Crestwood Midstream Investor Presentation Highlights Growth Projects

Presentation Title
Presentation Subtitle
Crestwood Midstream Partners LP Crestwood Equity Partners LP
Connections for America’s Energy
™
™
Presentation Title
™
™
Presentation Title
™
™
6/26/2017
Presentation Title
™
™
Presentation Title
™
™
™
™
Investor Presentation
June 2017

™
™
™
™
™
™
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, assumptions
and expectations of Crestwood’s management, the matters addressed herein are subject to numerous risks and
uncertainties which could cause actual activities, performance, outcomes and results to differ materially from those
indicated. Such forward-looking statements include, but are not limited to, statements about the benefits that may result
from the merger and statements about the future financial and operating results, objectives, expectations and intentions
and other statements that are not historical facts. Factors that could result in such differences or otherwise materially affect
Crestwood’s financial condition, results of operations and cash flows include, without limitation, the possibility that
expected 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 extent
and success of drilling efforts, as well as the extent and quality of natural gas and crude oil volumes produced within
proximity of Crestwood assets; failure or delays by customers in achieving expected production in their oil and gas
projects; 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, including
suppliers, contractors, operators, processors, transporters and customers; the ability of Crestwood to consummate
acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any
acquisition; 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 and
permits, the ability of Crestwood to control the costs of construction, including costs of materials, labor and right-of-way
and other factors that may impact Crestwood’s ability to complete projects within budget and on schedule; the effects of
existing and future laws and governmental regulations, including environmental and climate change requirements; the
effects of existing and future litigation; and risks related to the substantial indebtedness, of either company, as well as
other factors disclosed in Crestwood’s filings with the U.S. Securities and Exchange Commission. You should read filings
made by Crestwood with the U.S. Securities and Exchange Commission, including Annual Reports on Form 10-K and the
most recent Quarterly Reports and Current Reports for a more extensive list of factors that could affect results. Readers
are cautioned not to place undue reliance on forward-looking statements, which reflect management’s view only as of the
date made. Crestwood does not assume any obligation to update these forward-looking statements.
Company Information
2
Forward-Looking Statements
Contact Information
Corporate Headquarters
700 Louisiana Street
Suite 2550
Houston, TX 77002
(1) Market data as of 6/20/2017.
(2) Unit count and balance sheet data as of 3/31/2017.
Crestwood Equity Partners LP
NYSE Ticker CEQP
Market Capitalization ($MM)(1,2) $1,417
Enterprise Value ($MM)(2) $3,654
Annualized Distribution $2.40
Investor Relations
investorrelations@crestwoodlp.com
(713) 380-3081
No IDRs
Corporate Structure

™
™
™
™
™
™
Key Investor Highlights
3
• Conservative 2017E guidance
• Focused growth strategy
• Low-cost partnership
• Strong balance sheet
• Strong distribution coverage
• Significant insider ownership
$360MM - $390MM
2017 Adjusted EBITDA
Long-term
Leverage Ratio < 4.0x
1.2x-1.3x Long-term
Coverage Ratio
No GP IDRs; OPEX and G&A
down 15% 2015/16(2)
~32% LP units; alignment of
interest with LP’s
Bakken, Delaware-Permian,
Marcellus
(1) FY 2016 O&M and G&A net of unit based compensation and other
significant costs, compared to FY 2015.

™
™
™
™
™
™ 4
Repositioned for Distribution Growth
Stabilized portfolio for 2017; increasing inventory of high quality
growth projects drive EBITDA/DCF in 2018+
• Execution of 2017-18 strategy positions Crestwood for resumption of
distribution growth in 2H 2018 while meeting conservative leverage and
coverage targets
• Accretive capital investments expanding Crestwood’s core operating areas in
high-quality basins where supply-demand fundamentals are strong
– Bakken, Delaware Permian and Marcellus
– Strong joint venture relationships with First Reserve and Con Edison
2016 2017 2018
• Deleveraged / de-
risked portfolio
• Captured new growth
projects in DP and
Bakken
• Formed strategic joint
ventures in LT growth
regions
• Trough cash flow from
commodity cycle
• Maintain strong
distribution coverage
• Build-out Delaware
Permian and Bakken
growth projects under
construction
• Northeast expansion
(MARC II)
• Increased Stagecoach
contribution
• Bakken Bear Den
expansions (Phase 2)
• PRB Niobrara
Development
Repositioning Execution DCF Growth
2019+
• Nautilus gathering
system
• Arrow gathering system
expansions
• Bear Den West Pipeline
& Processing Plant
• Orla Express Pipeline&
Orla Processing Plant
• Increased Stagecoach
contribution

