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Presentation TitlePresentation Subtitle

Crestwood Midstream Partners LP Crestwood Equity Partners LP

Connections for America’s Energy™

™




™




™

12/4/2017




™




™Connections for America’s Energy™

™

Investor Presentation

December 2017

Connections for America’s Energy™ ™™ ™™ ™

The statements in this communication regarding future events, occurrences, circumstances, activities, performance,outcomes and results are forward-looking statements. Although these statements reflect the current views, assumptionsand expectations of Crestwood’s management, the matters addressed herein are subject to numerous risks anduncertainties which could cause actual activities, performance, outcomes and results to differ materially from thoseindicated. Such forward-looking statements include, but are not limited to, statements about the benefits that may resultfrom the merger and statements about the future financial and operating results, objectives, expectations and intentionsand other statements that are not historical facts. Factors that could result in such differences or otherwise materially affectCrestwood’s financial condition, results of operations and cash flows include, without limitation, the possibility thatexpected cost reductions will not be realized, or will not be realized within the expected timeframe; fluctuations in crude oil,natural gas and NGL prices (including, without limitation, lower commodity prices for sustained periods of time); the extentand success of drilling efforts, as well as the extent and quality of natural gas and crude oil volumes produced withinproximity of Crestwood assets; failure or delays by customers in achieving expected production in their oil and gasprojects; competitive conditions in the industry and their impact on our ability to connect supplies to Crestwood gathering,processing and transportation assets or systems; actions or inactions taken or non-performance by third parties, includingsuppliers, contractors, operators, processors, transporters and customers; the ability of Crestwood to consummateacquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from anyacquisition; changes in the availability and cost of capital; operating hazards, natural disasters, weather-related delays,casualty losses and other matters beyond Crestwood’s control; timely receipt of necessary government approvals andpermits, the ability of Crestwood to control the costs of construction, including costs of materials, labor and right-of-wayand other factors that may impact Crestwood’s ability to complete projects within budget and on schedule; the effects ofexisting and future laws and governmental regulations, including environmental and climate change requirements; theeffects of existing and future litigation; and risks related to the substantial indebtedness, of either company, as well asother factors disclosed in Crestwood’s filings with the U.S. Securities and Exchange Commission. You should read filingsmade by Crestwood with the U.S. Securities and Exchange Commission, including Annual Reports on Form 10-K and themost recent Quarterly Reports and Current Reports for a more extensive list of factors that could affect results. Readersare cautioned not to place undue reliance on forward-looking statements, which reflect management’s view only as of thedate made. Crestwood does not assume any obligation to update these forward-looking statements.

Company Information

2

Forward-Looking Statements

Contact Information

Corporate Headquarters811 Main Street

Suite 3400

Houston, TX 77002

(1) Market data as of 12/1/2017. (2) Unit count and balance sheet data as of 9/30/2017.

Crestwood Equity Partners LP

NYSE Ticker CEQP

Market Capitalization ($MM)(1,2) $1,719

Enterprise Value ($MM)(2) $4,015

Annualized Distribution $2.40

Investor [email protected]

(713) 380-3081

No IDRs

Corporate Structure

Connections for America’s Energy™ ™™ ™™ ™ 3

Well-Positioned for DCF per Unit Growth


Key Investor Highlights

4

• Focused on execution

• Attractive balance sheet

• Strong distribution coverage

• Disciplined growth strategy

• Self-funded capital program

• Significant insider ownership

Increased 2017E guidance reaffirmed

Long-termLeverage Ratio <4.0x

1.2x-1.3x Long-termCoverage Ratio

No equity required to fund ’17/’18 capital programs

~32% LP units; alignment of interest with LP’s

Bakken, Delaware Basin, PRB Niobrara, Marcellus


Diversified Assets in Active Basins

5

Crestwood assets offer operating scale, fixed-fee services & DCF growth

• 5-Yr Growth Strategy Driven by 4 Core Growth Areas− Bakken – 2018+− Delaware Basin – 2019+− PRB – 2019+− Marcellus Shale – 2020+

