise Value (AMID’s 66.7% Share) $314.0—$439.6 Source: FactSet, Public Filings 96 Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Discounted Cash Flow Analysis – Other Offshore Pipelines ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $16.6 $34.5 $32.8 $30.4 $28.0 $28.0 $28.0 Less: Tax Depreciation and Amortization (246.8) (4.0) (4.0) (4.0) (3.2) (4.0) EBIT ($230.2) $30.5 $28.8 $26.4 $24.8 $24.0 Less: Cash Taxes — (1.4) (1.4) (1.3) (1.2) (8.9) EBIAT ($230.2) $29.0 $27.4 $25.2 $23.7 $15.1 Plus: Tax Depreciation and Amortization 246.8 4.0 4.0 4.0 3.2 4.0 Less: Growth Capital Expenditures — — — — — —Less: Maintenance Capital Expenditures (4.3) (4.0) (4.0) (4.0) (4.0) (4.0) Unlevered Free Cash Flow $12.3 $29.0 $27.4 $25.2 $22.9 $15.1 EBITDA Multiple / Perpetuity Growth Rate 8.5x —% Terminal Value $238.3 $178.1 PV of Terminal Value @ 8.5% Discount Rate $165.1 $123.4 Plus: PV of Unlevered Free Cash Flow @ 8.5% Discount Rate 98.3 Implied Enterprise Value $263.4 $221.7 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 6.5x 7.5x 8.5x 9.5x 10.5x (2.0%) (1.0%) —% 1.0% 2.0% 7.5% $231.8 $252.1 $272.3 $292.6 $312.8 7.5% $213.0 $227.6 $246.0 $270.1 $303.0 AC C 8.0% 228.1 248.0 267.8 287.6 307.5 C AC 8.0% 204.2 217.1 233.1 253.8 281.3 W 8.5% 224.6 244.0 263.4 282.8 302.2 W 8.5% 196.2 207.6 221.7 239.6 262.9 9.0% 221.0 240.1 259.1 278.1 297.1 9.0% 188.9 199.1 211.6 227.1 247.1 9.5% 217.6 236.3 254.9 273.5 292.2 9.5% 182.3 191.4 202.4 216.1 233.4 97

Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Precedent M&A Transaction Analysis – Other Offshore Pipelines ($ in millions) Summary Results 2019E EBITDA $33.7 Relevant EBITDA Multiple 6.0x—8.0x Implied Enterprise Value as of December 31, 2019E $202.4—$269.8 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $198.3 $264.4 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 8.5% Discount Rate $— Implied Enterprise Value Range—2019E EBITDA $198.3—$264.4 2020E EBITDA $34.5 Relevant EBITDA Multiple 6.0x—8.0x Implied Enterprise Value as of December 31, 2020E $206.8—$275.8 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $190.6 $254.2 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 8.5% Discount Rate $— Implied Enterprise Value Range—2020E EBITDA $190.6—$254.2 Implied Enterprise Value Range $190.6—$264.4 98 Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Peer Group Trading Analysis – Other Offshore Pipelines ($ in millions) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/15/19 Value Value 2019E 2020E Current 2019E Growth Return Offshore Pipelines Plains All American Pipeline, L.P. $24.30 $17,655.9 $29,090.9 10.6x 10.5x 4.9% 5.4% 9.6% 14.5% Genesis Energy, L.P. 22.62 2,771.8 6,955.5 10.0 9.5 9.5% 9.7% 0.5% 10.0% Shell Midstream Partners, L.P. 19.24 4,394.0 6,327.2 8.6 7.4 8.3% 8.9% 4.4% 12.7% Mean 9.7x 9.1x 7.6% 8.0% 4.8% 12.4% Median 10.0 9.5 8.3% 8.9% 4.4% 12.7% Summary Results 2019E EBITDA $33.7 Relevant EBITDA Multiple 8.5x—10.5x Implied Enterprise Value Based on 2019E EBITDA $286.7—$354.2 2020E EBITDA $34.5 Relevant EBITDA Multiple 7.5x—10.5x Implied Enterprise Value Based on 2020E EBITDA $258.6—$362.0 99

D. Preliminary Valuation of Delta House Preliminary Valuation of Delta House Summary Valuation – Delta House ($ in millions) Discounted Cash Flow Analysis $500.0 $400.0 $315.6 $300.0 $258.6 $200.0 $100.0 $— 8.0% – 9.0% WACC 2025E EBITDA Perpetuity Growth Multiple: Rate: 2.0 x – 4.0x (11.0%) – (9.0%) 100

Preliminary Valuation of Delta House Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to analyze AMID’s share of Delta House’s discounted cash flows: ? Discounted the projected cash flows to June 30, 2019 ? EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections ? Mid-point discount rate of 8.5% utilizing WACC based on CAPM ? Terminal value based on a (i) 2.0x to 4.0x EBITDA exit multiple and (ii) (11.00%) to (9.00%) perpetuity growth rate • Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 101 Preliminary Valuation of Delta House Discounted Cash Flow Analysis – Delta House ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E 2024E 2025E Multiple Growth 1 1 EBITDA $113.7 $242.7 $225.5 $199.8 $175.8 $133.9 $127.2 $71.5 $71.5 Less: Change in Deferred Revenue 9.8 (84.7) (86.7) (78.0) (78.0) (57.2) (55.6) Less: Change in Other Working Capital (8.9) 22.0 (0.8) 6.2 2.4 3.9 (1.2) Cash Flow Available for Distribution $114.6 $180.0 $138.1 $128.1 $100.2 $80.6 $70.3 $71.5 Less: Class B Carry — (1.2) (3.5) (3.3) (3.0) (2.4) (2.2) (2.2) (2.2) Class A Cash Flows $114.6 $178.8 $134.6 $124.8 $97.2 $78.2 $68.1 $69.4 3.0x (10%) Terminal Value $208.1 $337.4 PV of Terminal Value @ 8.5% Discount Rate $122.4 $198.5 Plus: PV of Unlevered Free Cash Flow @ 8.5% Discount Rate $653.1 Implied Enterprise Value $775.5 $851.6 Implied Enterprise Value (AMID’s 35.65% Share) $276.5 $303.6 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 1.0x 2.0x 3.0x 4.0x 5.0x (12.0%) (11.0%) (10.0%) (9.0%) (8.0%) 7.5% $253.3 $268.8 $284.2 $299.7 $315.1 7.5% $307.6 $312.2 $317.3 $323.1 $329.6 C AC 8.0% 250.3 265.3 280.3 295.3 310.3 C AC 8.0% 301.3 305.5 310.3 315.6 321.5 W 8.5% 247.4 261.9 276.5 291.0 305.6 W 8.5% 295.3 299.2 303.6 308.5 313.9 9.0% 244.5 258.6 272.7 286.9 301.0 9.0% 289.5 293.2 297.3 301.8 306.8 9.5% 241.7 255.4 269.1 282.8 296.5 9.5% 284.1 287.5 291.2 295.4 300.0 1. GAAP EBITDA adjusted by change in deferred revenue 102

E. Preliminary Valuation of Bakken Crude Oil Gathering Preliminary Valuation of Bakken Crude Oil Gathering Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $50.0 $43.6 $40.0 $34.9 $34.9 $29.6 $30.0 $24.5 $24.0 $20.0 $17.9 $19.2 $10.0 $— 12.0% – 13.0% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 8.5x – 10.5x 1.75% – 2.25% 7.0x – 9.0x 7.0x – 9.0x 8.5x – 10.5x 8.0x – 10.0x 103

Preliminary Valuation of Bakken Crude Oil Gathering Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to analyze AMID’s Bakken crude oil gathering asset’s discounted cash flows: ? Discounted the projected cash flows to June 30, 2019 ? EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections, assuming no asset sales ? Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) ? Mid-point discount rate of 12.5% utilizing WACC based on CAPM ? Terminal value based on a (i) 8.5x to 10.5x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate • Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 104 Preliminary Valuation of Bakken Crude Oil Gathering Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $2.0 $4.4 $3.8 $2.9 $2.1 $2.1 $2.1 Less: Tax Depreciation and Amortization (20.8) (0.1) (0.1) (0.1) (0.0) (0.1) EBIT ($18.8) $4.3 $3.7 $2.8 $2.0 $2.0 Less: Cash Taxes — (0.2) (0.2) (0.1) (0.1) (0.7) EBIAT ($18.8) $4.1 $3.6 $2.7 $1.9 $1.3 Plus: Tax Depreciation and Amortization 20.8 0.1 0.1 0.1 0.0 0.1 Less: Growth Capital Expenditures — — — — — —Less: Maintenance Capital Expenditures (0.0) (0.1) (0.1) (0.1) (0.1) (0.1) Unlevered Free Cash Flow $2.0 $4.1 $3.6 $2.7 $1.9 $1.3 EBITDA Multiple / Perpetuity Growth Rate 9.5x 2.0% Terminal Value $19.6 $12.2 PV of Terminal Value @ 12.5% Discount Rate $11.5 $7.2 Plus: PV of Unlevered Free Cash Flow @ 12.5% Discount Rate 11.4 Implied Enterprise Value $23.0 $18.6 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 7.5x 8.5x 9.5x 10.5x 11.5x 1.75% 1.75% 2.00% 2.25% 2.25% 11.5% $21.1 $22.3 $23.6 $24.9 $26.1 11.5% $19.7 $19.7 $19.9 $20.2 $20.2 AC C 12.0% 20.8 22.0 23.3 24.5 25.8 C AC 12.0% 19.0 19.0 19.2 19.5 19.5 W 12.5% 20.5 21.7 23.0 24.2 25.4 W 12.5% 18.5 18.5 18.6 18.8 18.8 13.0% 20.3 21.5 22.6 23.8 25.0 13.0% 17.9 17.9 18.1 18.3 18.3 13.5% 20.0 21.2 22.3 23.5 24.7 13.5% 17.4 17.4 17.6 17.7 17.7 105

Preliminary Valuation of Bakken Crude Oil Gathering Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Crude Oil Gathering Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 06/2017 Noble Midstream Partners LP / Additional interest in gathering assets in Delaware and DJ Basins (Noble Energy) $270.0 8.7x 06/2017 Howard Energy Partners / Delaware Basin crude oil gathering and natural gas assets (WPX Energy Inc.) 863.0 10.8 08/2016 PBF Logistics / San Joaquin Valley Pipeline (PBF Energy) 175.0 8.8 05/2015 Summit Midstream Partners, LP / Crude oil and produced water gathering systems and transmission pipelines in the Bakken (Summit Midstream Partners, LLC) 255.0 11.4 01/2015 Kinder Morgan, Inc. / Hiland Partners 3,000.0 16.0 01/2015 EnLink Midstream Partners, LP and EnLink Midstream, LLC / LPC Crude Oil Marketing LLC 100.0 8.0 11/2013 Tesoro Logistics LP / Remaining portion of logistics assets related to Tesoro’s acquisition of BP’s Carson City assets (Tesoro Corporation) 650.0 10.4 09/2013 JP Energy Development / Wildcat Permian Services LLC 210.0 5.1 11/2012 Targa Resources Partners LP / Williston Basin crude oil pipeline and terminal system and natural gas gathering and processing operations (Saddle Butte Pipeline, LLC) 950.0 11.5 Mean 10.1x Median 10.4 Precedent Transactions – Trucking Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 10/2018 Martin Midstream Partners L.P. / Martin Transport, Inc. (Martin Resource Management Corporation) $135.0 5.7x 04/2018 PBF Logistics / Terminal, rail and trucking assets (Undisclosed and PBF Energy, Inc.) 125.4 6.9 06/2015 Ferrellgas Partners LP / Bridger Logistics, LLC 837.5 8.4 01/2015 EnLink Midstream Partners, LP / LPC Crude Oil Marketing LLC 100.0 8.0 12/2014 Delek Logistics Partners LP / FRANK Thompson Transport 12.0 5.0 06/2014 Rose Rock Midstream, LP / Crude oil trucking assets (Chesapeake Energy) 50.0 5.5 08/2013 Rose Rock Midstream, LP / Crude oil trucking assets (Barcas Field Services LLC) 47.0 5.5 02/2013 Global Partners LP / 60% membership interest in Basin Transload LLC 85.0 5.0 12/2012 NGL Energy Partners LP / Crude oil purchasing and logistics operations (Pecos Gathering & Marketing) 132.4 5.5 11/2012 Inergy Midstream, LP / Rangeland Energy, LLC 425.0 7.2 10/2012 Gibson Energy Inc. / OMNI Energy Services Corp. 445.0 5.5 06/2012 Quality Distribution, Inc. / Wylie Bice Trucking and RM Resources 100.4 7.9 05/2012 NGL Energy Partners LP / High Sierra Energy LP and High Sierra Energy GP, LLC 679.0 6.2 05/2010 Gibson Energy / Crude oil transportation and logistics operation (Taylor) 153.2 7.1 Median 6.0x Mean 6.4 Source: Public filings, Wall street research 106 Preliminary Valuation of Bakken Crude Oil Gathering Precedent M&A Transaction Analysis ($ in millions) Summary Results 2019E EBITDA $2.8 Relevant EBITDA Multiple 7.0x—9.0x Implied Enterprise Value as of December 31, 2019E $19.7—$25.4 Implied Enterprise Value Range on June 30, 2019E @ 12.5% Discount Rate $19.2 $24.6 Less: Present Value of June 30, 2019E to June 30, 2019E Growth Capital Expenditures @ 12.5% Discount Rate $— Implied Enterprise Value Range—2019E EBITDA $19.2—$24.6 2020E EBITDA $4.4 Relevant EBITDA Multiple 7.0x—9.0x Implied Enterprise Value as of December 31, 2020E $30.5—$39.2 Implied Enterprise Value Range on June 30, 2019E @ 12.5% Discount Rate $27.1 $34.9 Less: Present Value of June 30, 2019E to June 30, 2020E Growth Capital Expenditures @ 12.5% Discount Rate $— Implied Enterprise Value Range—2020E EBITDA $27.1—$34.9 Implied Enterprise Value Range $19.2 $34.9 107

Preliminary Valuation of Bakken Crude Oil Gathering Peer Group Trading Analysis ($ in millions, except per unit amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/15/19 Value Value 2019E 2020E Current 2019E Growth Return Crude Oil Gathering Delek Logistics Partners, LP $32.46 $808.4 $1,504.3 7.9x 7.0x 10.0% 10.6% 3.0% 12.9% Genesis Energy, L.P. 22.62 2,771.8 6,955.5 10.0 9.5 9.5% 9.7% 0.5% 10.0% NGL Energy Partners LP 13.51 1,677.4 4,275.2 8.8 7.9 11.5% 11.5% 1.9% 13.4% Plains All American Pipeline, L.P. 24.30 17,655.9 29,090.9 10.6 10.5 4.9% 5.4% 9.6% 14.5% Mean 9.3x 8.7x 9.0% 9.3% 3.7% 12.7% Median 9.4 8.7 9.8% 10.1% 2.4% 13.2% Summary Results 2019E EBITDA $2.8 Relevant EBITDA Multiple 8.5x—10.5x Implied Enterprise Value Based on 2019E EBITDA $24.0—$29.6 2020E EBITDA $4.4 Relevant EBITDA Multiple 8.0x—10.0x Implied Enterprise Value Based on 2020E EBITDA $34.9—$43.6 108 F. Preliminary Valuation of Silver Dollar Pipeline