™
™
™
™
™
™
Focused Initiatives Lead to Value Creation
5
• De-risked base portfolio; stable cash flow outlook
– Stabilized base portfolio with volume growth in 2017 across every major gathering system
– Disciplined growth strategy in the Bakken, Delaware Permian and NE Marcellus
• Improved balance sheet & access to public/private growth capital
– March 2017 bond refinancing pushes out nearest senior note maturity to 2023
– $250MM ATM fully available for funding capital projects; recently renewed CEQP WKSI shelf
– Strong financial and strategic partners in regional joint ventures
• Building impressive inventory of visible, accretive growth projects in key
basins
– Delaware Permian Nautilus initial gathering system build-out in service (early) Q2 2017
– Bakken Arrow expansions underway; Bear Den Phase I processing plant in service Q3 2017
– Delaware Permian Orla processing plant / Orla Express target in service Q3 2018
– Bakken Arrow Bear Den Phase 2 plant expansion target in-service as early as Q4 2018
1
2
3
Successful execution of key initiatives will lead to substantial value generation
for Crestwood unitholders over next 3 years

™
™
™
™
™
™
Nationwide Footprint Leveraged to Organic Growth
6
Crestwood has a diversified portfolio of assets located in the most active
domestic shale plays
• Activity has resumed across
Crestwood’s major G&P systems
in 2017
– Bakken:100-120 wells
– Delaware Permian: 80 wells
– PRB Niobrara: 20 wells
– SW Marcellus: 22 wells
– Barnett: 7 wells; workovers
• Increased activity supports
backlog of high quality growth
opportunities
− Bakken, Delaware Basin,
Marcellus and PRB Niobrara
− Strong counterparties; solid
fundamentals & contracts
• Current projects and backlog
expected to deliver DCF growth
in FY 2018

™
™
™
™
™
™
60%
20%
20%
48%
29%
23%
43%57%60%
20%
20%
48%
29%
23%
57%
Volume & EBITDA Breakdown by Commodity
7
Gas Oil NGLs
Despite Crestwood’s correlation to crude oil pricing, Crestwood’s diverse asset
portfolio is well balanced across all commodities
Volumes
by Commodity
EBITDA
by Commodity

™
™
™
™
™
™
High Quality Contract and Customer Mix
CEQP Contract Portfolio
8
8
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)
• G&P assets backed by 1.1 million acreage
dedication with average contract tenor of >10
years
– High quality producer mix with clear economic
incentive to drill on Crestwood acreage
• Top-tier NE Gas Storage & Transportation franchise
– Strategic joint venture with ConEdison also
serving as the anchor customer
– Largely investment grade counterparty mix
• Diversified NGL Marketing, Supply & Logistics
business
– Serves quality upstream customers and
diversified mix of downstream customers
– Strategically-located storage & terminal assets
2017 Forecast EBITDA
(1) Not inclusive of all Crestwood customers.
Stable Cash Flows by Segment Driven By Favorable Contract Mix and High Quality
Customer Base

™
™
™
™
™
™
Commercial Update
9
9

™
™
™
™
™
™ 10
Backlog of Announced Projects Drives Growth
Project Region Key Customer(s)
2017-2018 Capital
($MM)
In-Service
Date
Nautilus System
Delaware
Permian
Shell
$90MM/ $45MM net
to CEQP
6/2/2017
Bear Den Processing Plant - Phase 1 Bakken Arrow System Producers $115MM Q3 2017
Orla Processing Plant
Delaware
Permian
Multiple(1) $170MM / $10MM net
to CEQP2 Q3 2018
Bear Den Processing Plant - Phase 2 Bakken Arrow System Producers $105MM Q4 2018
Incremental Annual Cash Flow Impact from Capital Projects
Current projects are expected to generate over $30 million per year in incremental
cash flow in 2018 and $75 million per year by 2020
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.
$0
$10
$20
$30
$40
$50
$60
$70
$80
2017 2018 2019 2020
IncrementalAnnualCashFlow
($USMillions)
Bakken Growth Permian Growth

™
™
™
™
™
™
0
10
20
30
40
50
60
1/8/2016
2/8/2016
3/8/2016
4/8/2016
5/8/2016
6/8/2016
7/8/2016
8/8/2016
9/8/2016
10/8/2016
11/8/2016
12/8/2016
1/8/2017
2/8/2017
3/8/2017
4/8/2017
5/8/2017
6/8/2017
Strong Bakken Arrow Fundamentals
11
Bakken & Three Forks Breakevens
>1,500 estimated future drilling locations on
Arrow System
Improved recoveries, lower wells costs and exceptional returns drive increased
permitting and drilling activity for Arrow producers
Arrow
System
Sources: Wood MacKenzie used for breakeven, EUR and well
cost data. Baker Hughes rig data as of 6/16/2017.
Strong EURs and Well Costs
Bakken Rig Count Since 2016
$7MM
D&C Costs
900M
Barrels
Equivalent
5/27/2016: 22 rigs
Current: 49 rigs
+123%

