Raging Capital Management's "Crestwood Comeback" Plan

Crestwood Comeback
Crestwood Equity Partners LP (NYSE: CEQP)
December 14, 2015

Raging Capital Management, LLC (“Raging Capital”) has a beneficial and economic interest in securities of Crestwood Equity Partners LP (the “Company”). The views and opinions expressed in the
materials contained herein represent the opinions of Raging Capital and are based on or derived from publicly available information with respect to the Company and other industry participants. Other parties
may form different conclusions based on the same publicly available information. In addition, there may be confidential or other information in the possession of the Company that could lead it to disagree
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obligation to notify any other party of any such changes. Raging Capital has no obligation to update the information or opinions, analyses or conclusions contained in any materials presented herein.
Certain financial projections and information presented are based on or derived from filings made with the Securities and Exchange Commission (“SEC”) and other regulatory authorities, and information or
presentations issued by the Company, other companies and from other third parties. Neither Raging Capital nor any of its affiliates shall have any liability for any misinformation contained in any third party
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There is no assurance or guarantee with respect to the prices at which any securities of the Company or other companies will trade, and such securities may not trade at prices that may be implied herein.
The estimates, projections and potential impact of the opportunities identified by Raging Capital herein are based on assumptions that Raging Capital believes to be reasonable as of the date of the materials
presented, but there can be no assurance or guarantee that actual results or performance of the Company will not differ, and such differences may be material.
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The materials presented contain forward-looking statements that involve certain risk and uncertainty. All projections, forecasts and estimates, including, without limitation, any statements contained herein
that are not clearly historical in nature or that necessarily depend on future events are forward-looking, and the words “anticipate,” “believe,” “expect,” “potential,” “opportunity,” “scenario,” “estimate,” “plan,”
“case” and similar expressions are generally intended to identify forward-looking statements. The projected results, forecasts, estimates and statements provided herein that are not historical facts are based
on current expectations and assumptions, as of the dates indicated and involve risks, uncertainties and other factors that may cause actual results or performance to be materially different from any future
results or performance presented by such projected results and statements. Forward-looking statements involve certain assumptions and involve judgments with respect to, among other things, future
economic, competitive and market conditions including commodity prices and future business decisions of the Company, all of which are difficult or impossible to predict accurately and many of which are
beyond the control of Raging Capital. Although Raging Capital believes that the assumptions underlying the projected results or forward-looking statements are reasonable as of the date presented, any of
the assumptions may be inaccurate and therefore, there can be no assurance that the projected results or forward-looking statements included herein will prove to be accurate. As a result of the significant
uncertainties inherent in the projected results and forward-looking statements provided herein, such information should not be regarded as a representation as to future results or that the outcomes and
potential scenarios presented or implied will be achieved. Raging Capital will not undertake and has no obligation to disclose the results of any revisions that may be made to any projected results or forward-
looking statements herein or to update the materials presented based on actual events whether anticipated or unanticipated.
Disclaimer

 A fee-based midstream MLP with embedded
IDRs that operates in three segments:
 NGL and Crude Services: Includes its NGL
supply and logistics business, crude oil rail
terminals, and the Arrow gathering system
 Gathering and Processing: Provides natural
gas gathering, processing, treating, and
compression services in the Marcellus, Barnett,
Fayetteville, PRB Niobrara, and other basins
 Storage and Transportation: Owns and
operates natural gas storage facilities with an
aggregate working gas storage capacity of
approximately 79.3 Bcf
Crestwood Equity Partners LP (CEQP)
Crestwood Equity Partners: Classically Cheap
Crestwood Equity Partners (CEQP)
Price $14.28
Shares Outstanding 68.6M
Market Cap $980M
Enterprise Value $4.2B
EV/’15 EBITDA* 7.5x
EV/’16 EBITDA* 7.1x
Yield 38.5%
Leverage 4.6x
IDR 0%
Sources: FactSet, Raging Capital estimates
CEQP unit price as of 12/11/15
*EBITDA = Raging Capital “base case” estimate

Raging Capital View:
 CEQP’s stock is extremely undervalued and misunderstood
 Investors are getting paid to wait
 Attractive assets in Northeast storage, Marcellus, Bakken, Niobrara, and Permian
 Embedded IDRs is an underappreciated benefit to unitholders over the long term
 Partially cutting the distribution would provide multiple levers to drive unitholder value
Why We Are Bullish on Crestwood