Preliminary Valuation of Silver Dollar Pipeline Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $350.0 $300.0 $250.0 $205.7 $200.0 $192.9 $150.0 $135.5 $150.1 $154.3 $104.6 $100.0 $84.7 $50.0 $56.3 $— 9.5% – 10.5% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 8.5x – 10.5x 1.75% – 2.25% 7.0x – 9.0x 7.0x – 9.0x 8.5x – 10.5x 8.0x – 10.0x 109 Preliminary Valuation of Silver Dollar Pipeline Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to analyze Silver Dollar Pipeline’s discounted cash flows: ? Discounted the projected cash flows to June 30, 2019 ? EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections, assuming no asset sales ? Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) ? Mid-point discount rate of 10.0% utilizing WACC based on CAPM ? Terminal value based on a (i) 8.5x to 10.5x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate • Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 110

Preliminary Valuation of Silver Dollar Pipeline Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $6.2 $19.3 $22.0 $22.1 $22.7 $22.7 $22.7 Less: Tax Depreciation and Amortization (187.4) (13.1) (0.5) (0.4) (0.3) (0.4) EBIT ($181.2) $6.2 $21.5 $21.7 $22.4 $22.3 Less: Cash Taxes — (0.3) (1.0) (1.0) (1.1) (8.3) EBIAT ($181.2) $5.9 $20.5 $20.6 $21.4 $14.1 Plus: Tax Depreciation and Amortization 187.4 13.1 0.5 0.4 0.3 0.4 Less: Growth Capital Expenditures (12.0) (12.6) — — — —Less: Maintenance Capital Expenditures (0.2) (0.5) (0.5) (0.4) (0.4) (0.4) Unlevered Free Cash Flow ($6.1) $5.9 $20.5 $20.6 $21.3 $14.1 EBITDA Multiple / Perpetuity Growth Rate 9.5x 2.0% Terminal Value $216.0 $179.4 PV of Terminal Value @ 10.0% Discount Rate $140.7 $116.8 Plus: PV of Unlevered Free Cash Flow @ 10.0% Discount Rate 46.4 Implied Enterprise Value $187.0 $163.2 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 7.5x 8.5x 9.5x 10.5x 11.5x 1.75% 1.75% 2.00% 2.25% 2.25% 9.0% $163.4 $178.8 $194.3 $209.7 $225.1 9.0% $181.7 $181.7 $186.8 $192.3 $192.3 AC C 9.5% 160.4 175.5 190.6 205.7 220.8 C AC 9.5% 169.8 169.8 174.2 178.9 178.9 W 10.0% 157.4 172.2 187.0 201.9 216.7 W 10.0% 159.4 159.4 163.2 167.3 167.3 10.5% 154.5 169.1 183.6 198.1 212.6 10.5% 150.1 150.1 153.5 157.0 157.0 11.0% 151.7 165.9 180.2 194.4 208.6 11.0% 141.9 141.9 144.8 147.9 147.9 111 Preliminary Valuation of Silver Dollar Pipeline Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Crude Oil Gathering Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 06/2017 Noble Midstream Partners LP / Additional interest in gathering assets in Delaware and DJ Basins (Noble Energy) $270.0 8.7x 06/2017 Howard Energy Partners / Delaware Basin crude oil gathering and natural gas assets (WPX Energy Inc.) 863.0 10.8 08/2016 PBF Logistics / San Joaquin Valley Pipeline (PBF Energy) 175.0 8.8 05/2015 Summit Midstream Partners, LP / Crude oil and produced water gathering systems and transmission pipelines in the Bakken (Summit Midstream Partners, LLC) 255.0 11.4 01/2015 Kinder Morgan, Inc. / Hiland Partners 3,000.0 16.0 01/2015 EnLink Midstream Partners, LP and EnLink Midstream, LLC / LPC Crude Oil Marketing LLC 100.0 8.0 11/2013 Tesoro Logistics LP / Remaining portion of logistics assets related to Tesoro’s acquisition of BP’s Carson City assets (Tesoro Corporation) 650.0 10.4 09/2013 JP Energy Development / Wildcat Permian Services LLC 210.0 5.1 11/2012 Targa Resources Partners LP / Williston Basin crude oil pipeline and terminal system and natural gas gathering and processing operations (Saddle Butte Pipeline, LLC) 950.0 11.5 Mean 10.1x Median 10.4 Precedent Transactions – Trucking Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 10/2018 Martin Midstream Partners L.P. / Martin Transport, Inc. (Martin Resource Management Corporation) $135.0 5.7x 04/2018 PBF Logistics / Terminal, rail and trucking assets (Undisclosed and PBF Energy, Inc.) 125.4 6.9 06/2015 Ferrellgas Partners LP / Bridger Logistics, LLC 837.5 8.4 01/2015 EnLink Midstream Partners, LP / LPC Crude Oil Marketing LLC 100.0 8.0 12/2014 Delek Logistics Partners LP / FRANK Thompson Transport 12.0 5.0 06/2014 Rose Rock Midstream, LP / Crude oil trucking assets (Chesapeake Energy) 50.0 5.5 08/2013 Rose Rock Midstream, LP / Crude oil trucking assets (Barcas Field Services LLC) 47.0 5.5 02/2013 Global Partners LP / 60% membership interest in Basin Transload LLC 85.0 5.0 12/2012 NGL Energy Partners LP / Crude oil purchasing and logistics operations (Pecos Gathering & Marketing) 132.4 5.5 11/2012 Inergy Midstream, LP / Rangeland Energy, LLC 425.0 7.2 10/2012 Gibson Energy Inc. / OMNI Energy Services Corp. 445.0 5.5 06/2012 Quality Distribution, Inc. / Wylie Bice Trucking and RM Resources 100.4 7.9 05/2012 NGL Energy Partners LP / High Sierra Energy LP and High Sierra Energy GP, LLC 679.0 6.2 05/2010 Gibson Energy / Crude oil transportation and logistics operation (Taylor) 153.2 7.1 Median 6.0x Mean 6.4 Source: Public filings, Wall street research 112

Preliminary Valuation of Silver Dollar Pipeline Precedent M&A Transaction Analysis ($ in millions) Summary Results 2019E EBITDA $10.0 Relevant EBITDA Multiple 7.0x—9.0x Implied Enterprise Value as of December 31, 2019E $69.7—$89.7 Implied Enterprise Value Range on June 30, 2019E @ 10.0% Discount Rate $68.1 $87.6 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 10.0% Discount Rate ($11.8) Implied Enterprise Value Range—2019E EBITDA $56.3—$75.8 2020E EBITDA $19.3 Relevant EBITDA Multiple 7.0x—9.0x Implied Enterprise Value as of December 31, 2020E $135.0—$173.6 Implied Enterprise Value Range on June 30, 2019E @ 10.0% Discount Rate $122.7 $157.8 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 10.0% Discount Rate ($22.4) Implied Enterprise Value Range—2020E EBITDA $100.4—$135.5 Implied Enterprise Value Range $56.3 $135.5 113 Preliminary Valuation of Silver Dollar Pipeline Peer Group Trading Analysis ($ in millions, except per unit amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/15/19 Value Value 2019E 2020E Current 2019E Growth Return Crude Oil Gathering Delek Logistics Partners, LP $32.46 $808.4 $1,504.3 7.9x 7.0x 10.0% 10.6% 3.0% 12.9% Genesis Energy, L.P. 22.62 2,771.8 6,955.5 10.0 9.5 9.5% 9.7% 0.5% 10.0% NGL Energy Partners LP 13.51 1,677.4 4,275.2 8.8 7.9 11.5% 11.5% 1.9% 13.4% Plains All American Pipeline, L.P. 24.30 17,655.9 29,090.9 10.6 10.5 4.9% 5.4% 9.6% 14.5% Mean 9.3x 8.7x 9.0% 9.3% 3.7% 12.7% Median 9.4 8.7 9.8% 10.1% 2.4% 13.2% Summary Results 2019E EBITDA $10.0 Relevant EBITDA Multiple 8.5x—10.5x Implied Enterprise Value Based on 2019E EBITDA $84.7—$104.6 2020E EBITDA $19.3 Relevant EBITDA Multiple 8.0x—10.0x Implied Enterprise Value Based on 2020E EBITDA $154.3—$192.9 Source: FactSet, Public filings 114

G. Preliminary Valuation of Cushing Terminal Preliminary Valuation of Cushing Terminal Summary Valuation ($ in millions) Discounted Cash Flow Analysis Precedent M&A Analysis Peer Trading Analysis $100.0 $75.0 $50.0 $40.7 $38.3 $38.2 $32.5 $33.7 $31.7 $25.0 $— 10.0% – 11.0% WACC 2020E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2020E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple 7.5x – 8.5x 1.75% – 2.25% 8.0x – 10.0x 7.5x – 8.5x 115

Preliminary Valuation of Cushing Terminal Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to analyze Cushing Terminal‘s discounted cash flows: ? Discounted the projected cash flows to June 30, 2019 ? EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections, assuming no asset sales ? Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) ? Mid-point discount rate of 10.5% utilizing WACC based on CAPM ? Terminal value based on a (i) 7.5x to 8.5x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate • Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 116 Preliminary Valuation of Cushing Terminal Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA ($0.1) $4.5 $4.5 $4.5 $4.5 $4.5 $4.5 Less: Tax Depreciation and Amortization (35.1) — — — — (0.2) 1 EBIT ($35.2) $4.5 $4.5 $4.5 $4.5 $4.3 Less: Cash Taxes — (0.2) (0.2) (0.2) (0.2) (1.6) EBIAT ($35.2) $4.3 $4.3 $4.3 $4.3 $2.7 Plus: Tax Depreciation and Amortization 35.1 — — — — —Less: Growth Capital Expenditures — — — — — —Less: Maintenance Capital Expenditures — — — — — —Unlevered Free Cash Flow ($0.1) $4.3 $4.3 $4.3 $4.3 $2.7 EBITDA Multiple / Perpetuity Growth Rate 8.0x 2.0% Terminal Value $35.9 $32.3 PV of Terminal Value @ 10.5% Discount Rate $22.9 $20.6 Plus: PV of Unlevered Free Cash Flow @ 10.5% Discount Rate 13.3 Implied Enterprise Value $36.3 $33.9 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 7.0x 7.5x 8.0x 8.5x 9.0x 1.75% 1.75% 2.00% 2.25% 2.25% 9.5% $34.5 $36.0 $37.5 $39.0 $40.5 9.5% $37.1 $37.1 $37.9 $38.8 $38.8 C AC 10.0% 34.0 35.4 36.9 38.3 39.8 C AC 10.0% 35.1 35.1 35.8 36.6 36.6 W 10.5% 33.4 34.8 36.3 37.7 39.1 W 10.5% 33.3 33.3 33.9 34.6 34.6 11.0% 32.8 34.2 35.7 37.1 38.5 11.0% 31.7 31.7 32.2 32.8 32.8 11.5% 32.3 33.7 35.1 36.4 37.8 11.5% 30.2 30.2 30.7 31.3 31.3 1. Assumes maintenance capital expenditures equal to 5.0% of EBITDA 117

Preliminary Valuation of Cushing Terminal Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Terminals Date Transaction EBITDA Announced Acquiror / Target (Seller) Value Multiple ArcLight Capital Partners, LLC / Two refined products and crude oil terminals located in Tacoma, WA and Baltimore, MD (Targa 09/2018 $160.0 9.6x Resources Corp.) Delek Logistics Partners, LP / Big Spring Logistics assets including 15 storage tanks, salt wells, 4 light products terminals and certain 02/2018 315.0 7.9 other logistics assets (Delek US) 11/2017 TransMontaigne Partners / Martinez and Richmond Terminals (Plains All American) 275.0 10.0 11/2017 Andeavor Logistics LP / Anacortes Logistics Assets (Andeavor) 445.0 8.5 International-Matex Tank Terminals / Epic Midstream, which operates a portfolio of seven terminals in the U.S. Southeast and 08/2017 171.5 11.0 Southwest with 3.1 MMBbls of refined petroleum, asphalt, biofuels and chemical storage capacity (White Deer Energy and Blue Water 06/2017 SemGroup Corporation / Houston Fuel Oil Terminal Company (Alinda Capital Partners) 2,100.0 18.3 04/2017 PBF Logistics LP / Toledo, Ohio, refined products terminal assets (Sunoco Logistics LP) 10.0 3.4 03/2017 Sprague Resources LP / Inwood and Lawrence, New York, terminal assets (Carbo Industries, Inc. and Carbo Realty, L.L.C.) 70.0 7.8 02/2017 Sprague Resources LP / Refined product terminal assets in Springfield, Massachusetts (Leonard E. Belcher, Inc.) 20.0 5.7 01/2017 Sprague Resources LP / Storage terminal and Wilkesbarre Pier in East Providence, Rhode Island (Capital Terminal Company) 23.0 3.8 01/2017 Tallgrass Energy Partners, LP / Tallgrass Terminals, LLC and Tallgrss NatGas Operator, LLC 140.0 8.0 12/2016 NGL Energy Partners LP / Port Hudson Terminal and Kingfisher Facility (Murphy Energy Corporation) 51.0 5.0 11/2016 Tesoro Logistics L.P. / Northern California terminalling and storage assets (Tesoro Corporation) 400.0 8.4 NuStar Energy L.P. / Crude oil and refined products storage terminal in the Port of Corpus Christi, Texas (Martin Midstream Partners 10/2016 93.0 7.0 LP) 10/2016 Phillips 66 Partners / 30 crude oil, refined products and natural gas liquids logistics assets (Phillips 66) 1,300.0 8.7 Western Refining Logistics / Certain terminalling, storage and other logistics assets (Western Refining Inc. / St. Paul Park Refining 09/2016 210.0 8.5 Co.) 08/2016 Valero Energy Partners / Meraux and Three Rivers Terminal services business (Valero Energy Corp.) 325.0 8.3 VTTI Energy Partners LP / Additional 8.4% equity interest in VTTI MLP B.V. and associated pro-rata net debt (VTTI MLP Partners 08/2016 140.0 8.6 B.V.) Tesoro Logistics LP / Alaska crude oil, feedstock and refined product storage tanks and refined product terminals (Tesoro 07/2016 444.0 8.7 Corporation) 03/2016 Valero Energy Partners LP / McKee Terminal Services Business (Valero Energy Corporation) 240.0 8.6 02/2016 Phillips 66 Partners LP / 25% Controlling Interest in Phillips 66 Sweeny Frac LLC (Phillips 66) 236.0 9.7 02/2016 PBF Logistics LP / Four refined products terminals located near Philadelphia, Pennsylvania (Plains All American Pipeline, L.P.) 105.0 7.0 All Transactions Mean 8.2x Median 8.4 Source: Public filings, Wall street research 118 Preliminary Valuation of Cushing Terminal Precedent M&A Transaction Analysis ($ in millions) Summary Results 2020E EBITDA $4.5 Relevant EBITDA Multiple 8.0x—10.0x Implied Enterprise Value as of December 31, 2020E $35.9—$44.9 Implied Enterprise Value Range on June 30, 2019E @ 10.5% Discount Rate $32.5 $40.7 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 10.5% Discount Rate $— Implied Enterprise Value Range—2020E EBITDA $32.5—$40.7 119