™
™
™
™
™
™
Arrow Producers’ Accelerate Development
12
The Arrow system will be Crestwood’s largest driver of cash flow growth in 2017 and
2018 based on more wells drilled and bigger IP rates
Overview
Arrow Growth Potential
80 well connects per year through 2021 drives 10%-15% EBITDA growth CAGR
110
76
69
48
70
80
0
30
60
90
120
2013 2014 2015 2016 2017 2018+
Long-Term Volume ForecastHistorical and Projected Well Connects
–
25
50
75
100
2013 2014 2015 2016 2017 2018 2019 2020 2021
Oil (MBbl/d) Water (MBbl/d) Gas (MMcf/d)
Arrow Well Connections
Only 70 new wells in CEQP’s guidance;
Producers are out pacing CEQP’s budget
26
Q1 2017
40-45
Q2 2017
100-120
FY 2017
Producer EstimatesActual
• Arrow Gathering system generated ~$90MM in 2016 Adj.
EBITDA; ~$104MM of Adj. EBITDA budgeted in 2017
– Actual Mar/Apr 2017 annualized EBITDA of ~$130 MM
• Increasing system capacity in 2016-17 to accommodate producer
growth expectations over next five years
• Substantial remaining drilling inventory on acreage dedicated to the
Arrow gathering system

™
™
™
™
™
™
• ~20 miles of new natural gas lines including
the Bear Den Loop project which brings
increased gas volumes to Arrow CDP for
delivery to ONEOK processing or Bear Den
West lateral for Crestwood processing at
new plant
• Loop line increases gathering capacity,
minimizes flaring, improves margins and
net-back for producers
• Full project in-service Q2 2017
Arrow System Expansion Projects
13
Arrow system expansions nearly double capacity to support producer’s long-term
development plans and increasing well performance; ~$55 MM 2016-17 capital
projects to improve oil, gas and water services on Arrow
DAPL and Oasis Connection Natural Gas Line Expansion Water Handling Expansion
• ~35 miles of new water lines
• Install new pipe and pump station to
upgrade system and bring additional
water volumes into Arrow System
• New salt water disposal well
• Full project in-service Q3/Q4 2017
• DAPL Connection is ~5 miles of 16"
crude pipeline from the Arrow CDP into
DAPL's Johnson Corner Facility
• DAPL connection lifts producers
netback and enhances market liquidity
options
• Oasis Petroleum gathering system
connection at Johnson Corners
• Projects currently in-service

™
™
™
™
™
™ 14
 Greatly enhances Flow
Assurance and “control of
our own destiny” to drive
volume growth on the
Arrow System
Arrow Bear Den Processing Plant
Crestwood commenced construction of Phase 1 processing plant to support Arrow
volumes; Expected in-service Q4 2017; Phase 2 likely in 2018 as volumes ramp up
Arrow Processing Project Rationale
Project Overview
• Bear Den Processing Plant (Phase 1) is a 30 MMcf/d
RJT unit in Watford City, ND; Connects to Arrow gas
gathering system via a new 25 mile pipeline from new
Bear Den Loop system expansion
• Plant will connect to Northern Border’s & WBI’s
residue natural gas pipelines, ONEOK’s NGL pipeline
and COLT Hub’s rail loading via Crestwood’s trucking
fleet
• Phase 1 project expected to cost ~$115 MM and be in-
service by Q3 2017; Phase 2 project scoping currently
underway with projected in-service as early as Q4
2018
• Crestwood purchases all oil and gas at the wellhead
from its producers; full control of processing volumes
• Attractive total project returns; Phase 1 project
accretive to DCF in 2018
Bear Den Plant Map
WBI Residue
New CEQP
Bear Den
West Line
 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 its integrated
midstream value chain
with incremental volumes
(MSL, Colt, Trucking)