 Failed strategic alternatives process
 Multiple potential bidders/partners when stock was at a split-adjusted price range of
$60 to $140 per unit, but a transaction was not consummated
 Tax-loss selling and decreased liquidity following reverse stock split
 MLP asset class pressure from energy price declines and technical factors
 Many MLPs have direct exposure to oil and natural gas prices, as well as an IDR
structure that is unfavorable to LP unitholders
 Exposure to Bakken crude-by-rail and gathering contracts and a bankrupt Barnett
Shale producer
Why Has CEQP’s Stock Come Under Pressure?

 Under our worst-case 2017 scenario of $529M in EBITDA, CEQP would trade at:
 3.4x P/DCF
 29.4% DCF yield
 Under our base-case 2017 scenario of $607M in EBITDA, CEQP would trade at:
 2.7x P/DCF
 37.3% DCF yield
 Based on their 2017 LP’s contributions, the average midstream MLP trades at:
 9.1x P/DCF, and 9.5x for companies with embedded IDRs
 11.8% DCF yield, and 11.2% for companies with embedded IDRs
MLP Valuation
Sources: FactSet, Raging Capital estimates as of 12/11/15; For CEQP assumes $32.5M of maintenance capex and $50M in growth capex in ‘16 and ’17 and preferreds paid in cash for ‘17
Midstream MLP peer group: AM, BPL, EEP, ENLK, EQM, ETP, OKS, NS, PSXP, SEP, TCP, TLLP, VLP, WES, WPZ
Embedded IDR Midstream MLP peer group: EPD, GEL, KMI, MMP

Peer Valuations
Sources: FactSet as of 12/11/15, Raging Capital estimates for KMI
Company Ticker 2016 P/DCF 2017 P/DCF 2016 DCF Yield 2017 DCF Yield 2016 Leverage
Antero Midstream Partners LP AM 11.5 12.1 8.7% 8.2% 1.4
Buckeye Partners LP BPL 10.1 9.6 9.9% 10.4% 3.8
Enbridge Energy Partners LP EEP 10.1 9.4 9.9% 10.6% 3.4
Energy Transfer Partners LP ETP 10.9 8.0 9.2% 12.5% 4.1
Enlink Midstream Partners LP ENLK 8.8 7.9 11.3% 12.7% 3.1
EQT Midstream Partners LP EQM 16.8 16.6 6.0% 6.0% 1.7
NuStar Energy LP NS 7.4 6.7 13.5% 14.9% 5.1
ONEOK Partners LP OKS 8.0 7.4 12.5% 13.6% 4.0
Phillips 66 Partners LP PSXP 11.9 8.0 8.4% 12.5% 2.3
Spectra Energy Partners LP SEP 13.4 11.5 7.5% 8.7% 3.1
TC PipeLines LP TCP 8.6 6.7 11.6% 14.9% 4.7
Teroro Logistics LP TLLP 10.2 8.7 9.8% 11.6% 3.2
Valero Energy Partners LP VLP 17.1 10.7 5.8% 9.4% 1.0
Western Gas Partners LP WES 19.2 9.0 5.2% 11.2% 2.8
Williams Partners LP WPZ 6.5 5.0 15.5% 20.0% 3.9
Average 11.4 9.1 9.7% 11.8% 3.2
Embedded IDRs
Enterprise Products Partners LP EPD 10.5 9.8 9.5% 10.2% 3.9
Genesis Energy LP GEL 8.6 7.9 11.7% 12.7% 4.8
Kinder Morgan KMI 7.4 7.0 13.4% 14.3% 5.5
Magellan Midstream Partners LP MMP 14.7 13.3 6.8% 7.5% 2.8
Average 10.3 9.5 10.4% 11.2% 4.3

 No direct commodity exposure
 90% fee-based revenues
 Embedded IDRs
 2016 run-rate costs savings of $25-30M,
and $5M public-entity cost savings
 EBITDA growth amid energy price
declines
Operating Highlights
Quarter Adj EBITDA Growth
Q4 2014 $132.7M 7.4%
Q1 2015 $141.9M 21.7%
Q2 2015 $133.1M 13.1%
Q3 2015 $133.5M 3.6%
Sources: CEQP 2014 10‐K, CEQP 2015 10‐Qs, CEQP 05/06/15 and 11/19/15 presentations

