Investor Presentation

UBS MLP Conference

January 10 & 11, 2017

22

This presentation includes forward-looking statements. These statements relate to, among other things, projections of

operational volumetrics and improvements, growth projects, cash flows and capital expenditures. We have used the words

"anticipate,” "believe," "could," "estimate," "expect," "intend," "may," "plan," "predict," "project," "should," "will," "potential,"

and similar terms and phrases to identify forward-looking statements in this presentation. Although we believe the

assumptions upon which these forward-looking statements are based are reasonable, any of these assumptions could prove

to be inaccurate and the forward-looking statements based on these assumptions could be incorrect. Our operations and

future growth involve risks and uncertainties, many of which are outside our control, and any one of which, or a combination

of which, could materially affect our results of operations and whether the forward-looking statements ultimately prove to be

correct. Actual results and trends in the future may differ materially from those suggested or implied by the forward-looking

statements depending on a variety of factors, which are described in greater detail in our filings with the SEC. Construction

of projects described in this presentation is subject to risks beyond our control including cost overruns and delays resulting

from numerous factors. In addition, we face risks associated with the integration of acquired businesses, decreased liquidity,

increased interest and other expenses, assumption of potential liabilities, diversion of management’s attention, and other

risks associated with acquisitions and growth. Please see our Risk Factor disclosures included in our Annual Report on

Form 10-K for the year ended December 31, 2015 filed on March 7, 2016 and on Form 10-Q for the quarter ended

September 30, 2016 filed on November 08, 2016. All future written and oral forward-looking statements attributable to us or

persons acting on our behalf are expressly qualified in their entirety by the previous statements. This presentation speaks

only as of the date on the cover page. We undertake no obligation to update any information contained herein or to publicly

release the results of any revisions to any forward-looking statements that may be made to reflect events or circumstances

that occur, or that we become aware of, after the date of this presentation.

is presentation includes forward-looking statements. These statements relate to, among other things, projections

of operational "believe," "could," "estimate," "expect," "intend," "may," "plan," "predict," "project," "should,"

Legal DisclaimerCautionary Statement

Key Business Highlights

.

Third quarter 2016 Adjusted EBITDA of $35.8 million

and Distributable Cash Flow of $24.4 million, an

increase of 126% and 121%, from third quarter 2015

Top-tier, third quarter distribution coverage of 1.9

times

On October 24, 2016, American Midstream (“AMID”)

announced merger with JP Energy Partners creating

a $2 billion enterprise value partnership

On November 1, 2016, AMID announced the

acquisition of an incremental 6.2% interest in Delta

House, a floating production system, bringing total

owned interest to 20.1%

AMID issued $300 million of 8.5% senior notes,

upon closing of the merger, net proceeds will be

used to fully repay and terminate the JPEP credit

facility and to partially repay outstanding

indebtedness under AMID’s credit facility

AMID asset footprint covers 10,000 square miles of

Gulf of Mexico production, and transports a total of

1.6 Bcf/d of natural gas, over 100,000 barrels per

day of oil crude, and 45,000 barrels per day of

NGLs

Terminals segment contracted capacity averaged

over 2.2 million barrels

American Midstream OverviewAmerican Midstream OverviewLegal DisclaimerLegal DisclaimerAmerican Midstream OverviewLegal DisclaimerAmerican Midstream Overview

American Midstream Partners, LP($ millions except unit)

2016 Guidance($ millions)

Growth Capital Expenditures 60 - 70

Adjusted EBITDA $125 - $135

Distributable Cash Flow 85 - 95

3

¹ - as of 01/04/2017² - at quarter end 9/30/2016³ - at quarter end 9/30/2016 inclusive of Series D preferred issuance and acquisition of incremental 6.2% Delta House interest⁴ - Inclusive of series A, C and D preferred units⁵ - For the quarter ended 9/30/2016. See slide 36 for reconciliation of non-GAAP Adjusted EBITDA to GAAP net income.

2016 Total Return

-50%

0%

50%

100%

150%

200%

1/1/2016 4/1/2016 7/1/2016 10/1/2016 1/1/2017

Alerian Index S&P Index American Midstream

12/31/2016

Market capitalization¹ 569$

Distribution coverage² 1.9x

Equity yield¹ 9.0%

8.5% 2021 senior unsecured note yield¹ 8.1%

TTM compliance Adjusted EBITDA⁵ 154$

Total indebtedness² 673$

Pro forma leverage³ 4.0x

Total outstanding units (millions)⁴ 52.8

4

AMID has Stable, Fee-based Cash Flow

• 92% of gross margin expected to be derived from

fee-based and fixed-margin contracts, minimizing

direct commodity exposure

• Cash flow supported by significant acreage / life-of-

lease dedications and firm transportation and storage

contracts

• Diverse and creditworthy customer base includes

supermajors, independent producers, LDCs, utilities,

industrial end-users, refiners, chemical manufacturers

and marketers

Fee-based cash flow information from Wells Fargo January 2017 MLP Monthly

American Midstream /

JP Energy Transaction

Overview

66

Transaction at a GlanceAMID to issue units to JPEP unitholders at 0.5775x exchange ratio

Transaction Overview

• AMID units issued to JPEP public unitholders at 0.5775x:1 exchange ratio

• General partner of JPEP merged into AMID general partner, AMID IDRs unchanged

• AMID Series A Preferred Units restructured to pay distributions equal to common units

• Annual synergies of at least $10 million from elimination of duplicative public company costs and certain operational benefits

Sponsor Support

• ArcLight affiliates to provide merger support up to $25 million to target ~5% DCF per unit accretion to unitholders in 2017 and 2018

• ArcLight affiliates will also reimburse JPEP’s transaction and transition costs

• AMID exchange ratio for ArcLight’s JPEP units of 0.5225x:1, adding further value to JPEP public unitholders by enabling them to receive a higher exchange ratio

ArcLightManagement

& Affiliates

Other

Investors

American Midstream Partners GP

(“AMID GP”)

American Midstream Partners LP

(NYSE: AMID)

JP Energy Partners LP

(NYSE: JPEP)