™
™
™
™
™
™ 15
• Primarily a crude-by-rail facility servicing West
and East Coast refiners
• Long-term (3-5 year) take-or-pay contracts
• Typically one fixed price for all hub services
Colt Hub Completes Transition to Terminalling Facility
Spot volumes increase at COLT HUB under new strategy; DAPL connection attracts new
customers sourcing barrels for premium net-backs out of the basin
Crestwood De-bundles Service Offerings –-> Grows Daily Spot Business
(1) Cash flow at the COLT Hub is not linear and will fluctuate and be impacted in
part by daily supply and demand fundamentals for crude oil.
(2) Sample prices as of 6/15/2017 and subject to change on a daily basis.
• Bakken terminalling hub servicing coastal
refiners, marketers, E&P companies
• Reduced take-or-pay contracts; increased daily
spot business
• De-bundled services for customer needs
___________Pre-FY 2017_________ ____________FY 2017+__________
Sample: $1.50/bbl for all services
$0.50-$0.65/bbl $0.50/bbl $0.25/bbl $0.15/bbl
Sample: Customized service by customer(2)
COLT Hub Overview
• COLT Hub completes transition from primarily a rail loading
facility to full-service crude oil terminal and adds DAPL
connection
• Buyers and sellers utilize storage for aggregation, operational
requirements, market liquidity and optionality and contango
markets
• CBR expected to compete for barrels out of the basin as rail
transloading operators and railroads lower pricing to compete
with pipeline competition
• 2017E Adj. EBITDA of $30MM; Q1’17 Adj. EBITDA of
$9.5MM(1)
DAPL’s Impact at the COLT Hub
• The DAPL pipeline went into service June 1, 2017
− Currently 16,000 Bbls/d flow through COLT into DAPL
− As budgeted, rail loading volumes lower and WTI/Bakken
basis spreads have tightened
• Crestwood is repurposing COLT to generate incremental
opportunities
− Retrofitting facility to handle NGL loading

™
™
™
™
™
™
0
50
100
150
200
250
300
350
400
1/8/2016
2/8/2016
3/8/2016
4/8/2016
5/8/2016
6/8/2016
7/8/2016
8/8/2016
9/8/2016
10/8/2016
11/8/2016
12/8/2016
1/8/2017
2/8/2017
3/8/2017
4/8/2017
5/8/2017
6/8/2017
Strong Delaware Permian Economics
16
Delaware Permian Wolfcamp Breakevens
Delaware Permian breakeven economics lead US onshore opportunity set and are
highly economic in today’s commodity price environment
Strong EURs and Well Costs
Permian Rig Count Since 2016
<$7MM
D&C Costs
900M
Barrels
Equivalent
Sources: Wood MacKenzie used for breakeven, EUR and well
cost data. Baker Hughes rig data as of 6/16/2017.
4/29/2016: 134 rigs
Current: 368 rigs
+175%

™
™
™
™
™
™
Building Competitive Scale in Delaware Permian
17
Asset MapAsset Overview & Strategy
Crestwood is expanding its footprint in the heart of the Delaware Basin, the most
active shale play in the US
• Current Assets includes Willow Lake
gathering & processing (100% owned) and
Nautilus gathering & compression (50% JV
owned)
1. Northern Delaware - 85 MMcf/d (1)
gathering and processing capacity with
existing contracts with Concho,
Mewbourne, Matador, Cimarex,
Marathon and ExxonMobil
2. Southern Delaware - ~250 MMcf/d
natural gas gathering system for Shell
(SWEPI)
• Growth Strategy includes Orla Express
Pipeline (20”) and Orla Processing plant (200
MMcf/d) to connect the systems
– Covers >2 million acres and the 5 most
active counties in core Delaware Permian
Basin
>$100 million of total Delaware Basin EBITDA potential by 2021 from identified
expansion opportunities
(1) Expanding Willow Lake plant to 85 MMcf/d in Q3 2017

™
™
™
™
™
™
Willow Lake Gathering and Processing System
18
Willow Lake gathering system and processing plant is at the center of significant
development and M&A activity in the Northern Delaware-Permian (50 rigs operating)
Crestwood Delaware Basin Area MapWillow Lake System
• Willow Lake Gathering and Processing System is at the
epicenter of Northern Delaware Permian development in Eddy
and Lea counties, NM
– ~82 miles low pressure gathering system: current
processing capacity (55 MMcf/d) is full
– Additional 30 MMcf/d RJT skid being installed to handle
expected volumes in 2Q17-2Q18
• Existing acreage/well dedications with Concho and Mewbourne
supported by 100,000 acre AMI around plant/system
• Recent M&A activity near/on Willow Lake system includes XTO
(Exxon) purchase of Bass for ~$6 BB; Marathon purchase of
BG Energy for ~$2 BB; existing contracts with both entities;
working on development plans and infrastructure needs
0
10
20
30
40
50
Q1:16 Q1:17
MMcf/d
Processing Gathering
+44% gathering volumes
+65% processing volumes
Willow Lake Volume Growth