 To really understand Crestwood, investors need to take a deep dive into
each of its key assets
 We explain why Crestwood’s assets are misunderstood and lay out
potential scenarios as to how these assets are likely to perform
Asset-by-Asset Analysis

 Description
 Four storage facilities located in New York and Pennsylvania with 40.9 Bcf
of capacity
 Best asset is Stagecoach in NY, which has 26.2 Bcf of storage
 Also have 50% ownership of Gulf Coast facility, Tres Palacios
 Contract Type
 Take-or-Pay
 100% contracted; 15% of capacity up for renewal in 2016
 Customers: Consolidated Edison (ED), NJ Natural Gas, Repsol
 2016 Estimated EBITDA Contribution: $140-150M
Asset-by-Asset Analysis: Natural Gas Storage
Sources: CEQP 2014 10‐K, CEQP 08/17/15 presentation, Raging Capital estimates

 Weighted average contract term of 4 years
 Majority of contract renewals expected at or above existing rates
 Northeast scarcity value and permitting challenges with new facilities
 Stagecoach is the closest natural gas storage facility to NYC
 MARC I Pipeline expansion adds $6.3M in revenue at 90% EBITDA margin
Natural Gas Storage Highlights
Sources: CEQP presentation 11/19/15, CEQP Q3 2015 earnings call

 Misconception
 Pricing for CEQP’s Northeast storage assets may come under pressure from
low nat gas prices and diminishing summer/winter nat gas price spreads
 Reality
 Summer/winter nat gas price spreads have been deteriorating for years
 Example: Niska Gas Storage Partners (NKA) has seen its EBITDA decline
from $202M in 2010 to $36M in 2015
 CEQP’s Northeast assets have not seen this pressure
 Reality
 The Northeast storage market has always been unique due to storage scarcity
and a lack of infrastructure, often with wide price gaps versus Henry Hub
 Recall: Nat gas in New England traded at over $100 per Mcf in February 2014
following the “Polar Vortex”
Natural Gas Storage Misconception
Sources: FactSet, Forbes article, “How Can A Nation Awash In Natural Gas Have Shortages? And What To Do About It.”, 2/08/14

 2017 Worst Case: ~$130M EBITDA
 Assumes Northeast volumes don’t go above take-or-pay rates
 Assumes contribution from Marc 1 expansion and Tres Palacios JV
 2017 Base Case: ~$150M EBITDA
 Assumes Northeast volumes stay at similar rates plus some small price
increases
 Assumes contribution from Marc 1 expansion and Tres Palacios JV
 2017 Upside Case: ~$160M EBITDA
 Assumes Northeast volumes see a small increase as well as some small
price increases
 Assumes contribution from Marc 1 expansion and increased utilization at
Tres Palacios JV
Natural Gas Storage Scenario Analysis
Source: Raging Capital estimates

 Potential growth projects – such as Marc II, with a possible in-service
date of Q4 2017, and an expansion at Seneca Lake – offer additional
optionality
 We believe this is a great asset that deserves to be valued at a premium
multiple due to its steady nature and scarcity value
Natural Gas Storage Conclusion

 Description
 Provides gathering, dehydration, and compression services
 Contract Type
 Long-term fixed-fee with minimum volume commitments (MVCs) of 450
MMcf/d from 2016-2018
 5 years left on compression contract, 17 years on gathering contract
 Customers: Antero Resources (AR)
Asset-by-Asset Analysis: Marcellus Gathering

 140,000 acreage dedication with 235 wells connected
 22 well completions expected in Q2-Q3 2016
 1,850 Antero drilling locations on dedicated acreage
 Q3 2015 average gathering volumes of 522 MMcf/d vs. 450 MMcf/d MVC
 Current system capacity of 875 MMcf/d
 Over $900M of capital invested, including initial purchase price
Marcellus Gathering Highlights
Sources: CEQP 2013 and 2014 10‐Ks, CEQP 11/19/15 presentation

 Misconception
 Antero currently has no rigs on CEQP’s acreage, opting to drill its rich-gas
acreage
 It is possible that Antero may not start drilling on this acreage again
 Reality
 CEQP has 450 MMcf/d MVCs for 2016-2018, only 14% below the 522
MMcf/d rate observed in Q3 2015
 Reality
 Antero will bring online 22 wells in 2016, which should help keep volumes
relatively flat in 2016
Marcellus Gathering Misconception
Sources: CEQP 2014 10‐K, CEQP 08/17/15 and 11/19/15 presentations, AR Q3 2015 earnings call, Raging Capital estimates