• Remaining portfolio of assets provide stable cash flows, optimization alternatives and upside optionality

Bakken

Northeast MarcellusPRB

Niobrara

DelawareBasin


Balanced Portfolio; High Quality Customers

CEQP Contract Portfolio

66

Variable Rate Contracts

15%

Take-or-Pay and Fixed-Fee Contracts

85%

~85% of Crestwood 2017 EBITDA from take-or-pay and fixed-fee contracts; Key assets protected from commodity volatility and volume declines

Long-Term Contract Profile With High Quality Customers(1)

2017 Forecasted EBITDA

(1) Not inclusive of all Crestwood customers.

Stable cash flows supported by fixed-fee contracts, top-tier customer base and balanced commodity exposure by volume and EBITDA

G&P assets backed by 1.1 million acreage; High quality producer mix

Top-tier NE Gas Storage & Transportation franchise; Largely investment grade

Diversified NGL Marketing, Supply & Logistics business

60% 20%

20%

48%

29%

23%

Gas Oil NGLs

Volumes by Commodity

EBITDA by Commodity


0

10,000

20,000

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J‐16 F‐16 M‐16 A‐16 M‐16 J‐16 J‐16 A‐16 S‐16 O‐16 N‐16 D‐16 J‐17 F‐17 M‐17 A‐17 M‐17 J‐17 J‐17 A‐17 S‐17 O‐17 N‐17

0

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J‐16 F‐16 M‐16 A‐16 M‐16 J‐16 J‐16 A‐16 S‐16 O‐16 N‐16 D‐16 J‐17 F‐17 M‐17 A‐17 M‐17 J‐17 J‐17 A‐17 S‐17 O‐17 N‐17200,000

250,000

300,000

350,000

400,000

450,000

500,000

550,000

600,000


7

SW Marcellus• +42% YTD volume growth• 21 DUCs completed in 2017• 10%/yr PDP decline rate in 2018(1)

Improved Fundamentals Drive Volume Growth

System DriversKey Asset Volumes Since FY 2016

Barnett• 4% YTD modest volume decline• Active workover program in 1H:17• 5-10%/yr PDP decline rate in 2018

Bakken• +31%/13% YTD oil/gas volume growth• 100-110 well connects in 2017• 20-25% volume growth in 2018

Delaware Basin• +215% YTD volume growth• 2-3 active rigs in 2017• >20% volume growth in 2018

2017 YTD oil, gas and water volumes up 31%, 27% & 33%; continued growth expected from 2018 drilling plans

PRB Niobrara• +43% YTD volume growth• 3 active rigs in 2017• 4 rigs forecasted in 2018

BarnettSW Marcellus

Delaware Basin PRB Niobrara

Bakken – Natural GasBakken – Oil

30,000

40,000

50,000

60,000

70,000

80,000

90,000


Third-party curtailments

+31% +13%

+215%

+42%

+43%

(4%)

(1) MVCs through 2018 term; however, all current and future cash flow reflective of actual throughput and rate (no cash flow cliff).


Disciplined Organic Growth Strategy

Project Region Key Customer(s) 2017-2018 Capital ($MM) In-Service

Date

Nautilus System Delaware Basin Shell $130MM/~$32MM net to CEQP IN-SERVICE

Arrow Debottlenecking – Phase 1 Bakken Arrow Producers $45MM IN-SERVICE

Bear Den Processing Plant - Phase 1 Bakken Arrow Producers $115MM IN-SERVICE

Arrow Debottlenecking – Phase 2 Bakken Arrow Producers $85MM 2018 / 2019

Orla Processing Plant and Pipeline Delaware Basin Multiple(1) $170MM/$10MM net to CEQP(2) Q3 2018

Bear Den Processing Plant - Phase 2 Bakken Arrow Producers ~$185MM Q2 2019

Incremental Annual Cash Flow Impact from Capital Projects

Committed high return expansion projects drive accretive DCF growth in 2017-2021

(1) Current customers include Concho, Mewbourne, Matador, Cimarex, Marathon and ExxonMobil. Significant third party customers within close proximity of the Orla Plant’s anticipated location.