Preliminary Valuation of Cushing Terminal Peer Group Trading Analysis ($ in millions, except per unit amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership 3/15/19 Value Value 2019E 2020E Current 2019E Growth Return Crude Oil Storage Blueknight Energy Partners, L.P. $1.06 $43.9 $602.9 9.9x 8.9x NM 20.3% (12.2%) NM Global Partners LP 19.00 650.3 1,781.8 8.2 8.0 10.5% 10.5% —% 10.5% Sprague Resources LP 15.78 358.7 1,012.3 8.4 7.7 16.9% 16.9% 0.2% 17.1% USD Partners LP 11.00 297.9 497.0 8.2 7.4 13.1% 13.9% NM NM Mean 8.7x 8.0x 13.5% 15.4% (4.0%) 13.8% Median 8.3 7.9 13.1% 15.4% 0.0% 13.8% Summary Results 2020E EBITDA $4.5 Relevant EBITDA Multiple 7.5x—8.5x Implied Enterprise Value Based on 2020E EBITDA $33.7—$38.2 Implied Enterprise Value $33.7—$38.2 Source: FactSet, Public Filings 120 H. Preliminary Valuation of NGL JV Interests

Preliminary Valuation of NGL JV Interests Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $250.0 $198.7 $200.0 $189.8 $173.3 $179.7 $183.4 $150.0 $158.1 $145.8 $130.1 $100.0 $50.0 8.0% – 9.0% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 12.0x – 13.0x 1.75% – 2.25% 10.0x – 12.0x 10.0x – 12.0x 12.0x – 13.0x 10.0x – 12.0x 121 Preliminary Valuation of NGL JV Interests Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to perform a discounted cash flow analysis on AMID’s 25.3% interest in Wilprise, 16.7% interest in Tri-State and 50.0% interest in Cayenne: ? Discounted the projected cash flows to June 30, 2019 ? EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections ? Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) ? Mid-point discount rate of 8.5% utilizing WACC based on CAPM ? Terminal value based on a (i) 12.0x to 13.0x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate • Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 122

Preliminary Valuation of NGL JV Interests Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $5.2 $15.8 $15.4 $14.2 $13.2 $13.2 $13.2 Less: Tax Depreciation and Amortization (153.8) — — — — —EBIT ($148.5) $15.8 $15.4 $14.2 $13.2 $13.2 Less: Cash Taxes — (0.7) (0.7) (0.7) (0.6) (4.9) EBIAT ($148.5) $15.1 $14.6 $13.5 $12.6 $8.3 Plus: Tax Depreciation and Amortization 153.8 — — — — —Less: Growth Capital Expenditures — — — — — —Less: Maintenance Capital Expenditures — — — — — —Less: Change in Working Capital (0.0) (0.1) 0.1 0.2 0.2 —Unlevered Free Cash Flow $5.2 $15.0 $14.7 $13.8 $12.8 $8.3 EBITDA Multiple / Perpetuity Growth Rate 12.5x 2.0% Terminal Value $165.0 $130.5 PV of Terminal Value @ 8.5% Discount Rate $114.3 $90.4 Plus: PV of Unlevered Free Cash Flow @ 8.5% Discount Rate 51.4 Implied Enterprise Value $165.7 $141.8 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 11.5x 12.0x 12.5x 13.0x 13.5x 1.50% 1.75% 2.00% 2.25% 2.50% 7.5% $162.1 $166.8 $171.6 $176.4 $181.1 7.5% $154.0 $158.7 $163.8 $169.4 $175.6 C AC 8.0% 159.3 163.9 168.6 173.3 178.0 C AC 8.0% 143.8 147.7 151.9 156.5 161.5 W 8.5% 156.6 161.1 165.7 170.3 174.9 W 8.5% 134.9 138.2 141.8 145.7 149.8 9.0% 153.9 158.4 162.9 167.3 171.8 9.0% 127.3 130.1 133.1 136.4 139.9 9.5% 151.3 155.7 160.1 164.5 168.9 9.5% 120.6 123.0 125.6 128.4 131.4 123 Preliminary Valuation of NGL JV Interests Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – NGL Transportation Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 10/2017 Blackstone Energy Partners / 25% interest in Grand Prix Pipeline (Targa Resources Corp) $325.0 10.0x 10/2016 Phillips 66 Partners LP / 30 Crude, Products, and NGL Logistics Assets (Phillips 66) 1,300.0 8.7 6/2016 Riverstone Investment Group LLC / 50% Partner Interest in Utopia Pipeline Project (Kinder Morgan, Inc.) 300.0 12.0 5/2016 Phillips 66 Partners LP / Standish Pipeline and remaining 75% in Phillips 66 Sweeny Frac LLC (Phillips 66) 775.0 8.6 2/2015 Phillips 66 Partners LP / Interests in LLCs owning Sand Hills NGL pipelines and Explorer refined products pipeline (Phillips 66) 1,077.6 9.5 2/2015 NGL Energy Partners LP / NGL Storage Facility (Magnum NGLs LLC) 280.0 10.5 10/2014 ONEOK Partners, LP / 80% interest in WTLPG and 100% interest in Mesquite Pipeline (Chevron Corporation) 800.0 20.0 9/2014 Boardwalk Pipeline Partners, LP / Evangeline ethylene pipeline system (Chevron Petrochemical Pipeline LLC) 295.0 12.5 9/2014 Pembina Pipeline Corporation / Vantage Pipeline System and Mistral Midstream Inc.‘s interest in the Saskatchewan Ethane Extraction Plant (Riverstone Holdings LLC) 650.0 12.5 5/2014 Martin Midstream Partners LP / 20% interest in West Texas LPG Pipeline LP (Atlas Pipeline NGL Holdings, LLC) 134.4 14.5 DCP Midstream Partners, LP / 33.3% interest in each of Sand Hills and Southern Hills pipelines, remaining 20% interest in Eagle Ford system and the Lucerne 1 gas processing 2/2014 plant (DCP Midstream, LP) 1,150.0 12.0 2/2014 Western Gas Partners, LP / 20% interest in Texas Express Pipeline LLC and Texas Express Gathering LLC and a 33.3% interest in Front Range Pipeline LLC (Anadarko) 375.0 11.1 2/2014 Phillips 66 Partners LP / Gold Product Pipeline System and Medford Spheres (Phillips 66) 700.0 10.4 8/2013 DCP Midstream Partners, LP / 33.3% interest in Front Range Pipeline LLC (DCP Midstream, LP) 86.0 15.0 4/2011 Atlas Pipeline Partners LP / 20% interest in West Texas LPG Limited Partnership (Buckeye Partners, LP) 85.0 13.7 3/2011 Energy Transfer Partners, LP and Regency Energy Partners LP / Louis Dreyfus Highbridge Energy LLC 1,925.0 11.6 All Transactions Median 11.8x Mean 12.0 Source: Public filings, Wall street research 124

Preliminary Valuation of NGL JV Interests Precedent M&A Transaction Analysis ($ in millions) Summary Results 2019E EBITDA $15.3 Relevant EBITDA Multiple 10.0x—12.0x Implied Enterprise Value as of December 31, 2019E $152.9—$183.4 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $149.8 $179.7 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 8.5% Discount Rate $— Implied Enterprise Value Range—2019E EBITDA $149.8—$179.7 2020E EBITDA $15.8 Relevant EBITDA Multiple 10.0x—12.0x Implied Enterprise Value as of December 31, 2020E $158.1—$189.8 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $145.8 $174.9 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 8.5% Discount Rate $— Implied Enterprise Value Range—2020E EBITDA $145.8—$174.9 Implied Enterprise Value Range $145.8 $179.7 125 Preliminary Valuation of NGL JV Interests Peer Group Trading Analysis ($ in millions, except per unit / share amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/15/19 Value Value 2019E 2020E Current 2019E Growth Return Enterprise Products Partners L.P. $28.13 $61,460.5 $87,732.6 11.8x 11.2x 6.2% 6.3% 2.6% 8.7% ONEOK, Inc. 66.85 27,516.2 36,905.2 14.2 11.8 5.1% 5.4% 9.6% 14.7% Phillips 66 Partners LP 51.84 6,564.8 10,357.8 8.3 7.3 6.4% 6.7% 4.9% 11.3% Targa Resources Corp. 40.04 9,295.0 15,918.1 12.9 10.2 9.1% 9.1% 2.6% 11.7% Mean 11.8x 10.1x 6.7% 6.9% 4.9% 11.6% Median 12.4 10.7 6.3% 6.5% 3.7% 11.5% Summary Results 2019E EBITDA $15.3 Relevant EBITDA Multiple 12.0x—13.0x Implied Enterprise Value Based on 2019E EBITDA $183.4—$198.7 2020E EBITDA $15.8 Relevant EBITDA Multiple 10.0x—12.0x Implied Enterprise Value Based on 2020E EBITDA $158.1—$189.8 Source: FactSet, Public filings 126

I. Preliminary Valuation of AMID Corporate G&A Expenses Preliminary Valuation of AMID Corporate G&A Expenses Summary Valuation ($ in millions) Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $650.0 $600.0 $600.4 $550.0 $524.5 $521.2 $498.9 $500.0 $508.2 $450.0 $424.1 $400.0 $405.2 $350.0 $337.1 $300.0 $250.0 $200.0 8.3% – 9.3% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 9.2x – 10.9x 1.75% – 2.25% 7.4x – 9.3x 7.4x – 9.3x 9.2x – 10.9x 8.1x – 10.5x 127

Preliminary Valuation of AMID Corporate G&A Expenses Discounted Cash Flow Analysis – Assumptions ? Evercore utilized the following assumptions to perform a discounted cash flow analysis on AMID’s corporate G&A expenses ? Discounted the projected cash flows to June 30, 2019 ? Corporate G&A expenses per AMID Financial Projections ? Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) ? Mid-point discount rate of 8.8% utilizing weighted average WACC used in Sum of the Parts Analysis ? Terminal value based on a (i) 9.2x to 10.9x EBITDA exit multiple based on weighted average peer trading multiple and (ii) 1.75% to 2.25% perpetuity growth rate • Based on weighted average EBITDA exit multiple and perpetuity growth rate used in the Sum of the Parts analysis 128 Preliminary Valuation of AMID Corporate G&A Expenses Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth Corporate G&A Expense $26.7 $49.8 $49.8 $49.8 $49.8 $49.8 $49.8 Corporate G&A Expense $26.7 $49.8 $49.8 $49.8 $49.8 $49.8 Less: Cash Taxes (6.3) (11.8) (11.8) (11.8) (11.8) (18.4) Unlevered Free Cash Flow $20.4 $38.0 $38.0 $38.0 $38.0 $31.4 Multiple / Perpetuity Growth Rate 10.1x 2.0% Terminal Value $502.3 $468.5 PV of Terminal Value @ 8.8% Discount Rate $343.2 $320.1 Plus: PV of Unlevered Free Cash Flow @ 8.8% Discount Rate 143.6 Implied Value of AMID Corporate G&A Liability $486.8 $463.7 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 8.2x 9.2x 10.1x 10.9x 11.9x 1.50% 1.75% 2.00% 2.25% 2.50% 7.8% $439.0 $474.4 $504.2 $533.9 $569.4 7.8% $504.7 $520.3 $537.3 $555.8 $576.1 C C 8.3% 431.5 466.3 495.4 524.5 559.3 C C 8.3% 470.2 483.4 497.6 513.0 529.7 A A W 8.8% 424.2 458.3 486.8 515.3 549.4 W 8.8% 440.4 451.6 463.7 476.7 490.7 9.3% 417.1 450.5 478.4 506.4 539.7 9.3% 414.4 424.1 434.4 445.5 457.3 9.8% 410.2 442.9 470.2 497.6 530.3 9.8% 391.5 399.9 408.8 418.4 428.5 129

Preliminary Valuation of AMID Corporate G&A Expenses Precedent M&A Transaction and Peer Trading Analysis ($ in millions) Precedent M&A Transaction Summary Results 2019E Corporate G&A Expense $55.0 Relevant Multiple1 7.4x—9.3x Implied AMID Corporate G&A Liability Based on 2019E Expense $404.8—$509.6 Implied Enterprise Value Range on June 30, 2019E @ 8.8% Discount Rate $396.3 $498.9 2020E Corporate G&A Expense $49.8 Relevant Multiple1 7.4x—9.3x Implied AMID Corporate G&A Liability Based on 2020E Expense $366.8—$461.8 Implied Enterprise Value Range on June 30, 2019E @ 8.8% Discount Rate $337.1 $424.3 Implied Value of AMID Corporate G&A Liability $337.1 $498.9 Peer Trading Summary Results 2019E Corporate G&A Expense $55.0 Relevant Multiple1 9.2x—10.9x Implied AMID Corporate G&A Liability Based on 2019E Expense $508.2—$600.4 2020E Corporate G&A Expense $49.8 Relevant Multiple1 8.1x—10.5x Implied AMID Corporate G&A Liability Based on 2020E Expense $405.2—$521.2 1. Based on weighted average EBITDA multiple used in the Sum of the Parts analysis excluding Delta House 130 VI. Illustrative AMID Unitholder Tax Analysis

Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis @ Illustrative Offer Price ($5.25 / unit) – Assumptions ? PricewaterhouseCoopers LLP (“PwC”) provided the AMID unaffiliated unitholders tax liability by unit acquisition date information, which included the following: ? Adjusted Basis – Represents the weighted average price acquired, plus cumulative income, less cumulative distributions and DD&A from the acquisition date to January 2018 ? §751 Gain – Recharacterization of gain or loss on the sale of a partnership interest from capital to ordinary on §751 property owned by the partnership ? Net Ordinary Gain / (Loss) per Unit – Calculated as §751 Gain less Passive Loss Carryover assuming Passive Loss Carryover amounts are 100% available to offset Ordinary Gains ? Net Capital Gain / (Loss) per Unit – Calculated as Total Gain / (Loss) per Unit less §751 Gain ? Estimated Taxes – Calculated based on the Net Ordinary Gain / Loss per Unit and Net Capital Gain / (Loss) per Unit assuming the unitholder tax rates as set forth in table below Type Ordinary Gain Tax Rate (T1) Capital Gain Tax Rate (T2) Individual 29.6% 20.0% Corporation 21.0% 21.0% Partnership 29.6% 20.0% Estate 29.6% 20.0% Trust 29.6% 20.0% Foreign 21.0% 21.0% UBTI 21.0% 21.0% Other 29.6% 20.0% 131 Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis by Year Acquired @ $5.25 per Unit Ordinary Gain / (Loss) Total Gain / (Loss) Per Unit Per Unit Capital Gain / (Loss) Per Unit Tax Liability Per Unit A B C = A—B D E F = D + E C D G = C – D H = F * T1 I = G * T2 J = H + I Average Ordinary Tax Capital Tax Total Tax % of Total Purchase Offer Adjusted Total Gain / Carryover Net Ordinary Total Gain / Net Capital Liability / Liability / Liability / Year AMID Units Units Price Price Basis (Loss) 751 Gain Passive Losses Gain / (Loss) (Loss) 751 Gain Gain / (Loss) (Benefit) (Benefit) (Benefit) 2011 431,098 1.1% $19.53 $5.25 ($16.76) $22.01 $9.41 ($19.76) ($10.35) $22.01 $9.41 $12.60 ($3.02) $2.52 ($0.50) 2012 443,166 1.2% 19.44 5.25 (11.96) 17.21 8.74 (20.29) (11.55) 17.21 8.74 8.47 (3.16) 1.72 (1.44) 2013 826,804 2.2% 18.62 5.25 (9.89) 15.14 6.16 (19.36) (13.21) 15.14 6.16 8.98 (3.15) 1.86 (1.29) 2014 3,036,352 7.9% 21.94 5.25 0.10 5.15 6.30 (15.13) (8.83) 5.15 6.30 (1.15) (2.46) (0.23) (2.69) 2015 5,309,239 13.9% 11.30 5.25 (6.55) 11.80 5.67 (12.77) (7.10) 11.80 5.67 6.13 (1.76) 1.26 (0.50) 2016 14,537,257 38.0% 8.90 5.25 (4.71) 9.96 4.63 (10.06) (5.43) 9.96 4.63 5.33 (1.47) 1.08 (0.39) 2017 12,799,597 33.5% 13.03 5.25 4.11 1.14 3.16 (6.81) (3.64) 1.14 3.16 (2.03) (0.94) (0.41) (1.35) 2018 823,557 2.2% 11.85 5.25 6.15 (0.90) 2.13 (4.67) (2.53) (0.90) 2.13 (3.03) (0.73) (0.61) (1.34) Total / Wtd. Avg. 38,207,069 100.0% $12.16 $5.25 ($1.73) $6.98 $4.50 ($10.06) ($5.57) $6.98 $4.50 $2.48 ($1.47) $0.51 ($0.96) 132

Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis by Month Acquired @ $5.25 per Unit Ordinary Gain / (Loss) Total Gain / (Loss) Per Unit Per Unit Capital Gain / (Loss) Per Unit Tax Liability Per Unit A B C = A—B D E F = D + E C G H = C – G H = F * T1 I = G * T2 J = H + I Average Ordinary Tax Capital Tax Total Tax % of Total Purchase Offer Adjusted Total Gain / Carryover Net Ordinary Total Gain / Net Capital Liability / Liability / Liability / Month AMID Units Units Price Price Basis (Loss) 751 Gain Passive Losses Gain / (Loss) (Loss) 751 Gain Gain / (Loss) (Benefit) (Benefit) (Benefit) 08/2011 267,696 0.7% $20.79 $5.25 ($18.69) $23.94 $9.45 ($20.11) ($10.66) $23.94 $9.45 $14.49 ($3.14) $2.90 ($0.24) 09/2011 43,331 0.1% 16.26 5.25 (14.12) 19.37 9.39 (18.50) (9.11) 19.37 9.39 9.98 (2.62) 2.01 (0.61) 10/2011 57,668 0.2% 18.13 5.25 (13.21) 18.46 9.45 (19.46) (10.00) 18.46 9.45 9.01 (2.88) 1.81 (1.07) 11/2011 15,581 0.0% 17.70 5.25 (13.45) 18.70 9.26 (19.27) (10.01) 18.70 9.26 9.44 (2.92) 1.89 (1.03) 12/2011 46,821 0.1% 17.66 5.25 (13.63) 18.88 9.19 (19.41) (10.22) 18.88 9.19 9.69 (2.91) 1.95 (0.96) 01/2012 56,514 0.1% 17.95 5.25 (13.18) 18.43 9.16 (19.52) (10.36) 18.43 9.16 9.27 (2.87) 1.87 (0.99) 02/2012 32,048 0.1% 18.89 5.25 (12.62) 17.87 8.96 (19.90) (10.94) 17.87 8.96 8.91 (2.84) 1.82 (1.02) 03/2012 29,013 0.1% 20.50 5.25 (11.88) 17.13 8.89 (20.76) (11.87) 17.13 8.89 8.24 (3.33) 1.66 (1.67) 04/2012 125,148 0.3% 21.10 5.25 (11.16) 16.41 8.82 (21.08) (12.27) 16.41 8.82 7.60 (3.54) 1.53 (2.01) 05/2012 5,848 0.0% 21.26 5.25 (10.97) 16.22 8.74 (21.05) (12.31) 16.22 8.74 7.48 (2.59) 1.57 (1.01) 06/2012 68,628 0.2% 18.90 5.25 (12.45) 17.70 8.67 (20.17) (11.51) 17.70 8.67 9.03 (3.41) 1.81 (1.60) 07/2012 33,425 0.1% 19.20 5.25 (11.86) 17.11 8.59 (20.31) (11.72) 17.11 8.59 8.51 (2.74) 1.76 (0.98) 08/2012 17,585 0.0% 19.79 5.25 (11.18) 16.43 8.50 (20.23) (11.73) 16.43 8.50 7.93 (2.79) 1.64 (1.15) 09/2012 14,311 0.0% 19.20 5.25 (11.66) 16.91 8.41 (20.11) (11.70) 16.91 8.41 8.50 (2.71) 1.76 (0.94) 10/2012 26,589 0.1% 18.65 5.25 (11.54) 16.79 8.46 (19.88) (11.43) 16.79 8.46 8.34 (2.85) 1.71 (1.13) 11/2012 11,265 0.0% 18.96 5.25 (11.23) 16.48 8.36 (19.88) (11.52) 16.48 8.36 8.13 (2.86) 1.67 (1.19) 12/2012 22,793 0.1% 15.94 5.25 (13.08) 18.33 8.10 (18.70) (10.61) 18.33 8.10 10.23 (3.10) 2.05 (1.04) 01/2013 38,986 0.1% 14.57 5.25 (13.66) 18.91 7.82 (18.35) (10.53) 18.91 7.82 11.09 (2.54) 2.29 (0.25) 02/2013 30,849 0.1% 15.95 5.25 (12.38) 17.63 7.76 (18.45) (10.70) 17.63 7.76 9.88 (2.83) 2.01 (0.82) 03/2013 27,598 0.1% 16.66 5.25 (12.41) 17.66 7.81 (19.19) (11.39) 17.66 7.81 9.86 (3.27) 1.98 (1.29) 04/2013 85,157 0.2% 16.60 5.25 (12.15) 17.40 7.74 (19.30) (11.56) 17.40 7.74 9.65 (2.60) 2.01 (0.59) 05/2013 123,566 0.3% 16.53 5.25 (11.29) 16.54 5.82 (18.37) (12.55) 16.54 5.82 10.72 (2.84) 2.23 (0.61) 06/2013 162,294 0.4% 18.95 5.25 (9.67) 14.92 5.77 (19.37) (13.60) 14.92 5.77 9.16 (3.51) 1.87 (1.64) 07/2013 98,261 0.3% 20.55 5.25 (8.70) 13.95 5.68 (20.24) (14.55) 13.95 5.68 8.27 (3.23) 1.72 (1.51) 08/2013 98,280 0.3% 19.64 5.25 (9.08) 14.33 5.60 (19.70) (14.10) 14.33 5.60 8.73 (3.05) 1.83 (1.22) 09/2013 76,460 0.2% 19.79 5.25 (9.15) 14.40 5.46 (20.13) (14.67) 14.40 5.46 8.94 (3.31) 1.86 (1.45) 10/2013 23,935 0.1% 19.95 5.25 (8.94) 14.19 5.32 (20.30) (14.98) 14.19 5.32 8.87 (3.87) 1.81 (2.06) 11/2013 52,058 0.1% 19.94 5.25 (4.80) 10.05 5.08 (17.64) (12.56) 10.05 5.08 4.97 (3.47) 0.90 (2.58) 12/2013 9,360 0.0% 22.25 5.25 (7.31) 12.56 5.05 (20.98) (15.93) 12.56 5.05 7.52 (4.48) 1.52 (2.96) 01/2014 98,255 0.3% 22.41 5.25 (3.09) 8.34 7.23 (17.37) (10.13) 8.34 7.23 1.11 (2.92) 0.22 (2.70) 02/2014 82,749 0.2% 25.87 5.25 (1.30) 6.55 7.27 (19.04) (11.77) 6.55 7.27 (0.72) (2.90) (0.15) (3.05) 03/2014 41,914 0.1% 24.11 5.25 (2.62) 7.87 7.22 (18.83) (11.61) 7.87 7.22 0.65 (3.29) 0.13 (3.15) 04/2014 113,220 0.3% 24.13 5.25 (2.37) 7.62 7.14 (18.82) (11.69) 7.62 7.14 0.48 (3.12) 0.10 (3.02) 05/2014 310,048 0.8% 25.37 5.25 (1.02) 6.27 7.00 (18.70) (11.69) 6.27 7.00 (0.73) (3.44) (0.15) (3.58) 06/2014 139,500 0.4% 26.67 5.25 (0.49) 5.74 6.67 (19.54) (12.87) 5.74 6.67 (0.93) (2.92) (0.19) (3.11) 07/2014 38,645 0.1% 28.62 5.25 1.15 4.10 6.60 (20.25) (13.65) 4.10 6.60 (2.50) (3.72) (0.51) (4.23) 08/2014 49,223 0.1% 27.81 5.25 1.23 4.02 6.52 (19.30) (12.79) 4.02 6.52 (2.50) (3.30) (0.51) (3.81) 09/2014 937,032 2.5% 29.59 5.25 2.03 3.22 6.51 (20.34) (13.83) 3.22 6.51 (3.29) (4.09) (0.66) (4.75) 10/2014 47,707 0.1% 28.50 5.25 1.73 3.52 6.56 (20.01) (13.45) 3.52 6.56 (3.04) (3.41) (0.62) (4.03) 11/2014 1,082,778 2.8% 12.38 5.25 (0.55) 5.80 5.56 (7.44) (1.88) 5.80 5.56 0.25 (0.42) 0.05 (0.37) 133 Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis by Month Acquired @ $5.25 per Unit Ordinary Gain / (Loss) Total Gain / (Loss) Per Unit Per Unit Capital Gain / (Loss) Per Unit Tax Liability Per Unit A B C = A—B D E F = D + E C G H = C – G H = F * T1 I = G * T2 J = H + I Average Ordinary Tax Capital Tax Total Tax % of Total Purchase Offer Adjusted Total Gain / Carryover Net Ordinary Total Gain / Net Capital Liability / Liability / Liability / Month AMID Units Units Price Price Basis (Loss) 751 Gain Passive Losses Gain / (Loss) (Loss) 751 Gain Gain / (Loss) (Benefit) (Benefit) (Benefit) 12/2014 95,280 0.2% $20.70 $5.25 ($0.27) $5.52 $6.22 ($14.78) ($8.56) $5.52 $6.22 ($0.70) ($2.38) ($0.14) ($2.52) 01/2015 381,468 1.0% 14.86 5.25 (4.13) 9.38 5.68 (13.05) (7.38) 9.38 5.68 3.70 (1.78) 0.76 (1.02) 02/2015 239,550 0.6% 16.55 5.25 (5.77) 11.02 5.82 (16.10) (10.28) 11.02 5.82 5.19 (2.99) 1.04 (1.95) 03/2015 202,794 0.5% 17.15 5.25 (4.81) 10.06 5.77 (16.14) (10.36) 10.06 5.77 4.29 (3.07) 0.86 (2.21) 04/2015 290,539 0.8% 15.02 5.25 (5.81) 11.06 5.60 (15.14) (9.54) 11.06 5.60 5.46 (2.75) 1.10 (1.65) 05/2015 119,048 0.3% 12.50 5.25 (4.23) 9.48 5.37 (11.27) (5.90) 9.48 5.37 4.11 (1.44) 0.84 (0.60) 06/2015 113,234 0.3% 13.35 5.25 (4.09) 9.34 5.32 (11.95) (6.64) 9.34 5.32 4.02 (1.58) 0.83 (0.75) 07/2015 155,373 0.4% 15.36 5.25 (5.13) 10.38 5.48 (15.23) (9.75) 10.38 5.48 4.90 (2.51) 1.00 (1.50) 08/2015 294,672 0.8% 12.11 5.25 (6.74) 11.99 5.75 (13.58) (7.83) 11.99 5.75 6.24 (1.90) 1.29 (0.62) 09/2015 411,749 1.1% 9.98 5.25 (5.70) 10.95 5.37 (10.89) (5.52) 10.95 5.37 5.58 (1.45) 1.13 (0.32) 10/2015 2,323,787 6.1% 9.78 5.25 (7.73) 12.98 5.82 (12.67) (6.84) 12.98 5.82 7.15 (1.54) 1.49 (0.05) 11/2015 335,578 0.9% 8.89 5.25 (6.08) 11.33 5.39 (10.25) (4.86) 11.33 5.39 5.94 (1.19) 1.21 0.02 12/2015 441,447 1.2% 8.47 5.25 (6.99) 12.24 5.43 (11.08) (5.64) 12.24 5.43 6.81 (1.50) 1.39 (0.11) 01/2016 1,297,532 3.4% 4.88 5.25 (8.41) 13.66 5.10 (8.95) (3.85) 13.66 5.10 8.56 (1.05) 1.74 0.69 02/2016 1,643,686 4.3% 6.13 5.25 (7.21) 12.46 4.94 (9.01) (4.06) 12.46 4.94 7.52 (1.17) 1.51 0.35 03/2016 1,475,594 3.9% 4.49 5.25 (6.85) 12.10 4.50 (7.41) (2.92) 12.10 4.50 7.60 (0.79) 1.54 0.75 04/2016 602,390 1.6% 4.93 5.25 (6.91) 12.16 4.69 (7.99) (3.30) 12.16 4.69 7.47 (0.84) 1.54 0.70 05/2016 1,089,840 2.9% 8.69 5.25 (5.45) 10.70 5.16 (10.25) (5.09) 10.70 5.16 5.54 (1.25) 1.14 (0.11) 06/2016 623,433 1.6% 9.52 5.25 (4.12) 9.37 5.00 (10.11) (5.11) 9.37 5.00 4.37 (1.44) 0.89 (0.55) 07/2016 575,649 1.5% 10.79 5.25 (3.76) 9.01 4.75 (11.06) (6.32) 9.01 4.75 4.27 (1.70) 0.87 (0.83) 08/2016 635,891 1.7% 9.56 5.25 (3.67) 8.92 4.52 (9.77) (5.25) 8.92 4.52 4.40 (1.29) 0.90 (0.39) 09/2016 3,831,444 10.0% 11.51 5.25 (3.20) 8.45 4.52 (11.61) (7.08) 8.45 4.52 3.93 (2.02) 0.79 (1.23) 10/2016 781,682 2.0% 9.59 5.25 (2.62)��7.87 3.81 (9.16) (5.34) 7.87 3.81 4.05 (1.46) 0.82 (0.64) 11/2016 1,047,467 2.7% 12.52 5.25 (2.23) 7.48 4.30 (11.66) (7.36) 7.48 4.30 3.18 (1.92) 0.65 (1.27) 12/2016 932,651 2.4% 11.72 5.25 (1.97) 7.22 4.29 (10.95) (6.66) 7.22 4.29 2.93 (1.58) 0.60 (0.98) 01/2017 1,327,151 3.5% 14.27 5.25 0.86 4.39 4.54 (10.74) (6.19) 4.39 4.54 (0.15) (1.36) (0.03) (1.40) 02/2017 568,455 1.5% 15.19 5.25 4.00 1.25 3.49 (8.51) (5.01) 1.25 3.49 (2.24) (1.21) (0.47) (1.68) 03/2017 928,501 2.4% 13.34 5.25 2.81 2.44 3.24 (7.85) (4.61) 2.44 3.24 (0.80) (1.25) (0.16) (1.41) 04/2017 1,754,948 4.6% 14.35 5.25 4.94 0.31 3.05 (7.14) (4.09) 0.31 3.05 (2.74) (1.15) (0.55) (1.70) 05/2017 789,873 2.1% 14.35 5.25 5.38 (0.13) 2.95 (6.70) (3.75) (0.13) 2.95 (3.09) (0.99) (0.63) (1.62) 06/2017 2,148,456 5.6% 12.05 5.25 3.80 1.45 3.15 (5.98) (2.83) 1.45 3.15 (1.70) (0.75) (0.35) (1.10) 07/2017 1,075,846 2.8% 11.20 5.25 3.73 1.52 3.14 (5.61) (2.47) 1.52 3.14 (1.62) (0.67) (0.33) (1.00) 08/2017 1,100,931 2.9% 12.60 5.25 5.06 0.19 2.74 (5.68) (2.94) 0.19 2.74 (2.55) (0.73) (0.52) (1.25) 09/2017 790,298 2.1% 12.75 5.25 5.28 (0.03) 2.47 (5.61) (3.14) (0.03) 2.47 (2.51) (0.78) (0.51) (1.30) 10/2017 293,259 0.8% 12.85 5.25 5.15 0.10 3.08 (6.26) (3.18) 0.10 3.08 (2.98) (0.82) (0.61) (1.43) 11/2017 1,125,458 2.9% 12.50 5.25 5.22 0.03 2.95 (5.83) (2.88) 0.03 2.95 (2.93) (0.74) (0.60) (1.34) 12/2017 896,422 2.3% 11.85 5.25 4.88 0.37 2.73 (5.53) (2.80) 0.37 2.73 (2.36) (0.78) (0.48) (1.26) 01/2018 823,557 2.2% 11.85 5.25 6.15 (0.90) 2.13 (4.67) (2.53) (0.90) 2.13 (3.03) (0.73) (0.61) (1.34) Total / Wtd. Avg. 38,207,069 100.0% $12.16 $5.25 ($1.73) $6.98 $4.50 ($10.06) ($5.57) $6.98 $4.50 $2.48 ($1.47) $0.51 ($0.96) 134

Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis @ Illustrative Offer Price ($5.25 / unit) Implied Taxes 36.0 34.0 Tax Liability Deciles ($ per unit) 32.0 First Decile ($4.75)—($1.95) Sixth Decile ($1.13)—($0.99) Second Decile ($1.95)—($1.43) Seventh Decile ($0.99)—($0.55) 30.0 Third Decile ($1.43)—($1.34) Eighth Decile ($0.55)—($0.11) 28.0 Fourth Decile ($1.34)—($1.25) Ninth Decile ($0.11)—$0.02 Fifth Decile ($1.25)—($1.13) Tenth Decile $0.02—$0.75 26.0 Weighted Average ($0.96) 24.0 Total Tax Liability (Benefits) of Unaffiliated Unitholders ($MM) ($36.8) 22.0 Includes all units with zero tax 20.0 consequences or net tax benefits resulting n s) 18.0 from the Merger Millio (in 16.0 Units 14.0 12.0 10.0 8.0 6.0 4.0 2.0 0.0 —$ $0.01 $0.03 $0.04 $0.05 $0.06 $0.08 $0.09 $0.10 $0.12 $0.13 $0.14 $0.16 $0.17 $0.18 $0.19 $0.21 $0.22 $0.23 $0.25 $0.26 $0.27 $0.29 $0.30 $0.31 $0.32 $0.34 $0.35 $0.36 $0.38 $0.39 $0.40 $0.42 $0.43 $0.44 $0.45 $0.47 $0.48 $0.49 $0.51 $0.52 $0.53 $0.55 $0.56 $0.57 $0.58 $0.60 $0.61 $0.62 $0.64 $0.65 $0.66 $0.68 $0.69 $0.70 $0.71 $0.73 $0.74 $0.75 $0.77 $0.78 $0.79 $0.81 $0.82 $0.83 $0.84 $0.86 $0.87 $0.88 $0.90 $0.91 $0.92 $0.94 $0.95 $0.96 $0.97 $0.99 $1.00 Net Taxes Paid per AMID Unit 135 $ ( $ ( $ ( $ ( 40 30 20 10 $ 10 20 $ 30 $ 40 $ . . . . $ . 00 . 00 . 00 . 00 00) 00) 00) 00) — ($3.04) .83 5) ($ ($24.08) 408. ) First ($ ($2.55) Precedent 82) 2. ($ 3.33 ) ($ Decile $— Illustrative $6.00 4 ) 75. ($ ) 2.59 ($ 1. 11) ($ Taxable 84) 1 .9 ($ ($5.18) Second ) 42.1 ($ AMID $0.00 2. 64) ($ 3. 04 $ MLP MLP $7.03 A Decile 1.95 ) ($ .34) 2 ($ 0. 2 2 $ Buy ($1641) . -Third 2. 96) ($ MLP 1. 57) ($In B 58 0. $ ($1.23) Decile $3.23 13 8. $ Unitholder ($1.3) 4 MLP ($1.8) 0 C 0. 83 $ ($11.1 )8 Fourth ($2.90) Tax ($1.4 4) Estimated $0.95 Unitholder ($0 ).95 MLP $3.1 6 D Decile $11.32 ($1 4).3 Cash Tax ($0.03) $1 5 .0 ($2.44) Tax MLP Fifth ($2. 0)9 E ($0. 7)8 $1.22 Analysis ($0.56) Impact 136 Decile $3. 70 MLP ($1.25 ) $12 7 8. (Benefit) F $0. 1 3 $1. 51 / $0.60 Sixth ($2. 7)7 ($0. 4)4 $1 9 9. MLP ($0. 36) G Decile $4.00 $14.94 ($1. 13)Expense $0 71 . $2. 14 MLP $1. 89 per ($1. ) 23 H Seventh ($0.1 )4 ($0. 7) $2.52 Unit 0 $4.18 Decile $1 4 95. MLP ($0.99 ) I $1. 6 4 $5.50 $4.47 Eighth $1. 01 $1. 3 1 AMID $3. 4 8 $0. 1 0 $4.64 Decile $16.68 ($0.55) $2.00 $1 7 00. $5.71 Ninth $2 8 .8 $1.5 4 $5.75 $1. 2 0 Decile $5. 5 0 $19.98 ($0. 1)1 $3 3 .3 $14.35 $13.49 Tenth $6 11 . $2. 5 4 $6.94 $8.51 Decile $5.70 $21 4 6. $0. 02

. (150 . (125 (100 . . (75 . (50 . (25 25 . 50 . . 75 100 . 0%) 0%) 0%) 0%) 0%) 0%) % — 0% 0% 0% 0% (25.5%) %) (8.1 (100.3%) 6.(2 % 7 First ) .2(7 % )Precedent (6. 9% ) .9%) 0(3 Decile —% Illustrative % 4.61 (105.6%) (21 .7% ) (2.3%) Taxable .89%) (7 (16 % .5 ) Second (6. 1%) AMID .0% 0 5%) (2 4. MLP 6.51 % MLP Decile 1 % 7.2 A .33% (4 ) 6% 9.(1 ) 5% 0. Buy Third (60.9%) (9.4%) - In MLP (4.5%) B 1.4 % Estimated 1.4(1 % ) Decile 71 .5% 981 % . Unitholder (31.8%) MLP (9% .1 ) Cash C (4 %) % 71. 6.6 Fourth (9.2%) Tax (4.1%) Tax % .2 3 Unitholder (8.8 %) MLP 5% 1 9. D Decile 27 .6% (29 .7% ) Tax (0 .3% ) 2.2% (Benefit) (10. 2%) MLP Fifth (9.2 %) / E (2 %) 3 0% .5 . Analysis (5 % ) .2 Impact 137 Decile 2 % 0.1 MLP (27 9% ) 3% 1.4 . F 2 % .6 Expense 3.2 % 2. 5% Sixth (8. 8% ) per (1. % ) 3 (cont’d) 4 % .9 MLP (3 % ) .3 G Decile 2 % 1.7 Unit 36 % .4 (25 .2% ) 6. 0% as 4.5 % MLP 7 % % .9 (3. 9% ) H Seventh (0 %) of .4 (0 %) 6 2% . .6 22 % .7 Decile 3 % 8.9 MLP (2 % ) Offer 02. I 1 .3% 2 1 % 1.5 18. % 6 Eighth 3 % 2. 3 % 2. 9.4 % Value AMID 0 1% . 2 % 5.2 Decile 40 .7% (1 2%)2. 1 % .86 2 % .11 2 % 8.3 Ninth 9 .2% 4 % 4. 1 % .14 9 % .5 Decile 2 % 7.3 48 7% . (2. 4%) 28. 0% 30 1% . 5 % 6.2 Tenth 1 % 95. 6 9% . 1 % 7.0 79 % 0. Decile 30. 9% 5 % 2.8 0.5 % Appendix

A. Weighted Average Cost of Capital Analysis Weighted Average Cost of Capital Analysis AMID Total Partnership ($ in millions, except per unit / share amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Corporation 3/15/19 Value Preferred Equity Equity / Total Capitalization Beta Beta 1,2 Partnership / CNX Midstream Partners LP $14.61 $949 $477 33.5% 0.99 0.73 Crestwood Equity Partners LP 34.15 2,432 2,365 49.3% 0.87 0.52 DCP Midstream Partners, LP 31.14 4,554 6,383 58.4% 1.09 0.55 Natural Gas Enable Midstream Partners, LP 14.59 6,321 4,640 42.3% 0.79 0.52 Gathering and Hess Midstream Partners LP 22.33 1,244——% 0.95 0.95 Processing Noble Midstream Partners LP 37.25 1,482 559 27.4% 0.93 0.73 Summit Midstream Partners, LP 9.33 781 1,835 70.1% 0.85 0.32 Targa Resources Corp. 40.04 9,295 8,552 47.9% 0.98 0.57 Unlevered Beta Median 45.1% 0.94 0.56 Plains All American Pipeline, L.P. 24.30 17,656 11,501 39.4% 0.96 0.66 Genesis Energy, L.P. 22.62 2,772 4,194 60.2% 1.07 0.52 Offshore Shell Midstream Partners, L.P. 19.24 4,394 2,116 32.5% 0.79 0.59 Median 39.4% 0.96 0.59 American Midstream Partners, LP $4.00 $220 $1,348 86.0% 0.72 0.17 Historical MRP Supply-Side MRP Risk-free Rate 3 2.8% 2.8% Historical MRP (7.1%) WACC Sensitivities Unlevered Beta 0.30 0.30 Debt and Preferred / Total Capitalization 57.5% 57.5% Unlevered Beta Adjusted Levered Equity Beta 0.59 0.59 l 0.20 0.25 0.30 0.35 0.40 on 45.0% 8.7% 9.0% 9.3% 9.6% 9.9% Cost of 4 Tota i Market Risk Premium (“MRP”) 7.1% 6.0% nd / 50.0% 8.6% 8.9% 9.2% 9.5% 9.8% a zat Equity / WACC Small Company Risk Premium 5 5.0% 5.0% d i 55.0% 8.6% 8.8% 9.1% 9.4% 9.7% Equity Cost of Capital 6 12.0% 11.4% Debt erre 60.0% 8.5% 8.8% 9.1% 9.4% 9.6% re f Capital 65.0% 8.4% 8.7% 9.0% 9.3% 9.6% Pre-Tax Cost of Debt 7 9.9% 9.9% P 70.0% 8.4% 8.6% 8.9% 9.2% 9.5% After-Tax Cost of Debt 2 7.0% 7.0% WACC 9.1% 8.9% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta 0.20 0.25 0.30 0.35 0.40 Total on 45.0% 8.5% 8.8% 9.0% 9.3% 9.6% and / zati 50.0% 8.4% 8.7% 9.0% 9.2% 9.5% i 55.0% 8.4% 8.6% 8.9% 9.1% 9.4% Debt erred 60.0% 8.3% 8.6% 8.8% 9.1% 9.3% f Pre Capital 65.0% 8.3% 8.5% 8.7% 9.0% 9.2% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 70.0% 8.2% 8.4% 8.7% 8.9% 9.1% 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) for Partnerships and tax rate of 21.0% for Corporations 3. 20-year Treasury as of March 15, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10x) by Duff & Phelps with a market capitalization between $166.5 million and $227.8 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on a weighted average of AMID’s debt and preferred capital: (i) yield to worst for AMID’s 8.500% 2021 Senior Unsecured Notes as of March 15, 2019, (ii) interest rate on AMID’s revolving credit facility due September 5, 2019, (iii) implied cost of convertible preferred equity and (iv) interest rate on secured debt, each extended to 20-years by addition of a premium for U.S. Treasury maturing March 15, 2039, as applicable 138