Sponsor commitment up to

$25 million to support DCF

accretion

JPEP transaction and transition cost support

New AMID units issued at

0.5775x:1exchange ratio

for JPEP public unitholders

Contribution of assets / interests

77

Increase Scale & DiversificationLarger scale grows our opportunity in the market

• Significantly expands company size and service offerings

- ~$185 million expected pro-forma 2016 Adjusted EBITDA

- ~$2.1 billion pro-forma enterprise value

• Meaningfully expands our reach and value to current and potential customers

• Stronger marketplace liquidity; better access to long-term capital; pro-forma float of ~$644 million

• Increases number and type of potential acquisitions, improves competitiveness in the market

Enhancing Our Competitive Position Through Scale

Onshore G&P, 23%

Offshore, 42%

Transmission, 6%

Terminals, 17%

NGL Distribution, 12%

Diversification Across Segments

% of FY17 Pro Forma Adjusted EBITDA

Strong & Expanding Customer Base

Producers End Markets

Note: Expected pro-forma Adjusted EBITDA represents combined 2016 announced midpoint of guidance and run-rate synergies of at least $10 million. Pro-forma enterprise value as of 14/2017. Pro-forma float based on pro-forma public common unit count of 35.3 million and unit price of $18.25 per unit as of 1/4/2017

88

Transmission

Terminals

• Capitalize on access to Northeast supply to increase market demand and expand footprint

• Capture Southeast and Louisiana market share traditionally served by Gulf Coast pipelines

• Pursue additional storage infrastructure in proximity to crude/refined product /chemical flows and

near demand centers

• Expand geographically and rationalize logistics costs

• Leverage JPEP logistics/trucking expertise within AMID’s East Texas operations to expand footprint

Develop Commercial and

Acquisition Opportunities

• Combine pipeline and truck transportation capabilities to increase upstream connections,

processing capabilities, and downstream market options

Offshore • Actively build an integrated system with multiple market options particularly in the deep-water

Leverage Complementary AssetsA clear strategy for midstream opportunities across the value chain

NGL

Distribution

• Enhance critical mass with robust pipeline of commercial and M&A opportunities adjacent to existing footprint

• Link wellhead gathering, gas processing, and NGL production with direct access to downstream consumers (seasonal butane supply for gasoline blending, year-round propane supply)

• Leverage trucking capacity to optimize costs and secure additional NGL and condensate barrels for processing

• Integrate commercial, logistics and operations in Eagle Ford and Permian

Onshore G&P

Participate in Entire Value

ChainExtend Customer Reach

Segment Level Strategy

40%

16%

13%

17%

14%

Offshore

Onshore G&P

Transmission

Terminals

NGL Distribution & Sales

99

AMID and JPEP Partnership Overview

2016E Cash Flow by Division 1

Offshore

• Deep-water and shallow-water Gulf of Mexico and

Gulf Coast natural gas, crude oil, NGL and saltwater

pipelines

• Fee-based, semi-submersible floating production

system in prolific Mississippi Canyon

Onshore

G&P

• 11 natural gas and crude oil gathering systems,

7 processing plants, 4 fractionation facilities and a

fleet of crude oil gathering trucks

• Primarily located in the Permian, Cotton Valley /

Haynesville, Eagle Ford and Bakken

Transmission

• 3 interstate and 7 intrastate natural gas transmission

systems with 2.5 Bcf/d of capacity

• Located in Alabama, Louisiana, Mississippi and

Tennessee

Terminals

• 6.7 MMBbls of above-ground liquids storage capacity

across 3 marine terminals, 2 refined products

terminals and one crude oil storage facility

NGL

Distribution

& Sales

• Distribution network of 43 customer service locations

and 28 regulated central distribution systems

• 3rd largest cylinder exchange business in the U.S.

Diversification and integration along midstream value chain maximizes molecular control

1 Based on 2016E Adjusted EBITDA before G&A

1010

1 Pro forma enterprise value as of 1/4/2017

AMID and JPEP to merge, creating a diversified midstream partnership

• AMID and JPEP have executed a merger agreement, whereby AMID will merge with JPEP in a unit-for-unit

exchange

• Transformational combination creates a diversified partnership with an ~$2.1 billion enterprise value1

Transaction improves financial position, consolidates GP ownership and accelerates growth trajectory

• Increased scale enhances access to capital and improves ability to pursue organic growth opportunities and

accretive acquisitions

• Pro forma net leverage of 3.8x

• Large platform enhances ability to drive efficiencies; complementary business activities provide attractive

synergy opportunities

• Establish path to mid-single digit distribution growth over the long-term

Expect transaction to close in Q1 2017

• Merger has been unanimously approved by special committee of AMID plus full Board of AMID and JPEP

• Targeting Q1 2017 closing, pending required approvals and JPEP unitholder vote

A Merger of Growth and Diversification

1111

Strategically Located Assets

Strong asset footprint in leading basins: Permian, Eagle Ford, Bakken, East Texas and Gulf Coast

1212

Track Record of Tactical Growth at Attractive Multiples

• Drop-down of 12.9%

interest in Delta House

for $162MM

• Financed with public

equity offering and AMID

credit facility

• Acquisition of 66.7%

interest in offshore crude

oil gathering system for

$12MM

• Financed with AMID

credit facility

• Concurrent with

ArcLight’s purchase of

90% of AMID GP and

100% of AMID

subordinated units

• Drop-down of High Point

System along with

$15MM cash in exchange

for $90MM of Series A

Preferred Units issued to

ArcLight

High Point System MPOG

• $470MM acquisition of

Costar, including assets

in East Texas, Permian

and Bakken

• Financed with equity

issued to seller, PIPE

offering and AMID credit

facility

Costar

Delta House

• Drop-down of 4 marine

terminal sites for $64MM

• Financed with public

equity offering, equity

issued to ArcLight and

AMID credit facility

Blackwater Terminal

Drop-downs

3rd party acquisitions

• Acquisition of incremental

6.2% interest in Delta

House for $49MM

• Financed with Series D

Preferred Units issued to

ArcLight and AMID credit

facility

Delta House (4Q16)