 Antero, whose production is ~1.5 Bcfe/d, has firm transport commitments for ~3.8 Bcfe/d
by 2017
 The Columbia Pipeline will provide this acreage with access to premium-priced markets
in 2016
 Average initial production (IP) rate for 2015 well connects was 18 MMcf/d on CEQP
acreage – a minimum number of rigs is needed to keep volumes above MVCs
Marcellus Gathering Reality
Sources: CEQP 11/19/15 presentation, AR Q3 2015 earnings call, AR 12/2015 presentation

 Assumes volumes at MVCs
 Assumes volumes at MVCs
 Assumes Antero runs two rigs on its CEQP acreage
Marcellus Gathering Scenario Analysis

 It’s not unreasonable to think volumes remain flat in 2016, then go to MVCs in 2017
 The worst-case scenario is that EBITDA goes from ~$80M in 2015 to ~$65M in 2017
 However, Antero has very large firm transport commitments that could push it to drill its CEQP
acreage in the coming years
 Meanwhile, the decrease in NGL prices has led MarkWest to slow expansion, as evidenced by
its growth capex declining from over $3B in 2013 to guidance of $900-1,600M for 2016
 This could lead to a lack of rich-gas processing capacity in the Marcellus and a move by
E&Ps to less rich-gas areas (where CEQP’s assets are located)
 CEQP’s Marcellus acreage dedication and infrastructure is highly valuable, and Antero is likely
to drill, sell it to an E&P that will drill, or Antero Midstream (AM) may look to purchase this asset
 With a ~$4B enterprise value, AM could purchase the other half of Antero’s Marcellus acreage
dedicated to CEQP in a highly accretive deal given it has a blended cost of capital under 6%
Marcellus Gathering Conclusion
Sources: MWE 2013 10‐K, MWE Q3 2015 earnings call, AM 12/2015 presentation

 Description
 540 miles of gathering lines (including approximately 170 miles of crude
oil gathering pipeline)
 200 miles of natural gas gathering pipeline
 170 miles of produced water gathering lines
 Located in heart of the Bakken (Dunn and McKenzie counties)
 Contract Type
 Long-term fee-based with annual escalators
 Customers: WPX Energy (WPX) 34%, Halcón Resources (HK) 29%, QEP
Resources (QEP) 16%, XTO Energy 11%, Whiting Petroleum (WLL) 9%,
Enerplus (ERF) 1%
Asset-by-Asset Analysis: Arrow Gathering System
Sources: CEQP 2014 10‐K, CEQP 08/05/15 presentations, Raging Capital estimates

 150,000 acre dedication in core of Bakken; Arrow producers have filed
approximately 150 permits in past four months
 Arrow volumes have increased 13% y/y and 74% since Q1 2014; record crude
volumes announced for October 2015
 75-85 new well connects in 2015, with that expected to increase in 2016
 Core Bakken WTI breakeven is
between $20-$40*
Arrow Highlights
Sources: CEQP 11/19/15 presentation, *North Dakota Dept. of Mineral Resources

 Misconception
 Rig counts have been coming down in the Bakken, including on CEQP’s
acreage, which could negatively impact Arrow moving forward
 Reality
 Arrow is in the right area of the Bakken, with low breakeven costs
 Core Bakken well IP rates have skyrocketed in recent years due to
technological advancements while days to drill have dropped markedly
 Result: Less rigs need to be run for volumes to remain steady or increase
 Producers are also capturing dramatically more gas, as opposed to flaring
much of it as they did in the past
 Example: Halcón is capturing 95% of its gas versus only 75% a year ago
 This has resulted in increased volumes and EBITDA for Arrow’s 3-stream
gathering system, which is expected to continue
Arrow Misconception
Sources: CEQP 11/19/15 presentation, HK Q3 2015 earnings call, WPX Q3 2015 earnings call

 Assumes volumes slightly decline from current run-rate
 Assumes volumes remain at current run-rate
 Assumes volumes increase from current run-rate
Arrow Scenario Analysis