(2) Assumes First Reserves covers $160 million of plant capital in return for a 50% ownership in the Willow Lake gathering and processing assets.

Highlights

• High-grading organic expansion around core assets; focused on driving greatest DCF per unit accretion

• High rate of return project build multiples of 5x to 7x

• ~$120MM+ expected EBITDA contribution from current projects by 2021

Focused on 5x to 7x organic build multiples vs 12x to 15x M&A multiples

$0

$20

$40

$60

$80

$100

$120

2017 2018 2019 2020 2021

Increm

ental A

nnua

l Cash Flow

($US Millions)

Bakken Delaware Basin


Self-Funded 2017 and 2018 Capital Programs

US Salt Divestiture

Crestwood is committed to maintaining a strong balance sheet and excess distribution coverage as it pursues organic growth projects

• Divested US Salt LLC, a non-core business in the MS&L segment, for approximately $225 million

• Valuation is ~11x 2017E distributable cash flow

• Transaction closed December 1, 2017

Crestwood is self-funding its 2017 and 2018 capital programs to maximize project returns and DCF/unit value creation

Retained DCF

Joint-Venture Strategy

• Forecasted cash flow growth allows Crestwood to maintain distribution coverage >1.2x and leverage <4.0x

• Crestwood will reinvest cash flow into accretive organic projects in Q4 2017 and FY 2018

• Strategic joint-ventures minimize project risk and capital commitments, while enhancing commercial opportunities:– Delaware Basin: First Reserve and Shell Midstream (NYSE: SHLX)– NE Marcellus: Consolidated Edison (NYSE:ED)– PRB Niobrara: Williams Partners (NYSE:WPZ)

1

2

3


Attractive Set of Near-term Organic Growth Projects


Bakken Growth Strategy

11

Crestwood continues to expand the Bakken Arrow System to offer producers full value-chain services and meet growing volume forecasts

Arrow Overview

Oil

Natural Gas

Water

• Arrow Gathering system expected to generate ~$120MM of Adj. EBITDA in 2017; ~$90MM in 2016 Adj. EBITDA

• >1,500 drilling locations identified on dedicated acreage

• Diversified and balanced group of producers: WPX, QEP, XTO, EnerPlus, Bruin, Rimrock

• 8-year weighted average contract length and Crestwood purchases 100% of oil and gas volumes at the wellhead

• Crestwood expects to connect >100 wells in both 2017 and 2018

• The Arrow system will be Crestwood’s largest driver of cash flow growth in ’17/’18

3-Product Growth Strategy• Oil gathering volumes expected to increase ~15% in 2018

• Current projects: Increasing oil gathering capacity to 120 MBbls/d

• Gas gathering volumes expected to increase ~50% in 2018

• Current Projects: (1) Increasing gas gathering capacity to 120 MMcf/d and (2) Bear Den Plant: 2-phase 150 MMcf/d plant; Evaluating downstream NGL solutions to optimize producer netbacks and project returns

• Water gathering volumes expected to increase ~60% in 2018

• Current projects: Increasing water gathering capacity to 90 MBbls/d and new SWD wells

1

2

3

Forecasted Volume Growth

80 well connects per year through 2021 drives

15-20% EBITDA CAGR

–

25

50

75

100

125

2013 2014 2015 2016 2017 2018 2019 2020 2021

Oil (MBbl/d) Water (MBbl/d) Gas (MMcf/d)


0

30

60

90

120

150

YE 2017 YE 2019

Capa

city (M

Mcf/d)

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Capa

city (M

Bbls/d)

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city (M

Mcf/d)

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Capa

city (M

Bbls/d)

Arrow System Expansion Projects

12

Arrow expansions nearly double capacity to support long-term development plans and increasing Bakken well performance