$214MM

aggregate

purchase price

financed with

$120MM Series

C Preferred Units

issued to ArcLight

and AMID credit

facility

• Drop-down of incremental

1% interest in Delta

House for $10MM

Delta House

• Acquisition of 49.7%

interest in Destin pipeline,

66.7% in Okeanos

pipeline, 60% interest in

American Panther for

GoM Assets

• Acquisition of 16.7%

interest in Tri-States

pipeline and 25.3%

interest in Wilprise

pipeline

Tri-States and Wilprise

• Acquisition of Lavaca

System for $104MM

• Financed with public

equity offering and Series

B Units issued to ArcLight

Lavaca System

2013 2014 20162015

Over $1.1 billion of growth transactions completed at ~8x multiple

Strategic Asset

Portfolio

14

AMID’s Integrated Gulf of Mexico Platform

• Integrated midstream platform focused on the Deepwater Gulf of Mexico (Mississippi Canyon, Viosca Knoll and Main Pass)

• Ability to interconnect with various AMID systems located in the shallow water and Gulf coast regions

• AMID’s pipeline assets cover 10,000 square miles of offshore production, with a focus on the Mississippi Canyon region:

• Most prolific development area, accounting for 31% of GoM reserves and 31% of GoM production 1

• Most active development area, with 8 out of 22 GoM drilling rigs currently operating in the region 2

• AMID’s integrated offshore assets provide deepwater producers with downstream optionality, with ability to access natural gas processing

markets at Destin/Pascagoula (via Destin Pipeline) as well as Venice and Toca (both via High Point)

Deepwater Systems

Asset Ownership Asset Type Division

Delta House 20.1% FPS Offshore

Destin 49.7% Gas Pipeline Offshore

Okeanos 66.7% Gas Pipeline Offshore

Main Pass Oil Gathering 66.7% Oil Pipeline Offshore

Shallow Water Systems

Asset Ownership Asset Type Division

High Point 100.0% Gas Pipeline Transmission

Quivira 100.0% Gas Pipeline Onshore G&P

American Panther 60.0% Gas / Oil Pipelines Offshore

Burns Point 50.0% Processing Plant Onshore G&P

Gulf Coast Systems

Asset Ownership Asset Type Division

Tri-States 16.7% NGL Pipeline Offshore

Wilprise 25.3% NGL Pipeline Offshore

Chalmette 100.0% Gas Pipeline Transmission

Gloria & Lafitte 100.0% Gas Pipeline Onshore G&P

1 Based on reserves as of 12/31/2014 and 2015 production statistics (as reported by the Bureau of Ocean Energy Management). 2 As of 12/1/2016 (as reported by Baker Hughes)

15

Gulf of Mexico Development Activity

• Approximately 40% of active Gulf of Mexico rigs are near AMID’s assets in the Mississippi Canyon

• Companies are citing break-even economics of <$50/Bbl for standalone projects and <$40/Bbl for tie-backs

• 10 major standalone projects where FID could be taken in the next 12 to 18 months with >4BBoe and 20 potential tie-backs with >2BBoe

• In 2016, GOM production has risen by 11% y/y to 1.6 MMBbl/d; GOM production rose by 10% in 2015

16

Delta House Overview

• Fee-based, semi-submersible floating production system and

associated oil and gas export pipelines located in the highly

prolific Mississippi Canyon region (MC254) of the deepwater

Gulf of Mexico

• Operated by LLOG, one of the leading producers in the

Gulf of Mexico

• AMID owns a 20.1% interest

• Nameplate capacity: 80 MBbl/d oil and 200 MMcf/d gas

• Peak capacity: 100 MBbl/d oil and 240 MMcf/d gas

• Commenced operations in April 2015

• 11th LLOG-operated tie-back completed mid-October

2016, bringing Delta House to peak capacity

• Additional tie-backs currently being evaluated, which

would keep Delta House operating at peak capacity for the

foreseeable future

• Supported by long-term, volumetric-tiered, fee-based tariffs

with ship-or-pay components and life-of-lease dedications with

investment grade, well positioned counterparties

• Directly connected to the Destin Pipeline, providing AMID

additional fee-based revenue streams

Operating at peak capacity and underpinned by some of the leading Gulf of Mexico producers

27

53

65 71

64 67 72

64

117

138

153 162

177

194

-

40

80

120

160

200

-

20

40

60

80

100

120

Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Oct-16

MM

cf/

d

MB

bbl/d

Crude Oil (left axis) Natural Gas (right axis)

Nameplate capacity (oil):

80 MBbl/d

Nameplate capacity (gas):

200 MMcf/d

Note: Q2 2016 volumes affected by scheduled pipeline maintenance during June (11 days)

Historical Volume Throughput (Gross)