™
™
™
™
™
™
Shell Nautilus Gas Gathering System
19
Greenfield natural gas gathering system to support Shell’s development activity in
Loving and Ward counties, TX
Proposed System MapOverview
• Shell (SWEPI) Nautilus Gas Gathering System
– In-service date of June 2, 2017
– 20 year gathering and compression contract
– 194 miles of low pressure gathering lines; 36 miles of high
pressure trunklines; initially designed to gather 250 MMcf/d
– 4 compressor stations, w/ dehydration, and liquids handling
services; 196 Receipt Points
– Processing Plant connections with Bone Springs (direct),
Ramsey (via Avalon Express), and Orla (via Orla Express)
• 100,000 acreage dedication in Loving and Ward counties, TX
– Currently ~5 rigs SWEPI running in area
• Tiered fixed-fee contract structure for gathering and compression
• Capex ~$90MM in 2017 ($45MM net to CEQP)
Event Status
Signed Agreement w/ Shell COMPLETED
Project Development COMPLETED
Construction COMPLETED
In-Service Date COMPLETED

™
™
™
™
™
™
Orla Express Pipeline & Orla Processing Plant
20
Crestwood is building a super-header and 200 MMcf/d processing plant connecting
Willow Lake and Nautilus gathering systems; positioned to compete across the entire
primary Delaware Permian catchment area (161 Hz rigs operating)
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
– Planned expansions to 600 MMcf/d of
capacity
– Multiple takeaway options include
residue interconnects with EPNG and
ETP, and NGL interconnects with Targa
& EPD
• Initial phase connects Willow Lake
gathering to Orla Express and Orla plant
to handle projected volumes from
northern Delaware Permian
– Base scope capital of ~$170 million
– Targeted in-service date Q2 2018
• Expansion phase will connect the Nautilus
system to Orla plant and new laterals
connecting additional producers
– Expansion scope capital of $70 million
– Targeted in-service date 2H 2018 and
early 2019
Orla Plant: 200
MMcf/d cryogenic
gas processing
plant
Orla Express Pipeline
connecting existing
Willow Lake system to
new Orla gas
processing plant

™
™
™
™
™
™
Expanding First Reserve Delaware Permian JV
FR provides up-front capital on Orla Plant & Orla Express Capital
21
Financing Terms for Orla Expansion Joint Venture Structure
• Crestwood contributed the Willow Lake assets to the FR
Permian JV at a value of $151 million (“Contribution
Value”)
– Implies a transaction multiple of ~14x based on
LTM EBITDA
– Transaction approved by CEQP conflicts committee
• FR will be obligated to fund 100% all capital
requirements equal to the Contribution Value
– Initial Orla expansion project scope of ~$170 MM
– Any capital requirements thereafter will be funded
50/50
• Crestwood continues to receive 100% of all Available
Cash generated by the contributed entity until earlier
of Orla plant in-service date or June 30, 2018
• AMI for FR DBJV expanded to include Eddy and Lea
Counties, NM (currently Culberson, Reeves, Loving and
Ward Counties, TX)
Crestwood
Midstream
Partners LP
Crestwood
Infrastructure
Holdings LLC
100%
50%Crestwood
Permian Basin
Holdings LLC(2)
Crestwood
Permian Basin
LLC(3)
Crestwood
New Mexico
Pipeline LLC(1)
PF Permian JV Asset Summary
Willow Lake
Assets
Nautilus
Assets
FR XIII
Crestwood
Permian Basin
Holdings LLC50%
All Permian assets now included in Permian JV with First Reserve; Willow Lake
contribution allows Crestwood to organically grow Permian footprint without
accessing the capital markets
300+
MMcf/d
Gathering Capacity
on Willow Lake and
Nautilus systems
285
MMcf/d
Processing
Capacity
360
Miles
Gathering and
header lines

™
™
™
™
™
™
23%
49%
28%
79%
13%
9%
NE Marcellus Stagecoach Gas Services JV
22
Assets MapStagecoach Overview
Stagecoach Storage
Customers
Producers
Marketers
Marketers
Utility / LDCs
Producers
Stagecoach Transportation
Customers
Utility/ LDCs
• Strategic 50/50 joint venture 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
− Firm 3-6 year contracts on pipeline and storage assets
• Stagecoach generated Approximately $145 million Adjusted
EBITDA in 2016

™
™
™
™
™
™
Increasing NE Marcellus Gas Supply Picture
23
• PV-10 positive breakeven pricing approximately $2/Mcf(1)
• Long haul pipeline project cancellations have created
bottleneck issues to get natural gas out of the basin
• Producers will send incremental volumes through
Stagecoach assets to get to Millennium, Transco and
Tennessee pipelines
• Stagecoach is a leading pipeline hub that provides
producers optionality to get out of the basin
Current natural gas prices have encouraged northeast Marcellus producers to
resume capital programs in the basin that will drive natural gas production growth
Growing Volumes Benefit StagecoachNE Producers Increasing Capital Budgets
…Which Leads to Higher Production Forecasts
-
500
1,000
1,500
2,000
2,500
Chesapeake SWN Cabot EQT Gulfport Range Rice
CapitalExpenditures($USMM)
2016 2017Combined 68% Increase in
Y-o-Y Capital Expenditures
0
100
200
300
400
500
600
700
Chesapeake SWN Cabot EQT Gulfport Range Rice
DailyProduction(MMcf)
2016 2017Combined ~10% Increase in
Y-o-Y Natural Gas Production
(1) Chesapeake Energy investor presentation.
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
2,000,000
TransportationVolumes(Mcf/d)
Transco Millennium Tennessee Stagecoach Storage UGI Sunbury
>35% Increase in Stagecoach Transportation Volumes