Gathering Projects

New Oil & Water Pumps

New Compressor

Station

Bear Den Plant

Phase 1: 30 MMcf/d

Phase 2: 120 MMcf/d

SWD Expansions

Crude Gathering Water Gathering Gas Gathering Gas Processing

+50% +70% +120% +400%


Arrow Bear Den Processing Plant

Crestwood’s Bear Den West pipeline and Phase 1 plant commissioned in late November 2017; Phase 2 scheduled for Q2 2019 as Arrow volumes ramp up

Greatly enhances Flow Assurance and “control of our own destiny”

Project Rationale

Project Overview• Bear Den Processing Plant is a two phase processing

solution that will provide 150 MMcf/d of combined processing capacity

• Phase 1: “Immediate solution” - 30 MMcf/d RJT unit sized to process excess gas volumes currently flaring or above third-party contracts

– Phase 1 project cost $115MM

– Commissioned late November 2017

• Phase 2: “Long-term solution” - 120 MMcf/d cryogenic plant sized to process 100% of Arrow gas by 2019

– Phase 2 project expected cost ~$185MM

– Targeted in-service Q2 2019

• Attractive total project returns of sub-6x; Phase 1 project accretive to DCF in 2018

Bear Den Plant – Phase 1

Better netbacks and more reliable service for Arrow producers than existing processor and competing proposals

Improves competitive position and ability to attract incremental third parties in the area

Enables Crestwood to utilize integrated midstream value chain with incremental volumes

Bear Den plant phase-1: final stages of construction

Crestwood purchases 100% of oil and gas volumes at the wellhead from its producers; full control of processing volumes


Delaware Basin Growth Strategy

14

Asset MapAsset Overview & Strategy

Crestwood is building competitive scale and fully integrated systems in the heart of the Delaware Basin, the most active shale play in the US

• 50/50 joint venture with First Reserve

• Current assets includes Willow Lake gathering & processing and Nautilus gathering & compression

– Total gathering capacity of 335 MMcf/d

– Total processing capacity of 85 MMcf/d

• Current growth projects: In-Service

– 30 MMcf/d dew point control skid Complete

– Orla Express Pipeline Q3 2018

– 200 MMcf/d Orla Processing Plant Q3 2018

• Future expansion opportunities:

– Crude oil gathering, terminalling and condensate stabilization/blending

– Produced water gathering and disposal

>$100 million of total Delaware Basin EBITDA potential by 2021 from identified expansion opportunities


Delaware Basin Current G&P Assets

15

Willow Lake and Nautilus gathering systems, combined gather over 110 MMcf/d, are at the center of significant development activity in the Delaware Basin

Delaware System MapsWillow Lake System• Willow Lake Gathering and Processing System is at the epicenter of

Northern Delaware Basin development in Eddy and Lea counties, NM

– ~82 miles low pressure gathering system

– Current processing capacity of 85 MMcf/d (includes 30 MMcf/d expansion to handle volume growth during 3Q17-2Q18)

• Existing acreage/well dedications with Concho and Mewbourne supported by 100,000 acre AMI around plant/system

• The Orla Express pipeline will connect the Willow Lake system to the Orla Processing Plant in 1H 2018

Nautilus System

Asset Ownership:Willow Lake

Orla Plant Nautilus

Crestwood 50% 50% 25%

First Reserve 50% 50% 25%

Shell Midstream - - 50%

• Nautilus Natural Gas Gathering System supports Shell’s Delaware Basin development program

– 20-year tiered fixed-fee gathering and compression contract

– 100,000 acreage dedication in Loving and Ward counties, TX

• ~$90MM of capital invested in 2017 at a ~5.0x build-multiple

• October 2017 – Shell Midstream exercises option to acquire 50% interest in the system; further aligning Crestwood’s and Shell’s interests

Over 200K dedicated acres

The Permian basin is the most important asset within Shell’s unconventional portfolio, Shell has around 270k acres in the Permian, and intends to invest $1 billion per year to grow production to 155 MBbls/d by 2020.” –SHLX Q2’17 Earnings Call