17

Integrated Deepwater Gulf of Mexico Platform

J

11

12

13

A

B

C

D

E

2

3

4

5

6

7

9

HF

8

10

DH

K

I

G

Delta House FPS

Destin Pipeline

Okeanos Pipeline

High Point

Third-Party Pipelines

DH

AMID Receipt Points Development Activity

Destin Pipeline Recently Completed

Platform / Interconnect Operator Block Field Onstream Operator Block

DH Delta House LLOG MC 254 A Marmalard 2Q 2015 LLOG MC 300

2 Pompano Stone Energy VK 989 B Son of Bluto 2 2Q 2015 LLOG MC 431

3 Gemini Cox Operating VK 900 C Big Bend 4Q 2015 Noble Energy MC 698

4 Main Pass 281 EnVen Energy MP 281 D Dantzler 4Q 2015 Noble Energy MC 782

5 Main Pass 283 W & T Offshore MP 283 E Amethyst 4Q 2015 Stone Energy MC 26

6 Horn Mountain Freeport McMoRan 1 MC 127 F Otis 2Q 2016 LLOG MC 79

7 Marlin Freeport McMoRan 1 VK 915 G Odd Job 4Q 2016 Deep Gulf Energy MC 214/215

8 Spirit Fieldwood Energy VK 780

9 Canyon Station (Transco) Williams Partners MP 261

10 Viosca Knoll Gathering Genesis Energy MP 260

Okeanos Pipeline Ongoing

Platform / Interconnect Operator Block Field Onstream Operator Block

11 Na Kika BP MC 474 H Horn Mountain Deep 2016E Freeport McMoRan 1 MC 126/127

12 Thunder Hawk Noble Energy MC 736 I Thunder Horse South 2017E BP MC 777/778

13 Thunder Horse BP MC 777/778 J Crown and Anchor 2017/18E LLOG VK 959

K Appomattox 2020E Shell MC 392

1 Acquisition by Anadarko Petroleum pending

529 551

410

510

224 229

153

206

151 136

269

313

0

100

200

300

400

500

600

Q1 2016 Q2 2016 Q3 2016 Oct-16

thou

sa

nd

mm

Btu

/d

Destin (Offshore) Okeanos High Point

Historical Natural Gas Volume Throughput

Deepwater Systems

Asset Ownership Asset Type Mileage Capacity

Delta House 20.1% FPS NA 100 MBbl/d / 240 MMcf/d

Destin 49.7% Gas Pipeline 255 1.2 Bcf/d

Okeanos 66.7% Gas Pipeline 100 1.0 Bcf/d

Main Pass Oil Gathering 66.7% Oil Pipeline 100 160 MBbl/d

18

Onshore G&P Overview

Business Overview

• Assets located in some of the most prolific producing

basins including the Permian, Cotton Valley /

Haynesville, Eagle Ford and Bakken

• Over 1,565 miles of high- and low-pressure natural

gas and crude oil gathering systems

• 7 processing plants with ~325 MMcf/d of capacity

• 4 fractionation facilities with 17 MBbl/d of capacity

• Fleet of 62 crude oil gathering trucks

• Significant acreage dedications in the Permian, Eagle

Ford and Bakken

• Connectivity to production fields, processing and

fractionation facilities and end-users via pipelines, truck

and rail

• Diversified customer base across the value chain

Top Onshore G&P Customers

G&P NGL Supply Liquid Sales

19

Expanding Permian Position

Silver Dollar Pipeline

• ~157-mile, crude oil gathering system with ~130 MBbl/d of

throughput capacity and ~140 MBbls of storage capacity

• Serves production from the Spraberry and Wolfcamp formations in

the Midland Basin

• Anchor producers control ~360,000 net acres and are accelerating

drilling and completion activity in 2H 2016 with additional growth

potential from nearby producers

• 3 interconnects to 3rd party, long-haul pipelines (Plains Spraberry,

Occidental Centurion Cline Shale and Magellan Longhorn pipelines)

Yellow Rose

• ~47-mile rich-gas gathering system and 40 MMcf/d cryogenic

processing plant located in Martin County, TX

Mesquite

• Contractual agreement with EnLink Midstream Partners for

fractionalization and stabilization services at EnLink’s Mesquite

facility:

• Rail terminal, 5 MBbl/d condensate stabilization facility and 5

MBbl/d off-spec NGL fractionator

Silver Dollar Pipeline

Yellow Rose / Mesquite

Note: Rig locations as reported by Baker Hughes

(as of 12/1/2016)

Ability to leverage JPEP’s trucking capabilities to drive increased utilization

20

East Texas – Capturing the Full Value Chain

• Process for over 30 rich and lean gas producers

• Over 50 truck NGL supply sources

• Rail terminal commissioned 1Q 2016

• 8 supply sources to date

• Key delivery source to Eastman’s local ethylene

production

• Eastman will support more C2 production

• 1 – 2 rigs planned in area (Cotton Valley / Haynesville

Shale)

Off and

On-

spec

NGLs

Condensate Eastman

Local Markets

Stabilized Condensates

Mount Belvieu

Beaumont

Gulf South

HPL

Residue Gas

Rich & Lean

Gas from Local

Producers

Local

MarketsC3

Chapel Hill

C4 /

C5

Inflow to AMID Outflow from AMID

XTO

Gas ProcessorsTruck and rail

ProducersTruck and rail

Y-Grade E / P

Longview

B / G Mix

Longview & Chapel Hill

Growth

• Secure gas processing and control of liquids from new

drilling

• Consolidate Chapel Hill into Longview to increase NGL

recoveries

• Enhance overall C2 recoveries

• Increase on-spec processing and rail volumes

• Increase selling prices for C2 to local outlets and for BG Mix into winter gasoline blending market

Residue Gas

697 694635

695633

714

0

125

250

375

500

625

750

2Q15 3Q15 4Q15 1Q16 2Q16 3Q16

MM

cf/

d

21

Business Overview

• Transmission assets supply natural gas to industrial

end-users, local distribution companies, municipalities,

power plants and other interstate pipelines throughout

Alabama, Louisiana, Mississippi and Tennessee

• FERC-regulated interstate and unregulated intrastate

pipelines with 2.5 Bcf/d of capacity

• 100% fixed-fee revenue with investment-grade

counterparties

• 1.1 Bcf/d contracted under long-term firm transportation

agreements with weighted-average remaining life of

3 years

Transmission Overview

Quarterly Average Transmission Throughput

LOUISIANA

MISSISSIPPI

ALABAMA

TENNESSEE

Bamagas

Trigas

AlaTenn

MLGT

Midla

Magnolia

High Point

Chalmette

Note: Quarterly average transmission throughput excludes Magnolia system

22

Terminals Asset Overview

Business Overview

• Strategically located storage terminals in key demand markets, primarily serving local refiners and chemical manufacturers

• 6.7 MMBbls of above-ground liquids storage capacity across 6 terminal sites

• Ability to store a wide variety of products including refined products, agricultural products, specialty chemicals and crude oil

• Terminals accessible by pipeline, ships, barges, railcars and trucks

• 100% of cash flow is fee-based, primarily under take-or-pay firm storage contracts

• Additional fee-based cash flow generated via receipt and disbursement throughput and ancillary services such as

blending, steam heating, truck weighing, etc.