Weighted Average Cost of Capital Analysis Natural Gas Gathering and Processing ($ in millions, except per unit / share amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Corporation 3/15/19 Value Preferred Equity Equity / Total Capitalization Beta Beta 1,2 Partnership / CNX Midstream Partners LP $14.61 $949 $477 33.5% 0.99 0.73 Crestwood Equity Partners LP 34.15 2,432 2,365 49.3% 0.87 0.52 DCP Midstream Partners, LP 31.14 4,554 6,383 58.4% 1.09 0.55 Natural Gas Enable Midstream Partners, LP 14.59 6,321 4,640 42.3% 0.79 0.52 Unlevered Gathering and Hess Midstream Partners LP 22.33 1,244——% 0.95 0.95 Beta Processing Noble Midstream Partners LP 37.25 1,482 559 27.4% 0.93 0.73 Summit Midstream Partners, LP 9.33 781 1,835 70.1% 0.85 0.32 Targa Resources Corp. 40.04 9,295 8,552 47.9% 0.98 0.57 Median 45.1% 0.94 0.56 Historical MRP Supply-Side MRP Risk-free Rate 3 2.8% 2.8% Unlevered Beta 0.56 0.56 Historical MRP (7.1%) WACC Sensitivities Debt and Preferred / Total Capitalization 45.1% 45.1% Unlevered Beta Adjusted Levered Equity Beta 0.88 0.88/ 0.30 0.40 0.50 0.60 0.70 4 ed 30.0% 7.0% 7.6% 8.2% 8.9% 9.5% Cost of Market Risk Premium (“MRP”) 7.1% 6.0% rr zation e i 35.0% 6.9% 7.5% 8.1% 8.8% 9.4% Equity / WACC Small Company Risk Premium 5 2.5% 2.5% ef al 6 r t 40.0% 6.8% 7.4% 8.0% 8.7% 9.3% Equity Cost of Capital 11.6% 10.7% nd P Capi 45.0% 6.7% 7.3% 7.9% 8.5% 9.2% 7 al 50.0% 6.6% 7.2% 7.8% 8.4% 9.0% Pre-Tax Cost of Debt 6.1% 6.1%bt a 55.0% 6.5% 7.1% 7.7% 8.3% 8.9% After-Tax Cost of Debt 2 4.3% 4.3% D e Tot 60.0% 6.5% 7.0% 7.6% 8.2% 8.8% WACC 8.3% 7.8% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d ization e 30.0% 6.7% 7.2% 7.8% 8.3% 8.9% err 35.0% 6.6% 7.1% 7.7% 8.2% 8.8% ef l r pita 40.0% 6.5% 7.1% 7.6% 8.1% 8.6% nd P a 45.0% 6.4% 7.0% 7.5% 8.0% 8.5% C 50.0% 6.4% 6.9% 7.4% 7.9% 8.4% a Debt Total 55.0% 6.3% 6.8% 7.3% 7.8% 8.3% 60.0% 6.2% 6.7% 7.2% 7.7% 8.2% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) for Partnerships and tax rate of 21.0% for Corporations 3. 20-year Treasury as of March 15, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 9) by Duff & Phelps with a market capitalization between $299.4 million and $656.8 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Natural Gas G&P peers’ Senior Unsecured Notes as of March 15, 2019 with an average maturity of December 5, 2028, extended to 20-years by addition of 22 bps premium for U.S. Treasury maturing March 15, 2039 versus U.S. Treasury maturing December 5, 2028 139 Weighted Average Cost of Capital Analysis Natural Gas Transportation ($ in millions, except per unit / share amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Partnership / Corporation 3/15/19 Value Preferred Equity Equity / Total Capitalization Beta Beta 1,2 EQT Midstream Partners, LP $44.09 $9,147 $5,182 36.2% 0.85 0.61 Enable Midstream Partners, LP 14.59 6,321 4,640 42.3% 0.79 0.52 Natural Gas TC PipeLines, LP 35.36 2,573 2,072 44.6% 0.84 0.54 Unlevered Tallgrass Energy, LP 24.05 6,740 3,206 32.2% 0.67 0.49 Transportation Beta The Williams Companies, Inc. 27.56 33,499 22,449 40.1% 1.00 0.66 Median 40.1% 0.84 0.54 Historical MRP Supply-Side MRP Historical MRP (7.1%) WACC Sensitivities Risk-free Rate 3 2.8% 2.8% Unlevered Beta 0.54 0.54 Unlevered Beta Debt and Preferred / Total Capitalization 40.1% 40.1%/ 0.30 0.40 0.50 0.60 0.70 edrr 30.0% 9.9% 10.5% 11.2% 11.8% 12.5% Adjusted Levered Equity Beta 0.79 0.79 zation e ef i 35.0% 9.6% 10.2% 10.8% 11.5% 12.1% Cost of 4 r t al 40.0% 9.2% 9.8% 10.5% 11.1% 11.7% Market Risk Premium (“MRP”) 7.1% 6.0% 45.0% 8.9% 9.5% 10.1% 10.7% 11.3% Equity / WACC Small Company Risk Premium 5 7.0% 7.0% nd P Capi al 50.0% 8.5% 9.1% 9.7% 10.3% 11.0% Equity Cost of Capital 6 15.4% 14.6%bt a 55.0% 8.2% 8.8% 9.4% 10.0% 10.6% 7 De Tot 60.0% 7.9% 8.4% 9.0% 9.6% 10.2% Pre-Tax Cost of Debt 5.2% 5.2% After-Tax Cost of Debt 2 3.7% 3.7% Supply-Side MRP (6.0%) WACC Sensitivities WACC 10.7% 10.2% Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d ization e 30.0% 9.6% 10.2% 10.7% 11.3% 11.8% err 35.0% 9.3% 9.8% 10.4% 10.9% 11.4% ef l r pita 40.0% 8.9% 9.5% 10.0% 10.5% 11.1% nd P a 45.0% 8.6% 9.1% 9.7% 10.2% 10.7% C 50.0% 8.3% 8.8% 9.3% 9.8% 10.3% a Debt Total 55.0% 7.9% 8.4% 9.0% 9.5% 10.0% 60.0% 7.6% 8.1% 8.6% 9.1% 9.6% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) for Partnerships and tax rate of 21.0% for Corporations 3. 20-year Treasury as of March 15, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10y) by Duff & Phelps with a market capitalization between $87.6 million and $166.3 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Natural Gas Transportation peers’ Senior Unsecured Notes as of March 15, 2019 with an average maturity of February 6, 2032, extended to 20-years by addition of 15 bps premium for U.S. Treasury maturing March 15, 2039 versus U.S. Treasury maturing February 6, 2032 140

Weighted Average Cost of Capital Analysis Offshore Pipelines ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered 1,2 Partnership / Corporation 3/15/19 Value Preferred Equity Equity / Total Capitalization Beta Beta Plains All American Pipeline, L.P. $24.30 $17,656 $11,501 39.4% 0.96 0.66 Genesis Energy, L.P. 22.62 2,772 4,194 60.2% 1.07 0.52 Unlevered Offshore Shell Midstream Partners, L.P. 19.24 4,394 2,116 32.5% 0.79 0.59 Beta Median 39.4% 0.96 0.59 Historical MRP Supply-Side MRP Risk-free Rate 3 2.8% 2.8% Unlevered Beta 0.59 0.59 Debt and Preferred / Total Capitalization 39.4% 39.4% Adjusted Levered Equity Beta 0.86 0.86 4 Historical MRP (7.1%) WACC Sensitivities Cost of Market Risk Premium (“MRP”) 7.1% 6.0% Equity / WACC Small Company Risk Premium 5 2.5% 2.5% Unlevered Beta 6 0.30 0.40 0.50 0.60 0.70 Equity Cost of Capital 11.4% 10.5% d / re tion 30.0% 7.0% 7.6% 8.3% 8.9% 9.5% z a Pre-Tax Cost of Debt 7 6.2% 6.2% i 35.0% 6.9% 7.5% 8.1% 8.8% 9.4% efer l 2 40.0% 6.8% 7.4% 8.0% 8.7% 9.3% After-Tax Cost of Debt 4.3% 4.3% Pr pita 45.0% 6.7% 7.3% 7.9% 8.6% 9.2% and Ca 50.0% 6.6% 7.2% 7.8% 8.4% 9.0% WACC 8.6% 8.1%bt 55.0% 6.6% 7.1% 7.7% 8.3% 8.9% D e Total 60.0% 6.5% 7.1% 7.6% 8.2% 8.8% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d ization e 30.0% 6.7% 7.2% 7.8% 8.3% 8.9% err 35.0% 6.6% 7.1% 7.7% 8.2% 8.8% ef l r pita 40.0% 6.5% 7.1% 7.6% 8.1% 8.7% nd P a 45.0% 6.5% 7.0% 7.5% 8.0% 8.5% C 50.0% 6.4% 6.9% 7.4% 7.9% 8.4% a Debt Total 55.0% 6.3% 6.8% 7.3% 7.8% 8.3% 60.0% 6.2% 6.7% 7.2% 7.7% 8.2% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 15, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 9) by Duff & Phelps with a market capitalization between $299.4 million and $656.8 million. 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Offshore Pipeline peers’ Senior Unsecured Notes as of March 15, 2019 with an average maturity of August 30, 2026, extended to 20-years by addition of 30 bps premium for U.S. Treasury maturing March 15, 2039 versus U.S. Treasury maturing August 30, 2026 141 Weighted Average Cost of Capital Analysis Delta House ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Partnership / Corporation 3/15/19 Value Preferred Equity Equity / Total Capitalization Beta Beta 1,2 Plains All American Pipeline, L.P. $24.30 $17,656 $11,501 39.4% 0.96 0.66 Genesis Energy, L.P. 22.62 2,772 4,194 60.2% 1.07 0.52 Unlevered Delta House Shell Midstream Partners, L.P. 19.24 4,394 2,116 32.5% 0.79 0.59 Beta Median 39.4% 0.96 0.59 Historical MRP Supply-Side MRP Risk-free Rate 3 2.8% 2.8% Unlevered Beta 0.59 0.59 Debt and Preferred / Total Capitalization 39.4% 39.4% Adjusted Levered Equity Beta 0.86 0.86 4 Historical MRP (7.1%) WACC Sensitivities Cost of Market Risk Premium (“MRP”) 7.1% 6.0% Equity / WACC Small Company Risk Premium 5 2.5% 2.5% Unlevered Beta 6 0.30 0.40 0.50 0.60 0.70 Equity Cost of Capital 11.4% 10.5% d / re tion 30.0% 7.0% 7.6% 8.3% 8.9% 9.5% z a Pre-Tax Cost of Debt 7 6.2% 6.2% i 35.0% 6.9% 7.5% 8.1% 8.8% 9.4% efer l 2 40.0% 6.8% 7.4% 8.0% 8.7% 9.3% After-Tax Cost of Debt 4.3% 4.3% Pr pita 45.0% 6.7% 7.3% 7.9% 8.6% 9.2% and Ca 50.0% 6.6% 7.2% 7.8% 8.4% 9.0% WACC 8.6% 8.1%bt 55.0% 6.6% 7.1% 7.7% 8.3% 8.9% D e Total 60.0% 6.5% 7.1% 7.6% 8.2% 8.8% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d ization e 30.0% 6.7% 7.2% 7.8% 8.3% 8.9% err 35.0% 6.6% 7.1% 7.7% 8.2% 8.8% ef l r pita 40.0% 6.5% 7.1% 7.6% 8.1% 8.7% nd P a 45.0% 6.5% 7.0% 7.5% 8.0% 8.5% C 50.0% 6.4% 6.9% 7.4% 7.9% 8.4% a Debt Total 55.0% 6.3% 6.8% 7.3% 7.8% 8.3% 60.0% 6.2% 6.7% 7.2% 7.7% 8.2% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 15, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 9) by Duff & Phelps with a market capitalization between $299.4 million and $656.8 million. Market capitalization for Delta House based on 100% interest in Delta House 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Offshore Pipeline peers’ Senior Unsecured Notes as of March 15, 2019 with an average maturity of August 30, 2026, extended to 20-years by addition of 30 bps premium for U.S. Treasury maturing March 15, 2039 versus U.S. Treasury maturing August 30, 2026 142