™
™
™
™
™
™ 24
Improving NE Gas Market; Regulatory Environment
• Improving Market Demand:
− 9.2 GW of new gas-fired power gen
within 60 miles of Stagecoach assets
− ~1.1 GW of coal plant retirements of in
2017
• Regulatory Environment Progressing:
Atlantic Sunrise, Rover, Northern Access,
Leach Xpress and Orion Expansion receive
conditional approvals
Proposed MARC II Project
Current Opportunities
Strong Regional Fundamentals
• MARC II: Currently conducting joint
discussions with customers; PennEast
received EIS approval
• Incremental services to direct regional
demand markets
The Northeast region is the largest US gas supply base and the best potential for long-
term demand growth
MARC I
North/South
Steuben
Thomas Corners
Seneca Lake
Crestwood
East Pipeline
Stagecoach
Total New Market
Demand for
Northeast Gas of
2.2 – 2.4 Bcfd by
2019
= Stagecoach Storage and Interconnects
PA
NY
CON EDISON
SERVICE
AREA

™
™
™
™
™
™
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
250
275
300
325
350
375
Q2:15 Q3:15 Q4:15 Q1:16 Q2:16 Q3:16 Q4:16 Q1:17
GatheringVolumes(MMcf/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 Gathering & Processing Update
25
BlueStone’s workover activities and recent DUC completions drive system volume
growth in 2017; 2017E Adj. EBITDA ~$60 million
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
System
wide
shut-ins
April 15th:
BlueStone
Agreement
(1) Source: EIA Henry Hub Natural Gas Spot Price.

™
™
™
™
™
™
• 20-year, fixed-fee gathering and compression
services w/ Antero Resources
• 140,000 acreage dedication
• System capacity of 875 MMcf/d; currently
<50% utilized
• 100 MMcf/d compression services on AM
gathering in Western Area (90% utilized)
• Current cash flow reflects actual throughput,
no MVC payments expected through 2018 (no
cash flow cliff)
• Four DUCs were brought online Q1 2017; Nine
additional DUCs expected in Q2 2017
SW Marcellus Gathering & Compression Update
26
Gathering volumes expected to average 400 MMcf/d in 2017 as producer begins
completing DUC Inventory; 2017E Adj. EBITDA ~$60 million
Asset Overview
Crestwood SW Marcellus System Supports Exceptional Resource Acreage
• Over 250 wells have been connected to Crestwood’s system – No dry holes
• Avg. 30-day IP rate of ~8.0 MMcf/d; Avg. EURs between 8.0 – 12.0 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
Asset Map
East AOD
Western Area
Arsenal
Resources
EQT
Noble Energy
EQT SWN
Area
Operators
(1) Source: Wood Mackenzie.

™
™
™
™
™
™
Chesapeake Actively Drilling in PRB Niobrara
27
CHK PRB Net Production Potential
Source: Chesapeake Energy Company Presentations.
• PRB Jackalope JV - Crestwood (50%) Williams (50%)
owns 180 MMcf/d gas gathering system and 120 MMcf/d
processing plant in Converse Co., Wyoming
• PRBJV entered into new 20-year fixed fee contract with
Chesapeake in Jan. 2017
− Eliminated old “cost of service” model
− Adjusted G&P fees to incentivize CHK accelerated
development
− Includes minimum revenue guarantees for 5 – 7
years ensuring return of capital on prior capex
• 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 at 2,560 Boe/d with 78% oil cut
• Recent Niobrara DUC’s brought on at 1,720 Boe/d with
~50% 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; 2017E Adjusted EBITDA ~$25 MM
388K
Dedicated Acres
2,600
Remaining Drilling
Locations
Chesapeake is currently running 2 rigs on the Jackalope system and
one dedicated frac crew; expect to go to 3 rigs in late 2017 or early 2018