Westwego Harvey

Brunswick

AMID legacy terminals

JPEP legacy terminals

North Little Rock

Caddo Mills

Cushing

23

Harvey Organic Growth Project

Expansion Project

• Management is evaluating the development of 1.35 MMBbls of

additional tank storage

• (8) 100 MBbl tanks

• (11) 50 MBbl tanks

• Additional rail capacity and second deep water ship berth that

will have a draft of greater than 50 feet

• Site plan approval received from Jefferson Parish in mid-

October 2016

• $50 to $60 million capital cost over the next 3 years could

bring total site capacity to ~2.5 MMBbls

Harvey Terminal

Harvey Terminal Summary

• Currently 1.1 MMBbls of storage capacity, with a utilization rate of greater than 98%

• Steady demand for storage capacity in the Port of New Orleans

• Well-positioned on the Mississippi River to serve a diverse customer base, including local refiners, chemical manufacturers and

product distributors

• Flexibility to store a wide variety of products including distillates, fuel oil, petroleum feedstocks, commodity, agricultural and specialty

chemicals

• Full modal access for ships, barges, railcars and tank trucks to serve both the domestic and import/export markets

Financial Strength

$32 $46$66

$165

$34$32

$47

$50

$10

$66$77

$113

$225

$0

$50

$100

$150

$200

$250

FY 2013 FY 2014 FY 2015 PF 9/30/16

Synergies

JPEP

AMID

2525

3.1x

4.5x

3.8x 3.5x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

JPEP AMID Pro Forma Long-TermTarget

1 Pro forma 9/30/16 EBITDA is AMID LTM 9/30/16 compliance EBITDA plus $11 million adjustment for Delta House acquisition on 10/31/16; JPEP LTM 9/30/16 Adjusted EBITDA; and $10 million in estimated run-rate synergies based on current Management assumptions, which may be materially different than actual results. Compliance EBITDA and Adjusted

EBITDA are non-GAAP measures. See slides 37 and 37 for a reconciliation to Net Income2 Net leverage and liquidity as of 9/30/16; long-term target leverage and liquidity are pro forma for the merger

Conservative Financial Profile

Adjusted EBITDA 1

Net Leverage 2 Liquidity 2

$103

$75

$181

$250

$0

$60

$120

$180

$240

$300

JPEP AMID Pro Forma Long-TermTarget

($ in millions)

($ in millions)

Target long-term leverage of 3.5x and liquidity of $250+ million

1

Potential non-core asset sales further enhance liquidity

2

Target ~1.2-1.3x distribution coverage with ~5% distribution growth in 2017 and 2018

3

Continue to finance growth opportunities with a conservative mix of debt and equity

4

26

Financial Strategy Designed for Growth

Distribution

Coverage

• 2017E and 2018E target distribution coverage of ~1.2-1.3x

• ArcLight to provide up to $25 million of merger support to target ~5% DCF per unit accretion in

2017 and 2018

Capital Markets

• Over $1.1 billion of drop-downs and acquisitions since 2013 at approximately an eight times

multiple

• Increased scale provides access to multiple capital markets options

• Merger increases trading liquidity and public float that accommodates greater institutional float

Leverage

• Pro forma for JP Energy merger, additional 6.2% interest in Delta House and Series D preferred

issuance, net leverage would be approximately 3.8x

• Long-term target leverage of 3.5x

Liquidity

• Pro forma for bond issuance and JP Energy merger, liquidity would be approximately $181

million and long-term target of $250+ million provides flexibility to opportunistically pursue

organic growth projects or bolt-on acquisitions with a conservative mix of debt and equity

• Optionality to divest non-core assets to enhance liquidity and re-deploy into core areas

Strong Support

from Strategic

Sponsor

ArcLight

• Will own 100% of the GP/IDRs and 49% of the LP units pro forma for the merger

• Restructured Series A preferred units to reduce minimum annual distribution to LP unit MQD

• Proven willingness to finance strategic transaction with equity investments, including convertible

preferred units with paid-in-kind distribution features

27

27

Demonstrated Support from Strategic Sponsor

• ArcLight Capital Partners, LLC is a leading energy-focused investment firm formed in 2001

• 29-person investment team that targets midstream, power and production opportunities with significant current income and meaningful downside protection and substantial growth potential

• Since inception, ArcLight has invested approximately $17 billion in 101transactions generating strong realized returns across diverse market cycles

• The firm has invested over $6.5 billion in 21 deals in the midstream infrastructure sector, including pipelines, storage terminals and gathering / processing systems

• Pro forma for the merger, ArcLight will own 94% of AMID GP and 50% of AMID LP units

• Highly supportive of merger with agreement to exchange JPEP LP units at 3.6% premium (vs. 14.5% public premium), provide merger support up to $25 million and reimburse JPEP’s transaction and transition costs

• Restructured Series A Preferred Units to reduce minimum distribution to LP unit MQD ($0.4125 per unit)

• Forgone IDR distributions until AMID returns to LP unit distribution growth

• $0.5 – $1.0 billion M&A pipeline actively supported by ArcLight; inventory of potential drop-down assets, including additional interests in Delta House

• Previous drop-downs and 3rd party acquisitions funded with equity issued to ArcLight, including convertible preferred units with the ability to PIK distributions

• $75 million AMID LP unit repurchase program ($12 million repurchased to date)

AMID SupportSelect Portfolio Companies

Note: Logos represent selected current portfolio companies. Not all ArcLight portfolio investments have the characteristics of these listed above. For more information on current and former ArcLight investments, please visit www.arclightcapital.com

Appendix: Partnership Overview

29

Offshore Assets

Delta House Lake Washington South Facility Gate 6 Facility

High Point Quivira / Burns Point Destin & Okeanos Delta House Main Pass Oil American Panther (1)

Product Gas Gas Gas Oil & Gas Oil Oil & Gas

Ownership 100.0%Quivira 100.0%

Burns Point 50.0%

Destin 49.7%

Okeanos 66.7%20.1% 66.7% 60.0%

Operator AMID AMID (Quivira)

EPD (Burns Point) AMID LLOG Panther Midstream

Panther (Oil)

AMID (Gas)