 Arrow is much more likely to see growth in the coming years than any
deterioration, even in a “lower-for-longer” energy price environment
 Hess (HES) sold its similar core Bakken midstream assets into a JV in
June 2015 at an 18x forward EBITDA multiple
 We think this is a strong asset that offers additional optionality on a rally
in oil prices
Arrow Conclusion
Source: Hess 6/11/15 presentation

 In June 2015, Hess (HES)
sold its 50% interest in its
Bakken Midstream assets into
a JV at an 18x forward
multiple
Bakken Comp
 Both assets are in the core of the
Bakken, with each having
gathering, storage, rail, and
trucking capabilities
Hess Bakken system shown above. Source: HES 6/11/15 presentation
CEQP Bakken system shown above. Source: CEQP 1/13/15 presentation

 Description
 Integrated crude oil loading and storage terminals and interconnecting
pipeline facilities located in the heart of the Bakken
 Contract Type
 Take-or-Pay
 Customers: Tesoro (TSO), U.S. Oil, Sunoco (SXL), BP (BP), Statoil
(STO)
 Exposure by End-Market: 73% West Coast, 27% East Coast
Asset-by-Asset Analysis: COLT Hub

 Largest crude-by-rail (CBR) facility in Bakken, with 20-25% market share
 Tesoro is COLT’s largest customer at ~40% of EBITDA
 145 Mbbls/d take-or-pay contracts through 2016, with contract renewals
staggered through 2019
COLT Highlights
Sources: CEQP 05/21/15 and 11/19/15 presentations

 Misconception
 Tesoro (TSO) may not renew its contract once it ends in December 2016
following its purchase of Great Northern Midstream and the Fryburg Rail
Terminal, putting 40% of the asset’s EBITDA at risk
 Reality
 Tesoro Logistics (TLLP) runs the pipe from Arrow to COLT, which then goes to
TSO’s Anacortes Refinery in Washington, a 120 Mbbls/d facility
 Tesoro and CEPQ’s systems are highly integrated
 TSO recently announced that Vancouver Energy, the largest oil-by-rail project in
the U.S. at an eventual 360 Mbbls/d, is expected to be completed in 2017
 The three largest Bakken CBR facilities – Savage Trenton, COLT, Fryburg –
combined have only around 485 Mbbls/d combined capacity
“West coast refineries are largely in the Northwest and there are Federal limitations
going into places like the Puget Sound. Refiners also like how you can get the oil
ratably.” – crude marketing and logistics consultant
COLT Misconception
Sources: TSO website, TLLP 8/19/15 presentation, TSO 12/10/15 presentation, Savage 4/10/14 press release, Raging Capital interviews, Raging Capital estimates

 Misconception
 The Sandpiper Pipeline and the
Dakota Access Pipeline coming
online in late 2016 / early 2017
could greatly impair crude-by-rail
assets in the Bakken
 Reality
 East Coast refiners predominantly
have switched to African crude
 Despite East Coast volumes
recently going to essentially zero,
overall volume at COLT has been
flat, indicating an increase in West
Coast volumes
 New pipeline capacity will not be
going to the West Coast
COLT Misconception
0
20
40
60
80
100
120
140
160
1Q 14 2Q 14 3Q 14 4Q 14 1Q 15 2Q 15 3Q 15
Colt Hub Throughput
Actual Througput MVC
Sources: CEQP 2014 and 2015 10‐Qs, CEQP 2014 10‐K, Raging Capital interviews

 Assumes Tesoro re-contracts at a substantially lower rate with reduced
volumes, with some East Coast MVCs rolling off
 Assumes Tesoro re-contracts at a lower rate with some reduced volumes
 Assumes some East Coast MVCs roll off
 Assumes overall West Coast volumes improve as TSO loses its most-
favored customer status, making COLT more attractive to other customers
 Assumes Tesoro re-contracts at a reduced rate but at similar volumes
 Assumes overall West Coast volumes improve nicely as TSO loses its
most-favored customer status, and some East Coast MVCs roll off
COLT Scenario Analysis