Orla Express Pipeline & Orla Processing Plant

16

200 MMcf/d processing plant and super-header integrates asset footprint to compete across the entire primary Delaware Basin catchment area

Premier G&P Footprint in Delaware Basin Core

WES/ETP Bone Spring

Project Overview• Construction underway on 33 miles

of 20” pipeline and 200 MMcf/d cryogenic gas plant in Orla, TX

– Plant capacity expandable to 600 MMcf/d

– Plant location offers multiple residue and NGL takeaway options

• Initial phase connects Willow Lake gathering to Orla Express and Orla plant

– Base scope capital of ~$170 million

– Targeted in-service date Q3 2018

• Expansion phase will connect the Nautilus system to Orla plant and new laterals connecting additional producers

Orla Plant: 200 MMcf/d cryogenic gas processing

plant

Orla Express Pipeline connecting existing

Willow Lake system to new Orla gas

processing plant

(1)

(1) Assumes First Reserves covers $160 million of plant capital in return for a 50% ownership in the Willow Lake gathering and processing assets.


Delaware Basin Water Solutions Next Leg of Growth

17

Scalable infrastructure solutions for Delaware Basin water requirements; potential next phase of Delaware Basin growth strategy

Delaware Water Production

• Based on Crestwood’s current capture area, 2.4 MMBbls/d of produced water is forecasted by 2021

• Crestwood’s existing assets well-positioned to offer water gathering and disposal services to producers

• Crestwood has extensive experience gathering and disposing produced water in the BakkenCapture Area.

1.0 1.2

1.6

2.0

2.4

–

0.5

1.0

1.5

2.0

2.5

3.0

2017 2018 2019 2020 2021

Source: DrillingInfo and Wood Mackenzie.(1) Water forecast based on capture area gas forecast and converted to

water based on GORs and WORs for the Wolfcamp and Bone Spring type curves per Wood Mackenzie.

EddyLea

Culberson

JeffDavis

Loving

Pecos

Reeves

Ward

Winkler

Daily Production (BBL)

5-YR Delaware Basin Water Forecast(1)

MMBbls/d


• Strategic 50/50 JV with Consolidated Edison (“Con Edison”)• Extensive network of FERC regulated storage and pipeline

assets located at center of prolific Marcellus dry-gas resource play− 2.9 Bcf/d delivery capacity; over 180 miles of pipes− 41 Bcf storage capacity

• Evaluating incremental takeaway projects out of the NE Marcellus basin with downstream pipeline partners

• Stagecoach generated ~$145MM Adjusted EBITDA in 2016; Current CEQP cash flow distribution is 35%− June 2018: Cash flow distribution steps up 5% to 40%− June 2019: Cash flow distribution steps up 10% to 50%

NE Marcellus is largest US gas supply base and best potential for demand growth; Stagecoach is strategically positioned to capture growth opportunities

23%

49%

28%

79%

13%

9%

NE Marcellus - Stagecoach Gas Services JV

18

Assets MapStagecoach Overview

Stagecoach Storage Customers

Producers

Marketers

Marketers

Utility / LDCs

Producers

Stagecoach Transportation Customers

Utility/ LDCs

CON EDISON SERVICE AREA


PRB Niobrara – Jackalope G&P JV

19

CHK PRB Net Production Potential

Source: Chesapeake Energy Company Presentations.