Weighted Average Cost of Capital Analysis Bakken Crude Oil Gathering ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Partnership / Corporation 3/15/19 Value Preferred Equity Equity / Total Capitalization Beta Beta 1,2 Delek Logistics Partners, LP $32.46 $808 $700 46.4% 0.77 0.48 Crude Oil Genesis Energy, L.P. 22.62 2,772 4,194 60.2% 1.07 0.52 Unlevered Gathering NGL Energy Partners LP 13.51 1,677 2,215 56.9% 1.08 0.56 Beta Plains All American Pipeline, L.P. 24.30 17,656 11,501 39.4% 0.96 0.66 Median 51.7% 1.02 0.54 Historical MRP Supply-Side MRP Risk-free Rate 3 2.8% 2.8% Unlevered Beta 0.54 0.54 Debt and Preferred / Total Capitalization 51.7% 51.7% Adjusted Levered Equity Beta 0.94 0.94 Cost of Market Risk Premium (“MRP”) 4 7.1% 6.0% Historical MRP (7.1%) WACC Sensitivities Equity / WACC Small Company Risk Premium 5 11.4% 11.4% Unlevered Beta 6 20.9% 19.9% Equity Cost of Capital / 0.30 0.40 0.50 0.60 0.70 7 ed 30.0% 13.3% 14.0% 14.6% 15.2% 15.9% Pre-Tax Cost of Debt 6.8% 6.8% rr zation e i 35.0% 12.8% 13.4% 14.1% 14.7% 15.3% After-Tax Cost of Debt 2 4.8% 4.8% ef r al t 40.0% 12.3% 12.9% 13.5% 14.2% 14.8% 45.0% 11.8% 12.4% 13.0% 13.6% 14.2% WACC 12.6% 12.1% nd P Capi al 50.0% 11.3% 11.9% 12.5% 13.1% 13.7% bt Tota 55.0% 10.8% 11.4% 12.0% 12.6% 13.2% De 60.0% 10.3% 10.9% 11.4% 12.0% 12.6% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d ization e 30.0% 13.0% 13.6% 14.1% 14.7% 15.2% err 35.0% 12.5% 13.1% 13.6% 14.1% 14.7% ef l r pita 40.0% 12.0% 12.6% 13.1% 13.6% 14.2% nd P a 45.0% 11.5% 12.1% 12.6% 13.1% 13.6% C 50.0% 11.0% 11.5% 12.1% 12.6% 13.1% a Debt Total 55.0% 10.5% 11.0% 11.5% 12.0% 12.6% 60.0% 10.0% 10.5% 11.0% 11.5% 12.0% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 15, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10z) by Duff & Phelps with a market capitalization between $2.5 million and $87.6 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Crude Oil Gathering peers’ Senior Unsecured Notes as of March 15, 2019 with an average maturity of December 18, 2025, extended to 20-years by addition of 32 bps premium for U.S. Treasury maturing March 15, 2039 versus U.S. Treasury maturing December 18, 2025 143 Weighted Average Cost of Capital Analysis Silver Dollar Pipeline ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Partnership / Corporation 3/15/19 Value Preferred Equity Equity / Total Capitalization Beta Beta 1,2 Delek Logistics Partners, LP $32.46 $808 $700 46.4% 0.77 0.48 Crude Oil Genesis Energy, L.P. 22.62 2,772 4,194 60.2% 1.07 0.52 Unlevered Gathering NGL Energy Partners LP 13.51 1,677 2,215 56.9% 1.08 0.56 Beta Plains All American Pipeline, L.P. 24.30 17,656 11,501 39.4% 0.96 0.66 Median 51.7% 1.02 0.54 Historical MRP Supply-Side MRP Risk-free Rate 3 2.8% 2.8% Unlevered Beta 0.54 0.54 Debt and Preferred / Total Capitalization 51.7% 51.7% Adjusted Levered Equity Beta 0.94 0.94 Cost of Market Risk Premium (“MRP”) 4 7.1% 6.0% Historical MRP (7.1%) WACC Sensitivities Equity / WACC Small Company Risk Premium 5 7.0% 7.0% Unlevered Beta 6 16.5% 15.5% Equity Cost of Capital / 0.30 0.40 0.50 0.60 0.70 7 ed 30.0% 10.2% 10.9% 11.5% 12.2% 12.8% Pre-Tax Cost of Debt 6.8% 6.8% rr zation e i 35.0% 9.9% 10.6% 11.2% 11.8% 12.5% After-Tax Cost of Debt 2 4.8% 4.8% ef r al t 40.0% 9.7% 10.3% 10.9% 11.5% 12.2% 45.0% 9.4% 10.0% 10.6% 11.2% 11.8% WACC 10.4% 10.0% nd P Capi al 50.0% 9.1% 9.7% 10.3% 10.9% 11.5% bt Tota 55.0% 8.8% 9.4% 10.0% 10.6% 11.2% De 60.0% 8.5% 9.1% 9.7% 10.3% 10.8% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d ization e 30.0% 9.9% 10.5% 11.0% 11.6% 12.1% err 35.0% 9.7% 10.2% 10.7% 11.3% 11.8% ef l r pita 40.0% 9.4% 9.9% 10.5% 11.0% 11.5% nd P a 45.0% 9.1% 9.6% 10.2% 10.7% 11.2% C 50.0% 8.8% 9.3% 9.9% 10.4% 10.9% a Debt Total 55.0% 8.5% 9.1% 9.6% 10.1% 10.6% 60.0% 8.3% 8.8% 9.3% 9.8% 10.3% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 15, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10y) by Duff & Phelps with a market capitalization between $87.6 million and $166.3 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Crude Oil Gathering peers’ Senior Unsecured Notes as of March 15, 2019 with an average maturity of December 18, 2025, extended to 20-years by addition of 32 bps premium for U.S. Treasury maturing March 15, 2039 versus U.S. Treasury maturing December 18, 2025 144

Weighted Average Cost of Capital Analysis Crude Oil Storage ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered 1,2 Partnership / Corporation 3/15/19 Value Preferred Equity Equity / Total Capitalization Beta Beta Blueknight Energy Partners, L.P. $1.06 $44 $562 92.8% 1.00 0.10 Global Partners LP 19.00 650 1,138 63.6% 0.91 0.41 Crude Oil Sprague Resources LP 15.78 359 661 64.8% 0.88 0.38 Unlevered Storage USD Partners LP 11.00 298 206 40.8% 0.65 0.44 Beta Median 64.2% 0.89 0.39 Historical MRP Supply-Side MRP Risk-free Rate 3 2.8% 2.8% Unlevered Beta 0.39 0.39 Debt and Preferred / Total Capitalization 64.2% 64.2% Adjusted Levered Equity Beta 0.89 0.89 Cost of Market Risk Premium (“MRP”) 4 7.1% 6.0% Equity / WACC 5 Historical MRP (7.1%) WACC Sensitivities Small Company Risk Premium 11.4% 11.4% Equity Cost of Capital 6 20.5% 19.6% Unlevered Beta / 0.10 0.20 0.30 0.40 0.50 Pre-Tax Cost of Debt 7 7.3% 7.3% ed 30.0% 12.1% 12.8% 13.4% 14.1% 14.7% rr 2 e zation 35.0% 11.7% 12.3% 12.9% 13.6% 14.2% After-Tax Cost of Debt 5.1% 5.1% ef i al r t 40.0% 11.2% 11.8% 12.4% 13.1% 13.7% WACC 10.6% 10.3% nd P Capi 60.0% 9.3% 9.9% 10.5% 11.1% 11.7% al 65.0% 8.9% 9.4% 10.0% 10.6% 11.2% bt Tota 70.0% 8.4% 9.0% 9.5% 10.1% 10.6% De 75.0% 7.9% 8.5% 9.0% 9.6% 10.1% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.10 0.20 0.30 0.40 0.50 d ization e 30.0% 12.0% 12.6% 13.1% 13.7% 14.2% err 35.0% 11.6% 12.1% 12.7% 13.2% 13.7% ef l r pita 40.0% 11.1% 11.6% 12.2% 12.7% 13.2% nd P a 60.0% 9.2% 9.7% 10.2% 10.7% 11.2% C 65.0% 8.8% 9.3% 9.8% 10.2% 10.7% a Debt Total 70.0% 8.3% 8.8% 9.3% 9.8% 10.2% 75.0% 7.9% 8.3% 8.8% 9.3% 9.7% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 15, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10z) by Duff & Phelps with a market capitalization between $2.5 million and $87.6 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Global Partners LP’s Senior Unsecured Notes maturing June 15, 2023 as of March 15, 2019, extended to 20-years by addition of 41 bps premium for U.S. Treasury maturing March 15, 2039 versus U.S. Treasury maturing June 15, 2023 145 Weighted Average Cost of Capital Analysis NGL Transportation ($ in millions, except per unit / share amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered 1,2 Partnership / Corporation 3/15/19 Value Preferred Equity Equity / Total Capitalization Beta Beta Enterprise Products Partners L.P. $28.13 $61,461 $26,178 29.9% 0.85 0.66 NGL ONEOK, Inc. 66.85 27,516 10,631 27.9% 0.95 0.73 Unlevered Transportation Phillips 66 Partners LP 51.84 6,565 3,794 36.6% 0.77 0.55 Beta Targa Resources Corp. 40.04 9,295 8,552 47.9% 0.98 0.57 Median 33.2% 0.90 0.61 Historical MRP Supply-Side MRP Risk-free Rate 3 2.8% 2.8% Unlevered Beta 0.61 0.61 Debt and Preferred / Total Capitalization 33.2% 33.2% Adjusted Levered Equity Beta 0.83 0.83 Cost of 4 Historical MRP (7.1%) WACC Sensitivities Market Risk Premium (“MRP”) 7.1% 6.0% Equity / WACC Small Company Risk Premium 5 2.5% 2.5% Unlevered Beta Equity Cost of Capital 6 11.2% 10.3% / 0.30 0.40 0.50 0.60 0.70 edrr 30.0% 6.6% 7.3% 7.9% 8.6% 9.2% Pre-Tax Cost of Debt 7 4.5% 4.5% e ef zation i 35.0% 6.5% 7.1% 7.7% 8.4% 9.0% r al t 40.0% 6.3% 7.0% 7.6% 8.2% 8.8% After-Tax Cost of Debt 2 3.2% 3.2% nd P Capi 45.0% 6.2% 6.8% 7.4% 8.0% 8.7% al 50.0% 6.1% 6.7% 7.3% 7.9% 8.5% WACC 8.5% 8.0% bt Tota 55.0% 5.9% 6.5% 7.1% 7.7% 8.3% De 60.0% 5.8% 6.4% 6.9% 7.5% 8.1% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d ization e 30.0% 6.3% 6.9% 7.4% 8.0% 8.5% err 35.0% 6.2% 6.7% 7.3% 7.8% 8.4% ef l r pita 40.0% 6.1% 6.6% 7.1% 7.7% 8.2% nd P a 45.0% 5.9% 6.5% 7.0% 7.5% 8.0% C 50.0% 5.8% 6.3% 6.8% 7.3% 7.9% a Debt Total 55.0% 5.7% 6.2% 6.7% 7.2% 7.7% 60.0% 5.5% 6.0% 6.5% 7.0% 7.5% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) for Partnerships and tax rate of 21.0% for Corporations 3. 20-year Treasury as of March 15, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 9) by Duff & Phelps with a market capitalization between $299.4 million and $656.8 million. Market capitalization based on 100% interest in Wilprise, Tri-States and Cayenne. 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for NGL Transportation peers’ Senior Unsecured Notes as of March 15, 2019 with an average maturity of April 16, 2032, extended to 20-years by addition of 15 bps premium for U.S. Treasury maturing March 15, 2039 versus U.S. Treasury maturing April 16, 2032 146

B. Detailed Segment Financial Projections Detailed Segment Financial Projections Natural Gas Gathering and Processing ($ in millions) AMID Financial Projections For the Twelve Months Ended December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Volumes (MMcfd) East Texas 43.1 42.1 42.7 43.0 43.5 44.0 44.4 Lavaca 106.3 130.3 183.5 229.2 260.1 286.5 310.5 Chatom / Glade Crossing 10.8 9.7 12.8 14.0 13.9 13.7 13.4 Permian 4.7 6.9 8.0 13.2 17.0 17.4 17.3 Total Volumes 164.9 189.0 247.0 299.4 334.5 361.5 385.6 15.3% Gross Margin East Texas $22.0 $21.5 $19.8 $20.4 $19.6 $19.4 $19.4 Lavaca 14.1 17.7 28.3 37.4 42.7 47.0 50.7 Chatom / Glade Crossing 3.3 7.7 9.3 10.5 9.5 9.4 8.5 Permian 3.3 4.7 7.2 9.5 11.1 11.3 11.2 Longview Plant Expansion — — — 6.8 11.6 11.6 11.6 Pascagoula Gas Plant — — 6.7 9.3 8.9 8.3 7.1 Gross Margin $42.7 $51.6 $71.2 $93.8 $103.4 $106.9 $108.6 16.0% Operating Expenses East Texas ($12.5) ($11.1) ($11.8) ($11.9) ($11.9) ($11.9) ($11.9) Lavaca (7.6) (7.0) (9.3) (10.0) (10.4) (10.6) (10.9) Chatom / Glade Crossing (7.7) (7.4) (6.8) (7.0) (7.0) (7.0) (7.1) Permian (3.1) (2.7) (2.7) (3.0) (3.2) (3.3) (3.3) Pascagoula Gas Plant — — (1.9) (2.2) (2.3) (2.3) (2.3) Other (0.8) 1.0 (0.1) (0.0) (0.0) (0.0) (0.0) Operating Expenses ($31.7) ($27.1) ($32.7) ($34.1) ($34.8) ($35.2) ($35.5) 5.5% EBITDA $11.0 $24.5 $38.6 $59.7 $68.6 $71.8 $73.1 Maintenance Capital Expenditures (1.9) (5.4) (2.7) (3.0) (3.0) (3.0) (3.0) Growth Capital Expenditures (13.2) (29.7) (104.1) (55.0) (29.4) (26.1) (25.1) Free Cash Flow ($4.1) ($10.6) ($68.2) $1.7 $36.2 $42.7 $45.1 NA Source: AMID management Note: Burns Point plant capacity excluded from total due to maintenance issues shutting down plant operations in December 2017 147

