Investor presentation march 2016

Presentation Title
Presentation Subtitle
Crestwood Midstream Partners LP Crestwood Equity Partners LP
Connections for America’s Energy
™
™
Presentation Title
™
™
Presentation Title
™
™
2/29/2016
Presentation Title
™
™
Presentation Title
™
™
™
™
Investor Presentation
March 2016

™
™
™
™
™
™
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 price as of 2/24/2016.
(2) Unit count and balance sheet data as of 12/31/2015.
Crestwood Equity Partners LP
NYSE Ticker CEQP
Market Capitalization ($MM)(1,2) $617
Enterprise Value ($MM)(2) $3,724
Annualized Distribution $5.50
Investor Relations
investorrelations@crestwoodlp.com
(713) 380-3081

™
™
™
™
™
™
Key Investor Highlights
3

™
™
™
™
™
™
• Solid execution in 2015 drives results; Adj. EBITDA increased 6%; OPEX and
G&A expenses reduced 9%; LTM coverage ratio ~1.0x
• Stable cash flow generation in 2016; ~60% of asset base flat to up 5%
• Strong liquidity position; No senior note maturities until 2020
• Diverse and balanced operations located in the most economic US shale plays
• Strong take-or-pay and fixed-fee contract portfolio; 92% take-or-pay and
fixed fee in 2016
• No Incentive Distribution Rights
• Strong sponsorship from First Reserve; $90MM units purchased Q415/Q116;
Currently owns 23% common units
Key Investor Highlights
4

™
™
™
™
™
™
2016 Outlook
5
Marketing, Supply & Logistics
• Adjusted EBITDA:
$95MM - $100MM
• Flat cash flows in 2016
• Marketing business supported
by hard assets and long-term
relationships
2016E Adjusted EBITDA of $490 million to $520 million; ~60% of the business flat
to up in 2016
2016E Segment Cash Flow Reduced CAPEX
Gathering &
Processing
43%
Storage &
Transportation
40%
Marketing
Supply &
Logistics
17%
2016E Adj. EBITDA Guidance
$490MM - $520MM
Segment Outlook
Storage & Transportation
$225MM - $235MM
• Volumes trending flat to up 5% in
2016
• NE S&T and COLT Hub take-or-
pay contracts drive stable cash
flow
Gathering & Processing
$235MM - $250MM
• Volumes trending 15%-20%
lower in 2016
• 2016E cash flow forecasts
include conservative forecasts
for Barnett and PRB Niobrara
assets
(1) Excludes corporate G&A expenses of $65 million.
Segment Contribution
(1) (1)
($MM) ($MM)

™
™
™
™
™
™
Repositioning Crestwood in 2015/16
6
Corporate Structure
69.1 MM common units
62.1 MM preferred units
In a challenging market, Crestwood continues to take actionable steps to improve its
positioning and broaden its investment appeal
No IDRs
Key Items
• In 2015, reduced O&M and G&A expenses by
$26MM year-over-year through Project Adapt
initiatives
• Limiting growth capital expenditures to previously
committed contractual projects
Simplification
Merger
Cost Cutting /
Reduced Capex
• In 1Q 2015, completed Project Adapt to cut costs
and improve processes and efficiencies
• In 2Q 2015, restructured operations to Pipeline
Services and Marketing, Supply & Logistics divisions
• On September 30, 2015, closed merger between
Crestwood Equity and Crestwood Midstream
• Improved cost of capital by eliminating IDRs
Deleverage
Strategy
• In 2016, Crestwood is pursuing strategic steps to
strengthen the balance sheet in lower-for-longer
environment
• Evaluating full range of options, including further
CAPEX and cost reductions, divesting of assets, and
evaluating appropriate distribution level
Streamlined
Business

™
™
™
™
™
™
Existing Scale and New Investment Opportunities
in the Right Places
7
Bakken
• Over 75% of cash flow is
sourced from two premier
basins: Marcellus and
Bakken
• Marcellus and Bakken cash
flow trading multiples
illustrate valuation
disconnect
• Delaware-Permian expansion
projects provide opportunity
to build third franchise
position
• Scale and diversity of
remaining cash flows are
competitively positioned
across multiple resource
plays
Crestwood’s crude oil and natural gas operations are situated in the highest
returning shale plays
Marcellus

™
™
™
™
™
™
Fixed-Fee Contracts Provide Safety Net
8
Contract Portfolio 2016E EBITDA
Variable
Rate Contracts
8%
Take-or-Pay and
Fixed-Fee
Contracts
92%
 92% of 2016E EBITDA from take-or-pay and fixed-fee contracts
 Significant cash flow contribution protected from commodity change and volume reduction
55% of EBITDA is
guaranteed through take-
or-pay contracts
YoY Margin Growth Despite Commodity Prices
Adjusted EBITDA
Crude Oil and Natural Gas Prices
Crude Oil
Natural Gas
Y-o-Y Adj. EBITDA
Growth: 6.4%
Crude Oil decline: (61%)
Natural Gas decline: (45%)