™
™
™
™
™
™
NGL Marketing benefits from NE NGL growth
28
Crestwood’s is a leading marketer for Marcellus/Utica producers, processors and
fractionation through truck, rail, storage and terminal assets; ME2 pipeline capacity
adds export ability to local/regional sales; 2017E Adj. EBITDA ~$60 MM(1)
Customers
Crestwood’s Assets
Macro-Drivers That Create Opportunity for Margin
Crestwood sources product two ways:
1) Upstream producers, processors and
fractionators
2) Downstream refiners, retailers, petrochem
Seasonal Spreads/Inventory CycleHeating Degree Days (“HDDs”)
Domestic NGL Supply Growth
• Significant NGL storage and terminal assets:
- 2.8 MMBbl of storage capacity (primarily
Marcellus/Utica)
- 10 trucking and rail terminals
• Significant NGL transportation fleet:
- +500 NGL truck/trailer units
- +2,100 NGL railcars
• Pipeline capacity to domestic and international
markets, including waterborne exports (TEPPCO,
Dixie, Mariner East 2)
PADD 1 Supply/Demand Outlook
• Propane supplies est +42% to 313
MMb/d by 2019
• NE demand flat at ~170-175
MMb/d through 2019
• Exports est + 373% to 175 MMb/d
by 2019
• Crestwood well positioned to
maintain traditional NE local market
sales while participating in margin
upside through exports
(1) Annual Adj. EBITDA excludes US Salt contribution of approximately $25MM/year.

™
™
™
™
™
™
Financial Review
29
29

™
™
™
™
™
™
2017 Outlook
30
Marketing, Supply & Logistics
• Adjusted EBITDA:
$80MM - $90MM
• EBITDA growth from recent
capital investment on new
terminals, West Coast
expansion and US Salt
Crestwood has a bright 2017 outlook as customers increase development activity
and new projects come into service in 2H 2017
Segment Outlook
Storage & Transportation
$80MM - $90MM
• Full-year of 35% Con Edison JV
cash flow distribution of 35%(2)
• COLT Hub 2017E EBITDA of
$30MM
Gathering & Processing
$265MM - $275MM
• New development activity
across Arrow, PRB Niobrara,
SW Marcellus and Permian
systems
Adjusted EBITDA
Distributable Cash Flow
Distribution Coverage Ratio
2017E Leverage Ratio
Growth Capital
Maintenance Capital
1.2x – 1.4x
4.0x – 4.5x
$225 million – $250 million
$20 million – $25 million
$360 million – $390 million(1)
$200 million – $230 million(1)
(1) Please see accompanying tables of non-GAAP reconciliations.
(2) In June 2018, Crestwood’s Stagecoach JV cash flow distribution increases
from 35% to 40% through June 2019, then increasing to 50%.

™
™
™
™
™
™
Strong Balance Sheet & Liquidity
31
• Top-tier leverage position
– Q1 2017 leverage of 3.9x
– 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
RCF
Preferred Equity Overview
• Crestwood has ~$636MM preferred equity outstanding
• Annual distribution of 9.25% payable quarterly
• Preferred equity holders have option to convert 1-for-
10 after Q2 2017 (6.8MM 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
Actuals Actuals Actuals
($ millions) 2015 2016 Q1 2017
Cash $1 $2 $1
Revolver $735 $77 $382
Senior Notes 1,800 1,475 1,214
Other Debt 9 6 5
Total Debt $2,544 $1,558 $1,601
Total Leverage Ratio 4.75x 3.74x 3.92x
Issue Price Yield
2023 102.50 5.5%
2025 101.50 5.5%

™
™
™
™
™
™
$0
$100
$200
$300
2017 DCF 2018 Portfolio CF Incremental Preferred 2018 DCF 2018 Distributions
LP
Distributions
@
$2.40 / unit
Excess
Coverage
Excess Coverage allows Distribution Growth in 2018
32
$0.60Quarterly Distribution
per unit
$2.40Annual Distribution
per unit
Strong distribution coverage in 2017 allows Crestwood to reallocate internally
generated cash flow for further deleveraging and future expansion opportunities
11.9%Current Distribution
Yield
(1) Mid-point of DCF guidance. Distribution yield as of 6/20/2017.
Current Distribution
($ MM)
• Arrow expansions
• Nautilus full year in-service
• Willow Lake projects
• PRB Niobrara activity
• Interest expense savings
• Stagecoach growth and cash flow
sharing step-up
DCF growth positions Crestwood to build excess
coverage after preferred equity cash distributions
2017 DCF (1) 2018 Portfolio
CF Growth
Incremental
Preferred Cash
Distributions
2018 DCF 2018
Distributions
Distribution Strategy: Maintain targeted coverage ratio of
1.2X – 1.3X with possibility of distribution increase in the 2H 2018;
Factors to consider: excess coverage, investment opportunities,
leverage ratio, cost of capital

™
™
™
™
™
™
The Crestwood Investment Opportunity
33
Focused on aggressively executing growth opportunities while maintaining
financial strength
• Near-term gathering and processing growth opportunities in the Bakken and
Delaware-Permian with FINANCING SOLUTION IN PLACE!
• Long-term northeast pipeline projects around existing assets with Con Edison
In the meantime…
• Crestwood is well-positioned to deliver attractive yield to investors(1)
– Current Yield = 11.9%; Coverage Ratio = 1.4x; Leverage Ratio = 3.9x
• 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 6/20/2017. Coverage ratio and leverage ratio as of 3/31/2017.