• PRB Jackalope JV - Crestwood (50%) and Williams (50%) owns 180 MMcf/d gas gathering system and 120 MMcf/d processing plant in Converse Co., Wyoming

• 20-year fixed fee contract; Includes minimum revenue guarantees for 5 – 7 years

• Chesapeake is currently drilling in the Turner, Parkman, Mowry and Sussex formations in addition to Niobrara

− Current gas volumes at >60 MMcf/d up from 46 MMcf/d from FY 2016

− Recent Turner test:

2,886 Boe/d with 51% oil cut



• Potential to grow production to more than 100,000 boe/d over the next five to seven years

Overview

New G&P contract allows Chesapeake to accelerate development plans and achieve full potential of PRB Niobrara acreage

388KDedicated Acres

2,600Drilling Locations

Chesapeake is currently running 3 rigs on the Jackalope system andone dedicated frac crew; expect to add a 4th rig in Q1 2018

CHK Outperforming Industry Offsets

5Productive Zones


$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

050

100150200250300350400

Q3:15 Q4:15 Q1:16 Q2:16 Q3:16 Q4:16 Q1:17 Q2:17 Q3:17

Gathe

ring Vo

lumes (M

Mcf/d)• Crestwood & BlueStone have 10-year

agreement

– Fixed-fee and percent of index fee structure for both Natural Gas and NGLs

– Contract structure provides significant upside as commodity prices rebound

• BlueStone brought 7 DUCs online in the first quarter 2017

• Active workover program designed to eliminate system declines and modestly grow volumes

• BlueStone evaluating new development and refrac opportunities

Barnett G&P Update

20

BlueStone’s workover activities and recent DUC completions off-set natural volume declines in 2017; Stable 4% YTD volume decline

Asset Overview Barnett Gathering Volume Growth

Increased volumes combined with fixed-fee/percent of index contract structure drive cash flow outperformance

Natural Gas Prices Since 2016(1)

BlueStone Begins System Reactivation

April 15th: BlueStone Agreement

(1) Source: EIA Henry Hub Natural Gas Spot Price.

1H:17 Workovers Offset Natural Field Decline


• 20-year, fixed-fee gathering and compression services w/ Antero Resources

• 140,000 acreage dedication; System capacity of 875 MMcf/d

• 100 MMcf/d compression services on AM gathering in Western Area (90% utilized)

• MVCs through 2018 term; however, all current and future cash flow reflective of actual throughput and rate (no cash flow cliff)

• 21 DUCs brought online in 2017

SW Marcellus G&C Update

21

Gathering volumes up 42% YTD 2017 as Antero completes DUC Inventory

Overview

Highlights• ~275 wells have been connected to Crestwood’s system – No

dry holes

• Avg. 30D IP rate ~8.0 MMcf/d; Avg. EURs between 8–12 Bcf(1)

• 800+ liquid-rich (>1,100 BTU) drilling locations and 1,000+ dry gas drilling locations remain

• Growing NGL processing at the Sherwood plant with increased market takeaway capacity out of the basin

• Multiple large SW Marcellus operators hold acreage positions contiguous to Crestwood’s eastern AOD

East AODWestern Area

Arsenal Resources

EQT

Noble Energy

EQTSWN

(1) Source: Wood Mackenzie.

200,000

250,000

300,000

350,000

400,000

450,000

500,000

550,000

600,000


Asset Map

Gathering Volumes Since FY 2016

21 DUCs in 2017 increased daily volumes >150 MMcf/d

Well connections in 2017 highlight exceptional reservoir quality and significant upside growth potential with incremental activity

Mcf/d


Balance Sheet Strength, Disciplined Capital Allocation, Accretive DCF Growth


Delivering on 2017 Guidance

23

EBITDA*

DCF*

Growth Capital*

Leverage

Coverage

Commitment to execution, lower cost structure and consistent quarterly results; delivering on increased 2017 financial guidance

$360 $390 $400$380

$200 $230$210

$130 $150 $250$225

4.0x 4.5x

1.2x 1.4x

Original Guidance Range Increased Guidance Range

*Dollar amounts shown in $US millions.