Detailed Segment Financial Projections Natural Gas Transportation ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Volumes (MMBtu/d) Alatenn Pipelines 307,240 309,785 336,011 362,781 388,340 388,340 388,340 TransUnion 470,000 470,029 470,000 470,000 470,000 470,000 470,000 Magnolia 95,110 77,255 54,188 49,256 49,256 49,256 49,256 Midla / MLGT 367,235 402,775 312,348 295,516 295,170 295,170 295,170 Total Volumes 1,239,585 1,259,843 1,172,546 1,177,553 1,202,766 1,202,766 1,202,766 (0.9%) Gross Margin Alatenn Pipelines $9.3 $9.6 $9.5 $9.5 $10.1 $10.1 $10.1 TransUnion 1.2 6.3 6.2 6.2 6.2 6.2 6.2 Magnolia 6.0 5.9 4.1 3.9 3.2 3.2 3.3 Midla / MLGT 7.8 8.0 8.5 9.5 11.7 13.1 13.1 Fuel Gain / Other 0.0 6.3 1.5 2.1 1.6 1.0 1.0 Total Gross Margin $24.3 $36.1 $29.8 $31.1 $32.8 $33.7 $33.7 (1.4%) Operating Expenses Alatenn Pipelines ($1.5) ($2.9) ($2.9) ($3.1) ($3.1) ($3.1) ($3.1) TransUnion (0.1) (0.5) (0.6) (0.6) (0.6) (0.6) (0.6) Magnolia (0.8) (1.7) (1.1) (1.1) (1.1) (1.1) (1.1) Midla / MLGT (3.6) (3.1) (2.9) (2.9) (2.9) (2.9) (2.9) Operating Expenses ($6.0) ($8.3) ($7.5) ($7.6) ($7.6) ($7.7) ($7.7) (1.5%) EBITDA Alatenn Pipelines $7.7 $6.6 $6.6 $6.4 $7.0 $7.0 $7.0 TransUnion 1.1 5.9 5.6 5.6 5.6 5.6 5.6 Magnolia 5.2 4.2 3.0 2.8 2.2 2.2 2.2 Midla / MLGT 4.2 4.9 5.7 6.6 8.8 10.2 10.2 Fuel Gain / Other 0.0 6.3 1.5 2.1 1.6 1.0 1.0 EBITDA $18.3 $27.9 $22.3 $23.5 $25.2 $26.0 $26.0 (1.3%) Maintenance Capital Expenditures (1.9) (1.2) (3.4) (3.5) (3.5) (3.5) (3.5) Growth Capital Expenditures (33.5) (3.7) (8.4) (1.1) (0.9) — — Free Cash Flow ($17.1) $23.0 $10.6 $18.9 $20.8 $22.5 $22.5 (0.4%) Source: AMID management 148 Detailed Segment Financial Projections Offshore Pipelines excl. Delta House ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2018A 2019E 2020E 2021E 2022E 2023E CAGR Gas Volumes (MMBtu/d) Destin-Okeanos (66.7% Ownership) 1,110,014 1,253,912 1,313,448 1,222,610 1,180,244 1,075,843 High Point Pipelines 319,319 348,275 345,326 338,439 310,503 281,825 Panther Pipelines 61,049 140,469 141,617 127,575 115,096 103,981 Total Gas Volumes 1,490,382 1,742,657 1,800,392 1,688,624 1,605,843 1,461,648 (0.4%) Crude Oil Volumes (MBpd) AmPan Pipelines 9.7 8.5 7.7 6.9 6.2 5.6 Main Pass Oil Gathering 26.6 30.4 28.0 25.8 23.7 21.8 Total Oil Volumes 36.4 38.9 35.7 32.7 29.9 27.4 (5.5%) Gross Margin Destin-Okeanos (100% Gross) $86.1 $79.6 $83.4 $74.3 $69.4 $62.3 Other 64.2 67.8 68.6 66.9 64.5 62.2 Total Gross Margin (100% Consolidated) $150.3 $147.4 $152.0 $141.2 $134.0 $124.4 (3.7%) Operating Expenses Destin-Okeanos (100% Gross) ($15.5) ($17.6) ($17.6) ($17.6) ($17.6) ($17.6) Other (29.6) (34.1) (34.1) (34.1) (34.1) (34.1) Operating Expenses (100% Consolidated) ($45.1) ($51.7) ($51.7) ($51.7) ($51.7) ($51.7) 2.8% EBITDA Destin-Okeanos (100% Gross) $70.6 $62.0 $65.8 $56.7 $51.9 $44.7 Other 34.6 33.7 34.5 32.8 30.4 28.0 EBITDA (100% Consolidated) $105.2 $95.8 $100.3 $89.5 $82.3 $72.7 (7.1%) Maintenance Capital Expenditures Destin-Okeanos (100% Gross) ($1.9) ($0.6) ($0.6) ($0.6) ($0.6) ($0.6) Other (1.9) (6.9) (4.0) (4.0) (4.0) (4.0) Maintenance Capital Expenditures (100% Consolidated) ($3.9) ($7.5) ($4.6) ($4.6) ($4.6) ($4.6) 3.4% Growth Capital Expenditures Destin-Okeanos (100% Gross) $— $— $— $— $— $— Other (22.8) (4.3) — — — — Growth Capital Expenditures (100% Consolidated) ($22.8) ($4.3) $— $— $— $— NA Change in Working Capital Destin-Okeanos (100% Gross) $3.8 $7.8 $1.4 $0.4 $1.0 $1.2 Other — — — — — — Change in Working Capital (100% Consolidated) $3.8 $7.8 $1.4 $0.4 $1.0 $1.2 Change in Deferred Revenue Destin-Okeanos (100% Gross) ($3.2) ($3.1) ($3.1) ($3.1) ($3.1) ($3.1) Other — — — — — — Change in Deferred (100% Consolidated) ($3.2) ($3.1) ($3.1) ($3.1) ($3.1) ($3.1) Free Cash Flow Destin-Okeanos (66.7% Net) $46.2 $44.2 $42.4 $35.7 $32.9 $28.2 Other 9.9 22.5 30.5 28.8 26.4 24.0 Free Cash Flow (Net to AMID) $56.1 $66.6 $72.8 $64.5 $59.3 $52.2 (1.4%) Source: AMID management 149

Detailed Segment Financial Projections Delta House ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2025E 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E CAGR Gas Transportation (MMcfd) 86.1 175.5 179.9 181.1 178.1 150.9 116.4 112.7 Oil Transportation (MBpd) 51.1 77.4 88.7 87.9 81.2 77.2 61.6 53.7 FPS Throughput (MBoed) 65.5 106.7 118.7 118.1 110.9 102.3 81.0 72.5 1.5% Processing Revenue $103.1 $170.4 $176.6 $159.8 $139.2 $124.4 $94.6 $90.6 Gas Transportation Revenue 18.4 33.2 33.3 34.4 32.7 26.8 20.5 19.9 Oil Transportation Revenue 21.6 30.5 33.7 32.2 28.8 25.4 19.8 17.6 Other Revenue 0.1 — — — — — — — Gross Margin $143.2 $234.1 $243.6 $226.4 $200.8 $176.7 $134.9 $128.1 (1.6%) Operating Expenses (1.4) (0.9) (0.9) (0.9) (0.9) (0.9) (0.9) (1.0) EBITDA $141.9 $233.3 $242.7 $225.5 $199.8 $175.8 $133.9 $127.2 (1.6%) Less: Change in Deferred Revenue 21.6 16.8 (84.7) (86.7) (78.0) (78.0) (57.2) (55.6) Less: Change in Working Capital (9.5) (6.1) 22.0 (0.8) 6.2 2.4 3.9 (1.2) Less: Interest Expense (0.9) — — — — — — — Levered Free Cash Flow $153.0 $244.0 $180.0 $138.1 $128.1 $100.2 $80.6 $70.3 (10.5%) Less: Term Loan Amortization (39.8) — — — — — — — Less: Class B Carry — — (1.2) (3.5) (3.3) (3.0) (2.4) (2.2) Class A Cash Flows (100%) $113.3 $244.0 $178.8 $134.6 $124.8 $97.2 $78.2 $68.1 Class A Cash Flows (35.65%) $40.4 $87.0 $63.7 $48.0 $44.5 $34.6 $27.9 $24.3 Less: AMID Level Delta House Insurance Expense (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) — — Delta House Net Distributions to AMID $40.2 $86.7 $63.5 $47.7 $44.3 $34.4 $27.9 $24.3 Source: AMID management 150 Detailed Segment Financial Projections Trucking ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Volumes (MBpd) South Texas Crude Trucking 6.2 7.2 12.8 14.0 14.0 14.0 14.0 Texas Panhandle Crude Trucking 6.4 9.4 0.8 — — — — Liquids Trucking 2.1 2.6 2.4 2.4 2.4 2.4 2.4 Volumes 14.7 19.2 16.0 16.4 16.4 16.4 16.4 (3.2%) Gross Margin South Texas Crude Trucking $0.9 $0.8 $1.0 $0.9 $0.9 $0.9 $0.9 Texas Panhandle Crude Trucking 1.6 0.5 (0.1) — — — — Liquids Trucking 1.4 0.8 1.1 1.0 1.0 1.0 1.0 Gross Margin $3.9 $2.1 $2.0 $1.9 $1.9 $1.9 $1.9 (2.2%) Operating Expenses South Texas Crude Trucking ($1.7) ($1.3) ($1.4) ($1.4) ($1.4) ($1.4) ($1.4) Texas Panhandle Crude Trucking (1.2) (1.3) (0.2) — — — — Liquids Trucking (2.1) (1.4) (1.5) (1.5) (1.5) (1.5) (1.5) Operating Expenses ($5.0) ($4.0) ($3.1) ($2.9) ($2.9) ($2.9) ($2.9) (6.1%) EBITDA ($1.1) ($1.9) ($1.1) ($1.0) ($1.0) ($1.0) ($1.0) NA Maintenance Capital Expenditures South Texas Crude Trucking $— $— $— $— $— $— $— Texas Panhandle Crude Trucking — — — — — — — Liquids Trucking — — — — — — — Total Maintenance Capital Expenditures $— $— $— $— $— $— $— NA Growth Capital Expenditures South Texas Crude Trucking $— $— $— $— $— $— $— Texas Panhandle Crude Trucking — — — — — — — Liquids Trucking — — — — — — — Total Growth Capital Expenditures $— $— $— $— $— $— $— NA Free Cash Flow ($1.1) ($1.9) ($1.1) ($1.0) ($1.0) ($1.0) ($1.0) NA Source: AMID management 151

Detailed Segment Financial Projections Bakken Crude Oil Gathering ($ in millions) AMID Financial Projections For the Twelve Month Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Transportation Volume (MBpd) 4.4 5.6 8.5 9.5 8.7 7.3 6.1 1.5% Trucking Volume (MBpd) 2.9 3.5 4.0 6.8 6.2 5.2 4.3 4.1% Gross Margin $3.1 $3.7 $7.2 $9.5 $8.7 $7.3 $6.1 Operating Expenses (2.1) (1.8) (3.6) (5.1) (4.9) (4.4) (4.0) Marketing Margin (0.3) (0.6) (0.0) — — 0.0 (0.0) EBITDA $0.7 $1.3 $3.6 $4.4 $3.8 $2.9 $2.1 9.4% Maintenance Capital Expenditures (0.2) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) Growth Capital Expenditures (2.5) (1.1) — — — — — Free Cash Flow ($1.7) $0.1 $3.5 $4.3 $3.7 $2.8 $2.0 86.8% Source: AMID management 152 Detailed Segment Financial Projections Silver Dollar Pipeline ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Silver Dollar Volume (MBpd) 29.5 30.8 40.5 61.2 69.7 74.6 77.9 West Texas Marketing Volume (MBpd) 17.6 — 26.3 40.2 45.5 49.0 51.2 West Texas Trucking (MBpd) 0.0 1.7 15.5 21.2 21.2 21.2 21.2 Gross Margin Silver Dollar ($0.3) $13.2 $13.1 $19.9 $22.5 $22.3 $22.9 West Texas Marketing and Trucking 19.2 7.3 1.9 4.7 5.0 5.2 5.3 Gross Margin $18.9 $20.5 $15.0 $24.7 $27.5 $27.5 $28.2 6.6% Operating Expenses Silver Dollar $— ($3.0) ($3.2) ($3.6) ($3.6) ($3.7) ($3.7) West Texas Marketing and Trucking (2.1) (1.4) (1.8) (1.8) (1.8) (1.8) (1.8) Operating Expenses ($2.1) ($4.4) ($5.0) ($5.4) ($5.4) ($5.4) ($5.5) 4.4% EBITDA $16.8 $16.1 $10.0 $19.3 $22.0 $22.1 $22.7 7.1% Maintenance Capital Expenditures Silver Dollar $— $— ($0.4) ($0.5) ($0.5) ($0.4) ($0.4) West Texas Marketing — — — — — — — Total Maintenance Capital Expenditures $— $— ($0.4) ($0.5) ($0.5) ($0.4) ($0.4) NA Growth Capital Expenditures Silver Dollar ($6.2) ($14.1) ($14.3) ($12.6) $— $— $— West Texas Marketing — — — — — — — Total Growth Capital Expenditures ($6.2) ($14.1) ($14.3) ($12.6) $— $— $— NA Free Cash Flow $10.6 $2.0 ($4.8) $6.2 $21.5 $21.7 $22.3 NA Source: AMID management 153

Detailed Segment Financial Projections Cushing Terminal ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Available Storage Capacity (MBbls) 2,618.2 2,400.0 1,300.0 3,000.0 3,000.0 3,000.0 3,000.0 Total Gross Margin $10.8 $3.4 $1.6 $7.2 $7.2 $7.2 $7.2 Operating Expenses (2.8) (2.4) (2.7) (2.7) (2.7) (2.7) (2.7) EBITDA $8.0 $1.0 ($1.1) $4.5 $4.5 $4.5 $4.5 35.7% Maintenance Capital Expenditures — (3.4) (3.8) — — — — Growth Capital Expenditures — — — — — — — Free Cash Flow $8.0 ($2.4) ($4.9) $4.5 $4.5 $4.5 $4.5 NA Source: AMID management 154 Detailed Segment Financial Projections NGL JV Interests ($ in millions) AMID Financial Projections1 For the Twelve Month Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR NGL Volumes (MBpd) Cayenne (50.0% Ownership) — 30.0 33.9 33.9 32.8 29.1 25.8 Tri States (16.7% Ownership) 53.8 50.4 55.1 57.1 55.9 54.8 53.7 Wilprise (25.3% Ownership) 34.0 36.7 31.9 32.9 31.9 28.2 25.0 NGL Volumes 87.8 117.1 120.9 123.8 120.6 112.1 104.5 (2.2%) Gross Margin Cayenne (50.0% Ownership) $— $13.9 $15.7 $15.9 $15.4 $13.6 $12.1 (2.7%) Tri States (16.7% Ownership) 50.5 48.3 51.6 53.8 52.9 52.2 51.4 1.3% Wilprise (25.3% Ownership) 5.2 5.7 4.8 4.9 4.8 4.2 3.7 (8.0%) Operating Expenses Cayenne (50.0% Ownership) $— ($1.3) ($1.0) ($1.0) ($1.0) ($1.0) ($1.0) Tri States (16.7% Ownership) (8.1) (10.2) (10.0) (10.0) (10.0) (10.0) (10.0) Wilprise (25.3% Ownership) (1.0) (0.9) (0.8) (0.8) (0.8) (0.8) (0.8) EBITDA Cayenne (50% Ownership) $— $12.5 $14.7 $14.9 $14.4 $12.6 $11.1 (2.4%) Tri States (16.7% Ownership) 42.4 38.1 41.6 43.8 42.9 42.2 41.4 1.7% Wilprise (25.3% Ownership) 4.2 4.8 3.9 4.1 3.9 3.4 2.9 (9.6%) Maintenance Capital Expenditures Cayenne (50.0% Ownership) $— $— $— $— $— $— $— Tri States (16.7% Ownership) — — — — — — — Wilprise (25.3% Ownership) — — — — — — — Growth Capital Expenditures Cayenne (50.0% Ownership) $— $— $— $— $— $— $— Tri States (16.7% Ownership) — — — — — — — Wilprise (25.3% Ownership) — — — — — — — Change in Working Capital Cayenne (50.0% Ownership) — (4.5) (0.0) (0.0) 0.2 0.4 0.3 Tri States (16.7% Ownership) (4.3) (2.3) (0.3) (0.3) (0.1) (0.1) (0.1) Wilprise (25.3% Ownership) (0.4) (0.3) 0.1 (0.1) 0.1 0.1 0.1 Free Cash Flow (Net Cayenne (50.0% Ownership) — 4.0 7.3 7.5 7.3 6.5 5.7 Tri States (16.7% Ownership) 6.4 6.0 6.9 7.3 7.2 7.0 6.9 Wilprise (25.3% Ownership) 1.0 1.1 1.0 1.0 1.0 0.9 0.8 Total Free Cash Flow (Net) $7.3 $11.1 $15.2 $15.7 $15.5 $14.4 $13.4 4% Source: AMID management 1. Projections shown on a 100.0% basis 155