™
™
™
™
™
™
Appendix
34
34

™
™
™
™
™
™
CEQP Non-GAAP Reconciliations
35
(in millions, unaudited) 2016
Full-Year
EBITDA
Net income (loss) (192.1)$
Interest and debt expense, net 125.1
Loss on modification/extinguishment of debt (10.0)
Provision (benefit) for income taxes 0.3
Depreciation, amortization and accretion 229.6
EBITDA (a)
152.9$
Significant items impacting EBITDA:
Unit-based compensation charges 19.2
(Gain) loss on long-lived assets, net 65.6
Goodwill impairment 162.6
(Earnings) loss from unconsolidated affiliates, net (31.5)
Adjusted EBITDA from unconsolidated affiliates, net 61.1
Change in fair value of commodity inventory-related derivative contracts
14.1
Significant transaction and environmental related costs and other items
11.6
Adjusted EBITDA (a)
455.6$
Distributable Cash Flow
Adjusted EBITDA (a)
455.6
Cash interest expense (b)
(117.7)
Maintenance capital expenditures (c)
(13.3)
(Provision) benefit for income taxes (0.3)
Deficiency payments (7.2)
Distributable cash flow attributable to CEQP 317.1$
Distirbutions to Niobrara Preferred (15.2)
Distributable cash flow attributable to CEQP common (d)
301.9$
CRESTWOOD EQUITY PARTNERS LP
Reconciliation of Non-GAAP Financial Measures
(a) EBITDA is defined as income before income taxes, plus debt-related costs (net interest and debt expense and gain or loss on modification/extinguishment of debt) and depreciation, amortization and
accretion expense. Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates to reflect our
proportionate share (based on the distribution percentage) of their EBITDA, excluding impairments. Adjusted EBITDA also considers the impact of certain significant items, such as unit-based
compensation charges, gains and losses on long-lived assets, impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to
potential and completed acquisitions, certain environmental remediation costs, certain costs related to our historical cost savings initiatives, the change in fair value of commodity inventory-related
derivative contracts, and other transactions identified in a specific reporting period. The change in fair value of commodity inventory-related derivative contracts is considered in determining Adjusted
EBITDA given that the timing of recognizing gains and losses on these derivative contracts differs from the recognition of revenue for the related underlying sale of inventory that these derivatives relate to.
Changes in the fair value of other derivative contracts is not considered in determining Adjusted EBITDA given the relatively short-term nature of those derivative contracts. EBITDA and Adjusted EBITDA
are not measures calculated in accordance with GAAP, as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to
maintain our business. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance
with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.
(b) Cash interest expense less amortization of deferred financing costs plus bond premium amortization.
(c) M aintenance capital expenditures are defined as those capital expenditures which do not increase operating capacity or revenues from existing levels.
(d) Distributable cash flow is defined as Adjusted EBITDA, less cash interest expense, maintenance capital expenditures, income taxes and 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 GAAP 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.

™
™
™
™
™
™
CEQP Non-GAAP Reconciliations
36
Expected 2017 Range
Low - High
Net income
Interest and debt expense, net
Depreciation, amortization and accretion
Unit-based compensation charges
Earnings from unconsolidated affiliates
Adjusted EBITDA from unconsolidated affiliates
Adjusted EBITDA
Cash interest expense(a)
Maintenance capital expenditures(b)
Cash distribution to preferred unitholders(c)
Distributable cash flow attributable to CEQP(d)
(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), and public Crestwood M idstream LP unitholders interest in CM LP distributable cash flow.
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.
$0 - $30
CRESTWOOD EQUITY PARTNERS LP
Full-Year 2017 Adjusted EBITDA and Distributable Cash Flow Guidance
Reconciliation to Net Income
(in millions, unaudited)
(a) Cash interest expense less amortization of deferred financing costs plus bond premium amortization plus or minus fair value adjustment of interest
rate swaps.
(b) M aintenance 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 Class A preferred unit holders.
25
195
110
(50) - (55)
80 - 85
$360 - $390
$200 - $230
(30)
(105)
(20) - (25)

Crestwood Midstream Investor Presentation Highlights Growth Projects

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Similar to Crestwood Midstream Investor Presentation Highlights Growth Projects

Similar to Crestwood Midstream Investor Presentation Highlights Growth Projects (20)

Recently uploaded

Recently uploaded (20)

Crestwood Midstream Investor Presentation Highlights Growth Projects