 While there is the possibility of a disruption in 2017 COLT volumes, TSO is betting big on
Bakken crude with Vancouver Energy USA, which is expected to go online at the end
of 2017
 With Vancouver Energy and Anacortes, TSO will be shipping an enormous amount of
crude from the Bakken in 2018 and beyond, needing to use multiple CBR facilities,
including COLT
 In a worst-case scenario, COLT EBITDA shrinks from ~$80M to ~$57-68M, but likely
bounces back in 2018 due to demand from Vancouver Energy and/or other West Coast
refiners
 It’s also possible that current low oil prices could postpone planned Bakken pipelines that
would help connect to East Coast markets, benefiting COLT when oil prices recover
COLT Conclusion

 Description
 Owns and operates 3 systems in the Barnett Shale that offer gathering,
processing, and compression services
 Contract Type
 Fixed-fee with an average of 8 years remaining
 Customers: Devon Energy (DVN) and Quicksilver Resources
 Eni Spa and Toyko Gas own 27.5% and 25%, respectively, of
Quicksilver’s Barnett assets
 2016 Estimated EBITDA Contribution: $75-$85M
Asset-by-Asset Analysis: Barnett
Sources: CEQP 2014 10‐K, Raging Capital estimates

 Misconception
 With Quicksilver in bankruptcy, CEQP may lose a material proportion of its
EBITDA and DCF
Barnett Misconception
 Reality
 While Quicksilver rejected
most of its gathering
contracts, it is reliant on
CEQP with 1,000 connected
wells
 The contract will move over
to whoever purchases the
U.S. assets out of
bankruptcy
 Pricing concessions in the
midstream space are
generally not given unless in
exchange for volume or
drilling commitments
Source: Quicksilver 9/22/15 8‐K presentation

 Quicksilver laid out two go-forward operating cases for its business: 1) stop drilling
and 2) continued drilling with rate relief
 In the worst-case scenario, volumes decline gradually over the next five years
Barnett Reality
Source: Quicksilver 9/22/15 8‐K presentation

 Assumes declining volumes from Quicksilver and Devon
 Given past industry practices, we assume no pricing concessions without
drilling or volumes commitments
 Assumes declining volumes from Quicksilver and increased Devon
volumes from lower pressure gathering
 Assumes new Quicksilver owner drills and increased Devon volumes from
lower pressure gathering and/or re-fracs
Barnett Scenario Analysis

 Quicksilver production is set to go up from 111 MMCf/d currently to 113 MMcf/d in 2016
even if it doesn’t drill, and this scenario sets a base downside scenario for 2017
 Crestwood is willing to give concessions to the future owners of Quicksilver’s acreage in
order to increase production, offering upside down the road
 In a worst-case scenario, EBITDA from Quicksilver’s acreage shrinks from ~$45M to
~$40M in 2017 and goes to ~$37M in 2018, with a flattening decline curve thereafter
 However, EBITDA from Quicksilver will decline gradually and has a good probability of
being flat to slightly increasing in a better nat gas price environment with the assets
under new stewardship
 Meanwhile, Devon volumes could increase due to CEQP offering lower-pressure
gathering services; Devon has also talked in the past about a re-fracing program in the
Barnett to boost volumes
Barnett Conclusion
Sources: Quicksilver 9/22/15 8‐K presentation, Raging Capital estimates

 Description
 Provides NGL (natural gas liquids) and crude oil storage, marketing and
transportation services to producers, refiners, marketers, and other
customers
 Contract Type
 Spread
 Customers: Over 350
Asset-by-Asset Analysis: NGL Marketing

 A summer/winter spread business for propane and butane
 Back-to-back contracts executed to avoid commodity price risk
 Benefiting from Marcellus NGL oversupply that is unlikely to dissipate anytime
soon
 Obtaining butane and propane for free
in summer and locking in $0.38-0.39
per gallon in Nov-Dec
 Spreads continue to widen
NGL Marketing Highlights
Sources: CEQP 2015 Enercom conference 11/19/15 presentations

 Assumes propane and butane seasonal spreads decline slightly
 Assumes propane and butane seasonal spreads are stable
 Assumes propane and butane seasonal spreads continue to increase
NGL Marketing Scenario Analysis

 A solid, underappreciated business that is benefiting from the
Marcellus/Utica being awash in NGLs
 A seasonally strong Q4/Q1 business that the sell-side often doesn’t take
into account in their models
NGL Marketing Conclusion