Capacity 1.1 Bcf/d 160 MMcf/d 1.2 Bcf/d 80,000 Bbl/d

200 MMcf/d 160,000 Bbl/d Various

Location

SE Louisiana, Main Pass,

Mississippi Canyon, Viosca

Knoll, West Delta

SE Louisiana Mississippi, Viosca Knoll, Main

Pass, Mississippi Canyon Mississippi Canyon

Mississippi Canyon, Main Pass,

Viosca Knoll

SE Louisiana and

GOM Shelf

Facilities800 miles of FERC-regulated &

unregulated gathering pipelines

35 miles of gathering pipelines,

cryogenic processing plant

360 miles of FERC-regulated &

unregulated gathering pipelines

Semi-submersible floating

production system; 60 miles of

oil and gas gathering pipelines,

11 wells online with life-of-lease

dedication

100 miles of oil gathering

pipelines

200 miles of oil and gas

gathering pipelines

AMID operates ~110 miles of

natural gas and saltwater

pipelines, including HGGS

Key

Customers

Phillips 66, W&T, Energy XXI,

Fieldwood, Stone, Cox

Operating, Enven, Upstream

Contango Oil & Gas,

PetroQuest, Cox Operating

BP, Exxon, Anadarko, LLOG,

Eni, Stone, Shell, FPL, Duke,

Chevron

LLOG, Ridgewood, Deep Gulf Anadarko, LLOG, Noble Cox Operating

Contract>75% long-term; life-of-lease

dedication 90% life-of-lease dedication

90% long-term; life-of-lease

dedication

100% long-term; life-of-lease

dedication 100% life-of-lease dedication 100% long-term

(1) AMID expected to acquire the remaining interest in American Panther in Q4 2016 and assume operatorship of all assets

30

Onshore G&P Assets

Longview Longview Rail Chatom

Eagle Ford East Texas Bakken Permian Gulf Coast

Product Gas Gas, NGLs, Condensate Oil Gas, NGLs, Condensate Gas, NGLs, Condensate

Capacity 220 MMcf/d70 MMcf/d gas processing,

10 MBbl/d NGL fractionation40 MBbl/d

40 MMcf/d gas processing,

8 MBbl/d NGL processing

25 MMcf/d gas processing,

2 MBbl/d NGL fractionation

Location Lavaca County, TXGregg, Rusk,

Smith Counties, TXMcKenzie County, ND

Martin, Andrews, Dawson, Gaines

Counties, TX

Chatom, AL

Bazor, MS

South LA and MS

Facilities200 mile gathering system, 30,000

HP compression

710 mile low & high pressure

gathering system, gas well & oil

processing, depropanizer

50 mile gathering system, truck

rack, H2S removal, refinery & pipe

connectivity

50 mile gathering system, 5,000

HP compression, off-spec NGL

processing, pipeline connectivity,

H2S treating

100 mile gathering system, sour

gas processing, depropanizer and

debutanizer, 90 MBbl/d NGL

pipeline, 191-mile FERC-regulated

NGL pipelines

Key

CustomersPenn Virginia, Devon XTO, Linn, Targa, Eastman Newfield, Trafigura AJAX, Energy Transfer Venture, Enterprise

Acreage

Dedication70,000 acres -- 24,000 acres 30,000 acres --

31

Harvey Westwego Brunswick Caddo Mills North Little Rock Cushing

LocationHarvey, LA

(Port of New Orleans)

Westwego, LA

(Port of New Orleans)

Brunswick, GA

(Port of Brunswick)

Caddo Mills, TX

(Dallas / Ft. Worth Area)North Little Rock, AR Cushing, OK

Product Petroleum / Chemical Chemical / Agricultural Chemical / Agricultural Refined Products Refined Products Crude Oil

Current

Capacity1,110 MBbls 1,045 MBbls 221 MBbls 770 MBbls 550 MBbls 3,000 MBbls

Facilities33 above-ground

storage tanks

48 above-ground

storage tanks

5 above-ground storage

tanks

10 above-ground

storage tanks

11 above-ground

storage tanks

5 above-ground storage

tanks

Transportation

Modes

Truck, railcar, water

vessel

Truck, railcar, water

vessel

Truck, railcar, water

vesselTruck and pipeline Truck, railcar, pipeline Pipeline

Key

Customers

Commodity brokers,

refiners and chemical

manufacturers

Commodity brokers,

refiners and chemical

manufacturers

Commodity brokers,

refiners and chemical

manufacturers

Retail fuel distributors,

refiners and marketers

Retail fuel distributors,

refiners and marketers

Crude marketer and

trader

Terminals Asset Overview

1,449 1,588 1,589 1,5192,018

2,224

218196 212 282

133118

87% 89% 88%84%

94% 95%

0%

20%

40%

60%

80%

100%

0

550

1,100

1,650

2,200

2,750

2Q15 3Q15 4Q15 1Q16 2Q16 3Q16

Utiliz

atio

n (

%)

MB

bls

Contracted Capacity Uncontracted Capacity Storage Utilization

AMID Quarterly Terminal Utilization JPEP Quarterly Terminal & Storage Throughput 1

6167

56 59 59 56

0

20

40

60

80

100

2Q15 3Q15 4Q15 1Q16 2Q16 3Q16

MB

bls

/d

1 Includes Caddo Mills and North Little Rock. Does not include Cushing

High Point Midla/MLGT AlaTenn/Bamagas/TriGas Magnolia

LocationOnshore and Offshore Southeast

LouisianaLouisiana and Mississippi North Alabama South Alabama

Product Natural gas Natural gas Natural gas Natural gas

Capacity 1,120 MMcf/d 518 MMcf/d 710 MMcf/d 120 MMcf/d

Facilities

574 miles of FERC-regulated

interstate pipelines and non-

jurisdictional gathering pipelines

that primarily serve Gulf of Mexico

producers

432 miles of FERC-regulated

interstate and intrastate pipelines

that serve various power plants,

local distribution companies and

industrial end-users

383 miles of FERC-regulated

interstate and intrastate pipelines

that serve various power plants,

local distribution companies and

industrial end-users

116 miles of intrastate pipelines

that provides FERC jurisdictional

interstate service, transports gas

from central Alabama to SE

markets

Key

Customers

BP, Cox, Fieldwood, Noble, Shell,

Stone, W&T

Exxon, Entergy, Atmos, Georgia

Pacific, Sequent

Huntsville, Athens, NAGD,

Ascend Chemical, BP, TVA,

Calpine, LS Power

Tenaska, Interconn, Spotlight,

PGP, Infinite, Rainbow, Saga

Petroleum

32

Transmission Assets & Organic Growth Projects

Interconnects

• Leverage existing interconnects with Texas Eastern, Tennessee Gas, Columbia Gas, and Transco to supply cheaper North East natural gas supply to other large long-haul pipelines serving Southeast markets