$0

$200

$400

$600

$800

2017 2018 2019 2020 2021 2022 2023 2024 2025

Strong Balance Sheet & Liquidity

24

• Top-tier leverage position– Q3 2017 leverage of 4.1x or 3.8x pro forma for

US Salt divestiture– Current borrowing capacity ~$650 MM

• Committed to long-term leverage <4.0x once growth projects come online

• No near-term maturities; attractive long-term capital

• Evaluating divestitures to ensure leverage targets

Balance Sheet Positioned for Strength Current Capitalization

Preferred Equity Overview• Crestwood has ~$650MM preferred equity

outstanding

• Annual distribution of 9.25% payable quarterly

• Crestwood began cash payments attributable to the Q3 2017 distribution

• Preferred equity holders have option to convert 1-for-10 after Q2 2017 (~7.1MM common units) – Investor conversion unlikely and no forced

conversion

Crestwood strengthened its balance sheet by repaying approximately $1 billion of debt in 2Q 2016; Crestwood targets YE 2017 leverage of 4.0x-4.5x

No Near-Term Debt Maturities($MM)

RCF

6.25% Notes

5.75% Notes

Issue Price Yield

2023 104.00 4.9%

2025 103.00 5.1%

Actuals Actuals Actuals Pro Forma($ millions) 2015 2016 Q3 2017 US SALT

Cash $1 $2 $1 $1

Revolver $735 $77 $444 $219

Senior Notes 1,800 1,475 1,200 1,200

Other Debt 9 6 2 2

Total Debt $2,544 $1,558 $1,647 $1,422

Total Leverage Ratio 4.8x 3.7x 4.1x 3.8x


The Crestwood Investment Opportunity

25

Focused on aggressively executing growth opportunities while maintaining financial strength

• SELF-FUNDED near-term gathering and processing growth opportunities in the Bakken and Delaware Basin

• Long-term PRB and northeast Marcellus pipeline projects

In the meantime…

• Crestwood is well-positioned to deliver attractive yield to investors(1)

– Current Yield = 9.8%; Coverage Ratio = 1.2x; Leverage Ratio = 3.8x

• Diversified business mix and strong contract portfolio

• No incentive distribution rights

• Assets leveraged to volume growth with commodity price improvement

• Reversion to Peer Group / Alerian yield provides significant upside for units

Execution Drives Significant Upside Return Opportunity;CASH FLOW PER UNIT GROWTH TO RESUME IN 2018

(1) Current yield data as of 12/1/2017. Coverage ratio and leverage ratio as of 9/30/2017 and pro forma for the US Salt divestiture for $225 million.


Appendix

2626

Appendix:


CEQP Non-GAAP Reconciliations

27

CRESTWOOD EQUITY PARTNERS LP Full Year 2017 Adjusted EBITDA and Distributable Cash Flow Guidance

Reconciliation to Net Income (in millions) (unaudited)

Net income (loss) $(13) - $7 Interest and debt expense, net 105 Loss on modification/extinguishment of debt

38 Depreciation, amortization and accretion 195 Unit-based compensation charges

25 Earnings from unconsolidated affiliates

(50) - (55) Adjusted EBITDA from unconsolidated affiliates

80 - 85

Adjusted EBITDA $380 - $400 Cash interest expense (a) (100) Maintenance capital expenditures (b) (20) - (25) Cash distributions to preferred unitholders (c)

(45)

Distributable cash flow attributable to CEQP common unitholders (d) $210 - $230

(a) Cash interest expense less amortization of deferred financing costs plus bond premium amortization plus or minus fair value adjustments. (b) Maintenance capital expenditures are defined as those capital expenditures which do not increase operating capacity or revenues from existing levels. (c) Includes cash distributions to Crestwood Niobrara preferred unitholders and cash distributions to preferred unitholders. (d) Distributable cash flow is defined as Adjusted EBITDA, less cash interest expense, maintenance capital expenditures, income taxes, deficiency payments

(primarily related to deferred revenue). Distributable cash flow should not be considered an alternative to cash flows from operating activities or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity, or the ability to service debt obligations. We believe that distributable cash flow provides additional information for evaluating our ability to declare and pay distributions to unitholders. Distributable cash flow, as we define it, may not be comparable to distributable cash flow or similarly titled measures used by other corporations and partnerships.

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