 Description
 Owns a 50% equity interest in the Jackalope system, which is 50% owned
and operated by Williams Partners (WPZ)
 Consists of approximately 162 miles of gathering pipelines and 24,080
horsepower of compression
 Contract Type
 15% annual cost-of-service fee on cumulative capex
 Contract expires in 2033
 Customers: Chesapeake Energy (CHK)
 2016 Estimated EBITDA Contribution: ~$38M
Asset-by-Asset Analysis: PRB Niobrara

 As of September 2015, $255M cumulative capex had been invested in
the Jackalope system
 Will equate to around $38M in EBITDA in 2016
 311,000 acres under dedication
 >3,000 gross drilling locations with only 126 wells drilled
PRB Niobrara Highlights
Sources: CEQP Q3 2015 10‐Q, CEQP 08/17/15 presentation, Raging Capital estimates

 Assumes no additional capex spend in 2016 or 2017
 Assumes no additional capex spend in 2016 or 2017
 Assumes a minimal amount of incremental capex spend in 2017
PRB Niobrara Scenario Analysis

 A solid contract structure in a top basin
 There could be further upside with additional capex spending in later
years, along with its ownership of Douglas Terminal
PRB Niobrara Conclusion

 Description
 Owns and operates five systems in the Fayetteville Shale to gather and
treat natural gas
 Contract Type
 Fixed-fee with an average of 10 years remaining
 Customers: BHP Billiton (BHP)
 2016 Estimated EBITDA Contribution: <$15M
 2017 Scenario Analysis: ~$12-13M in EBITDA, assuming volume
declines
 Conclusion: Small asset with declining EBITDA contribution assumed
Asset-by-Asset Analysis: Fayetteville

 Recently announced $500M JV with sponsor First Reserve
 First Reserve will fund 100% of initial build-out capital
 Cash flows expected to begin after first $250M of capital is invested
 Project includes 3-stream gathering system, crude storage terminal, and
condensate pipeline header, with in-service date of Q2 2017 for the pipeline
 Current small footprint in Delaware Permian with Willow Lake
 The most active crude shale play in the U.S., represents a large potential
growth vehicle
Delaware Permian Opportunity
Sources: CEQP 10/28/15 press release , CEQP 11/19/15 presentation

 Unlike CEQP, the typical master limited partnership (LP) pays incentive distribution
rights (IDRs) to a General Partner (GP)
 While the industry contends this is done to help the GP grow the LP more quickly, it is
a major cash drain to LP holders over time
 As an example, at its current distribution run-rate, Sunoco Logistics (SXL) is paying
nearly 36% of its DCF to its GP, Energy Transfer Equity (ETE), siphoning off a large
percentage of its cash flow
The Power of Embedded IDRs
Sources: FactSet, SXL Q3 2015 10‐Q, Raging Capital estimates

 CEQP has embedded IDRs
 The company does not have to pay a large percentage of its DCF to a
separate entity that adds little value, providing CEQP with a favorable
structure relative to many other MLPs
 MLPs with embedded IDRs have a large cost of capital advantage versus
peers in a normalized environment
 We believe MLPs with embedded IDRs should trade at large premiums
to their peers, not at a discount
The Power of Embedded IDRs

 We believe CEQP’s balance sheet is in good shape
 A new $1.5B revolver was established in September 2015 at a favorable
rate, with nearly $800M liquidity remaining
 Its nearest debt maturity is in 2020
 Debt/EBITDA of 5.0x in our 2017 worst-case scenario versus CEQP’s 5.5x
leverage covenant
 Robust interest coverage ratio* of nearly 3.0x in 2016, and 2.5x in our 2017
worst-case scenario
 In a worst-case scenario, it will generate over $235M of FCF (not DCF) in
2017 and over $315M of FCF in our base case scenario
The Balance Sheet
Sources: CEQP Q3 2015 10‐Q, Raging Capital estimates. *Assumes preferred interest payments paid in cash.