• AlaTenn interconnects will increase overall firm transportation agreements by 35%

Repurpose

Assets

• Midla-Natchez Lateral – FERC approved retirement and replacement of 12”, 50-mile Midla pipeline underpinned by multiple long-term firm transportation agreements

• High Point – filed FERC application to repurpose an underutilized gas pipeline and convert to NGL service

Note: Chart excludes the Chalmette System, a 39-mile intrastate pipeline with 125 MMcf/d of capacity

33

Interest OverviewSystem

Interest

Held

Pipeline

(miles) Product

Design

Capacity

Delta House 13.9% - - -

Destin 49.7% 255 Natural Gas 1.2 Bcf/d

Okeanos 66.7% 100 Natural Gas 1.0 Bcf/d

Wilprise 25.3% 30 Liquids 60,000 Bbls/d

Tri-States 16.7% 161 Liquids 80,000 Bbls/d

Other 60.0% 200 Natural Gas /

Saltwater

n/a

Main Pass

Oil Gathering

66.7% 98 Oil 160,000 Bbls/d

Delta House Floating Production System

Delta House

• Floating production system located in the Mississippi Canyon region in

deepwater Gulf of Mexico; operated by LLOG exploration

• 10 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 80,000 Bbl/d oil and 200 MMcf/d of gas and peak

processing capacity of 100,000 Bbl/d oil and 240 MMcf/d of gas

Destin

• FERC-regulated gas pipeline

• 120-mile offshore portion moves gas from producing platforms, including

Delta House to MP260 and continuing to Pascagoula processing plant

• 135-mile onshore portion transports gas to multiple pipelines and storage

facilities in Mississippi

Okeanos

• Gas gathering system that connects multiple producer platforms to MP260

Tri-States and Wilprise

• FERC-regulated NGL pipelines

• Tri-States receives gas from three plants and terminates at Kenner

Junction, feeding one fractionation facility and two NGL pipelines

• Tri-States connects to Wilprise pipeline at Kenner Junction and terminates

in Sorrento, Louisiana

Other

• Joint venture with Panther of natural gas, oil, and saltwater pipelines;

acquired from Chevron

• AMID to operate ~110 miles of natural gas and saltwater pipelines,

including Henry Gas Gathering System

Main Pass Oil Gathering

• Joint venture with Panther

• Crude gathering system located offshore southeast Louisiana

Legal DisclaimerGulf of Mexico Joint Ventures and Investments

Appendix: Non-GAAP Financial

Measures

35

This presentation includes forecasted and historical non-GAAP financial measures, including “Gross Margin,” “Adjusted EBITDA” and “Distributable Cash Flow.” Each has important limitations as an

analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP financial

measures as analytical tools by reviewing the nearest comparable GAAP financial measures, understanding the differences between the measures and incorporating these data points into management’s

decision-making process.

You should not consider any of gross margin, Adjusted EBITDA or DCF in isolation or as a substitute for or more meaningful than our results as reported under GAAP. Gross margin, Adjusted EBITDA and

DCF may be defined differently by other companies in our industry. Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby

diminishing their utility.

We define Adjusted EBITDA as net income (loss) attributable to the Partnership, plus interest expense, income tax expense, depreciation, amortization and accretion expense, certain non-cash charges

such as non-cash equity compensation expense, unrealized losses on commodity derivative contracts, debt issuance costs, return of capital from unconsolidated affiliates, transaction expenses and

selected charges that are unusual or nonrecurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts, and selected gains that are unusual or nonrecurring. The

GAAP measure most directly comparable to our performance measure Adjusted EBITDA is Net income (loss) attributable to the Partnership.

DCF is a significant performance metric used by us and by external users of the Partnership's financial statements, such as investors, commercial banks and research analysts, to compare basic cash

flows generated by us to the cash distributions we expect to pay the Partnership's unitholders. Using this metric, management and external users of the Partnership's financial statements can compute the

coverage ratio of estimated cash flows to planned cash distributions. DCF is also an important financial measure for the Partnership's unitholders since it serves as an indicator of the Partnership's

success in providing a cash return on investment. Specifically, this financial measure may indicate to investors whether we are generating cash flow at a level that can sustain or support an increase in the

Partnership's quarterly distribution rates. DCF is also a quantitative standard used throughout the investment community with respect to publicly traded partnerships and limited liability companies because

the value of a unit of such an entity is generally determined by the unit's yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder). DCF will not reflect changes in

working capital balances.

We define DCF as Adjusted EBITDA plus interest income, less cash paid for interest expense, normalized maintenance capital expenditures, and dividends related to the Series A and Series C convertible

preferred units. The GAAP financial measure most comparable to DCF is Net income (loss) attributable to the Partnership.

The GAAP measure most directly comparable to forecasted Adjusted EBITDA and DCF is forecasted net income (loss) attributable to the Partnership. Net income (loss) attributable to the Partnership is

forecasted to be approximately $20 million to $25 million in 2016.

Segment gross margin and gross margin are metrics that we use to evaluate our performance. We define segment gross margin in our Gathering and Processing segment as revenue generated from

gathering and processing operations and realized gains or (losses) on commodity derivatives, less the cost of natural gas, crude oil, NGLs and condensate purchased and revenue from construction,

operating and maintenance agreements ("COMA"). Revenue includes revenue generated from fixed fees associated with the gathering and treatment of natural gas and crude oil and from the sale of

natural gas, crude oil, NGLs and condensate resulting from gathering and processing activities under fixed-margin and percent-of-proceeds arrangements. The cost of natural gas, NGLs and condensate

includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to percent-of-proceeds arrangements and the cost of natural gas purchased for our own account, including

pursuant to fixed-margin arrangements.