 While the Alerian MLP Index (AMLP) has been under pressure, down -17% over the
past month, the price of CEQP’s common units has declined -42%
 CEQP has traded more in line with E&P MLPs that are facing serious liquidity issues
Trading Disconnect
Source: Yahoo Finance 12/11/15

 However, the bond market is clearly telling us one of these companies is
not like the others
The Bonds Tell a Different Story
Crestwood Bonds vs. E&P MLP Bonds
Company Yield to Maturities
Crestwood Equity Partners (CEQP) 9‐11%
Legacy Reserves (LGCY) 41‐46%
Atlas Resource Partners (ARP) 41‐46%
Breitburn Energy Partners (BBEP) 40‐49%
Linn Energy (LINE) 32‐72%
Source: Bloomberg 12/11/15

 A range of EBITDA scenarios in 2017:
 Worst Case: $529M
 Base Case: $607M
 Upside Case: $687M
 At $14.28 per unit, CEQP is valued
between 6.1x and 7.9x 2017
EV/EBITDA
 CEQP would generate between
$4.20-$6.50 in DCF per unit in 2017,
when treating the preferred interest
payments as cash
So Where Does That Leave Us?
Source: FactSet as of 12/11/15, Raging Capital estimates

 We believe that CEQP is
materially undervalued even
in a “lower-for-longer” energy
price environment
 However, we have seen how
quickly sentiment can shift in
the MLP space if energy
prices do bounce back
2008 Comparison
Source: FactSet

 We think the pressure CEQP is seeing today is very reminiscent of 2008, when large-
cap diversified MLPs on average fell about 50% and gathering and processing (G&P)
MLPs dropped by 80%
 In fact, G&P MLPs tended to bottom at 7-8x EV/EBITDA, a multiple similar to where
CEQP currently trades, and at yields between 20-50%
 Notably, these firms generally had much more direct commodity exposure than
CEQP, which is 90% fee-based
 By the end of 2010, the large-cap MLPs would rally 127% on average from their 2008
lows, while the average G&P MLP would rally 374%, excluding distributions
2008 Comparison
Source: FactSet

 However, let’s take a step back and look at Crestwood from the perspective
of a traditional value investor, not using “MLP math”
 At $14.28 per unit, CEQP trades at a 31% free cash flow yield (FCF, not
DCF) based on our 2016 estimates of $593M in EBITDA, $357M in DCF,
and $307M in FCF
 In our 2017 worst-case scenario, CEQP currently trades at a 24% FCF yield
 In our 2017 base-case scenario, CEQP currently trades at a 32% FCF yield
Crestwood the Company, Not the MLP
Source: Raging Capital estimates, Preferreds treated as cash payments

 FCF yields this high are normally ascribed to businesses considered at risk of permanent
secular decline
 In fact, CEQP’s FCF yield is considerably higher than a sample of companies that operate
in secularly declining industries
 This is not the type of valuation that should be given to a company with long-term fixed-fee
contracts, generally stable volume expectations, and strategically valuable assets
Crestwood the Company, Not the MLP
Source: Factset as of 12/11/15

Raging Capital View:
 Crestwood is not just undervalued by MLP standards – it’s extremely
undervalued by any standard
 The bond market illustrates the disconnect between the health of the company
and the price of the stock
 The decline in CEQP has created the best opportunity in the midstream MLP
space we have seen since late 2008 and early 2009
 While the company does not have to cut the distribution, we think it would be in
the best interests of unitholders for the company to invest in itself
 While the decline in unit price has been painful for unitholders, CEQP is now the
best holiday gift out there today for investors
We think CEQP is materially undervalued even in a worst-case scenario.
Crestwood Conclusion

Industry Glossary
 Distributable Cash Flow (DCF) – Adjusted EBITDA less cash interest expense, maintenance
capital expenditures, and other non-cash items
 DCF Yield – DCF divided by market cap
 Fixed-Fee vs. Take-or-Pay – Fixed-fee contracts have volumetric risk, but no commodity risk, while
take-or-pay contracts carry no volume or commodity risk
 Incentive Distribution Rights (IDRs) – Rights that give a General Partner (GP) an increasing share
of the distribution that a limited partner pays out; they are typically capped at 50%
Appendix

Class A Preferred Detail
 CEQP’s Class A preferred units are currently being paid-in-kind (PIK) until the end of Q2 2017,
upon which time they will be required to be paid in cash
 The cash payment will be ~$58.5M in 2017, assuming PIK interest until Q2 2017
Appendix
Source: CEQP Q3 2015 10‐Q

Company Information
 CEQP SEC filings: http://www.sec.gov/cgi-bin/browse-
edgar?CIK=ceqp&owner=exclude&action=getcompany&Find=Search
 CEQP Investor Relations page: http://www.crestwoodlp.com/investors/default.aspx
Appendix

Raging Capital Management's "Crestwood Comeback" Plan

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