We define segment gross margin in our Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less the

cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

We define segment gross margin in our Terminals segment as revenue generated from fee-based compensation on guaranteed firm storage contracts and throughput fees charged to our customers less

direct operating expense which includes direct labor, general materials and supplies and direct overhead.

We define gross margin as the sum of our segment gross margin for our Gathering and Processing, Transmission and Terminals segments. The GAAP measure most directly comparable to gross margin

is net income (loss) attributable to the Partnership.

3636

Appendix: Non-GAAP Financial Measures

($ in thousands) Year Ended Nine Months Ended LTM

12/31/2015 9/30/2015 9/30/2016 9/30/2016

Net income (loss) attributable to the Partnership ($127,480) ($5,899) ($7,051) ($128,632)

Add:

Depreciation, amortization and accretion expense 38,014 28,099 31,531 41,446

Interest expense 13,631 9,029 16,854 21,456

Debt issuance costs paid 2,238 1,984 3,987 4,241

Unrealized (gain) loss on derivatives, net 71 (523) 1,430 2,024

Non-cash equity compensation expense 3,863 2,891 2,213 3,185

Transaction expenses 1,426 1,368 9,557 9,615

Income tax expense 953 876 1,301 1,378

Distributions from unconsolidated affiliates 20,568 6,568 62,797 76,797

General Partner contribution for cost reimbursement 330 330 -- --

Loss on impairment of Goodwill 118,592 -- -- 118,592

Deduct:

Earnings in unconsolidated affiliates 8,201 1,265 29,983 36,919

Construction and operating management agreement income 841 702 341 480

Other post employment benefits plan, net periodic benefit 14 9 13 18

Gain (loss) on sale of assets, net (3,161) (3,160) 90 89

Adjusted EBITDA $66,311 $45,907 $92,192 $112,596

Material Project Adjustments 10,288

Adjustment for Acquisition TTM EBITDA 30,646

Compliance EBITDA 1153,530$

Reconciliation of Net income (loss) attributable to the Partnership

to Compliance EBITDA:

AMID Compliance EBITDA Reconciliation

1 For reporting purposes under our revolving credit facility, we are required to report Adjusted EBITDA as calculated under our revolving credit facility on a last twelve month basis. We

refer to this metric as Compliance EBITDA. Compliance EBITDA is defined as Adjusted EBITDA (as defined above) plus annualized cash flow attributable to material projects

completed during such twelve-month period and pre-acquisition EBITDA for the last twelve months of acquisitions completed during such period, including $11 million Delta House

adjustment for October 2016 acquisition

3737

Appendix: Non-GAAP Financial Measures

($ in thousands) Twelve Months Ended Nine Months Ended LTM

12/31/2013 12/31/2014 12/31/2015 9/30/2015 9/30/2016 9/30/2016

Net Loss ($14,221) ($53,023) ($58,656) ($12,720) ($12,484) ($58,420)

Depreciation and amortization 30,987 40,230 46,852 34,055 34,663 47,460

Goodwill impairment -- -- 29,896 -- -- 29,896

Interest expense 8,245 8,981 5,375 3,848 5,216 6,743

Loss on extinguishment of debt -- 1,634 -- -- -- --

Income tax expense 208 300 754 333 536 957

Loss on disposal of assets, net 1,492 1,137 909 1,402 2,451 1,958

Unit-based compensation 790 1,658 1,217 803 1,393 1,807

Total (gain) loss on commodity derivatives (902) 13,762 3,057 1,985 642 1,714

Net cash payments for commodity derivatives settled during the period (209) (1,071) (14,821) (14,400) (1,082) (1,503)

Early settlement of commodity derivatives 1 -- -- 8,745 8,745 -- --

Non-cash inventory costing adjustment -- -- -- -- 227 227

Corporate overhead support from general partner 2 -- -- 5,500 3,000 5,000 7,500

Transaction costs and other 1,286 3,766 1,877 2,930 (412) (1,465)

Discontinued operations 3 6,608 14,277 16,160 2,719 168 13,609

Adjusted EBITDA $34,284 $31,651 $46,865 $32,700 $36,318 $50,483

1 Due to its non-recurring nature, JPE excluded this transaction in calculating Adjusted EBITDA2 Represents expenses incurred by JPE that were absorbed by JPE GP and not passed through to JPE3 In February 2016, JPE completed the sale of its crude oil supply and logistics operations in the Midcontinent region of Oklahoma and Kansas. In June 2014, JPE completed the sale of its

crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming

JPEP Adjusted EBITDA Reconciliation

38

Additional Information and Where to Find it

A portion of this communication relates to a proposed business combination between American Midstream and JP Energy. In connection with the proposed transaction, American Midstream has filed a

proxy statement/prospectus and other documents with the Securities and Exchange Commission (“SEC”). WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE PROXY

STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS THAT HAVE BEEN AND MAY BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY IF AND WHEN THEY

BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION. Any definitive proxy statement(s) (if and when available) will be mailed to unitholders of JP Energy. Investors and

security holders will be able to obtain these materials (if and when they are available) free of charge at the SEC’s website, www.sec.gov. In addition, copies of any documents filed with the SEC may be

obtained free of charge from American Midstream's investor relations website at http://www.americanmidstream.com/investor-relations. Investors and security holders may also read and copy any reports,

statements and other information filed by American Midstream with the SEC at the SEC public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 or

visit the SEC’s website for further information on its public reference room.

No Offer or Solicitation

This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities, or a solicitation of any vote or approval, nor shall there be any sale of securities in any jurisdiction

in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a

prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.

Participation in the Solicitation of Votes

American Midstream and its directors and executive officers may be considered participants in the solicitation of proxies in connection with the proposed merger with JP Energy. Information regarding

American Midstream’s directors and executive officers is available in its Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on March 7, 2016. Other information

regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the proxy statement/prospectus and other

relevant materials to be filed with the SEC when they become available.