™
™
™
™
™
™
$299
$253
$100
$150
$200
$250
$300
$350
4Q14 Annualized FY 2015
Expense / Fixed Charge Reduction Strategy
9
($MM)
Total Expenses Total Expenses by Segment
Crestwood exceeded stated cost reduction goals in 2015; On-track to remove an
additional $10MM in 2016
• In 2015, Crestwood materially reduced expenses and fixed charges to improve margins and coverage:
– Reduced O&M and Adj. G&A(1) costs by $26.4 million in 2015 over 2014
– Additional 2016 cost savings of >$10MM; 2016+ run-rate savings of >$35MM
• Results drive greater profitability in the current industry environment
• Increased efficiency without sacrificing customer service, safety or compliance
• Simplification adds to coverage improvement through fixed charge elimination
(1) Adjusted G&A is defined as general and administrative expenses less unit-based compensation
charges and significant transaction and environmental related costs and other items.
(1)
4Q14
Annualized FY 2015
($MM)
Total
Expenses
Total
Expenses Variance
Gathering & Processing $109 $89 ($20)
Storage & Transportation $27 $32 $5
Marketing, Supply & Logistics $79 $70 ($9)
Adjusted G&A $84 $63 ($21)
Total Expenses $299 $253 ($46)
%-Change (15.4%)

™
™
™
™
™
™
Consistent Operating and Financial Results
10
(1) See accompanying tables of non-GAAP reconciliations.
(2) Cash flow margin is calculated by dividing Adj. EBITDA into Net Revenue.
(3) Cash flow margin adjusted for Q4 2015 shut-in and weather impacts.
Adjusted EBITDA and Margins(1)
Natural Gas Volumes
Improving financial performance demonstrates strong baseline cash flow; Q4 2015
strongly impacted by warm weather
(2)
Crude Oil Volumes
$18.0
Q415 miss of
$18mm
attributable to
unseasonably
warm
weather;
depressed NE
regional
pricing
(3)
$118.5

™
™
™
™
™
™
Capital Structure
11
Capitalization
• Strong liquidity position
– 1.5 billion revolving credit facility
– ~50% drawn RCF balance
• No near-term maturities;
attractive long-term capital
– $1.8 billion senior notes; 6.00%-6.25% coupon
– Nearest maturity 2020
• Ample covenant cushion
• Strong fixed charge coverage
• No need to access capital markets
in 2016
Crestwood has ample liquidity to execute business plan in challenging market
Debt Maturities
No near-term
debt maturities
RCF
6%
Notes
6.125%
Notes
6.25%
Notes
($ millions) 12/31/2015
Cash $0.5
Total Debt $2,540.3
Total Partners' Capital $2,946.9
Total Capitalization $5,487.2
Credit & Liquidity Stats
Total Leverage Ratio 4.75x
Senior Secured Leverage Ratio 1.37x
Total Leverage Covenant 5.50x
Senior Secured Leverage Covenant 3.75x
Summary
($MM)

™
™
™
™
™
™
• Diverse customer base is comprised of integrated
producers, refiners, utilities, and petrochemical
companies
• The majority of customers well-positioned to
navigate a lower-for-longer environment
• Crestwood is actively monitoring at-risk
counterparties to mitigate cash flow risk in 2016
• Highly confident in contractual positioning to
mitigate cash flow loss from potential bankruptcies
Quicksilver Resources
• Filed for bankruptcy March 2015; Began sales
process in Q4 2015
• BlueStone Natural Resources emerged as winning
bidder; Must close by March 2016
• Binding agreement in place with the back up bidder
• Long-term resolution likely by Q2 2016
Manageable Counterparty Risk
12
Crestwood has a diverse customer portfolio; producer counterparty risk manageable
in the event of continued market deterioration
2016E Cash Flow ExposureCounterparty Risk Overview
Manageable
counterparty
risk in 2016
(1)
(1) Represents total annual cash flow contributions from higher risk counterparties.

™
™
™
™
™
™
Core Operations Update
13

™
™
™
™
™
™
• Bakken has continued to produce
sufficient producer wellhead returns
– 94% of rigs operating in four counties
(McKenzie, Williams, Mountrail, Dunn)
– ~340 permits have been filed in those four
counties in last 120 days
– Estimated breakeven WTI pricing of $24-
$41/bbl in these four core counties
– Producers improved IP rates, realized cost
reductions, and minimized cost to market
– Reducing days to drill to 10-12 days
• Crestwood producers continue to
achieve strong results:
– In the last 120 days, Arrow producers have
filed approximately 100 permits in the
Bakken
– Halcon expects 2016 wells put online to
have an EUR of ~900 Mboe; average D&C
of $6.2MM
– Whiting reported 24-hr IP rate of 4,300
Boe/d on Crestwood’s system
Bakken Producers Remain Active Around
Crestwood’s Assets
14
Permits Filed in Last 120 Days
Permits Heat Map
By Arrow Producers
9
2
38
48
Source: North Dakota Industrial Commission
As of February 24, 2016.

™
™
™
™
™
™
0
25
50
75
100
125
Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15
GatheringVolumes(Mboe/d)
Crude Oil Natural Gas Water
$0
$5
$10
$15
$20
$25
Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15
AdjustedEBITDA($MM)
Bakken Arrow Gathering System
15
Tier 1 acreage dedication with substantial long-term growth through system build out
Summary
• ~150,000 acre dedication under LT contracts
• Crude, natural gas and water gathering
• Producers continuing active development through aid-
in-construction lateral requests
• Lower operating cost in 2015 improves margin
• Arrow volumes have increased 14% year-over-year and
76% since Q1 2014
• Arrow system connected to COLT Hub through Tesoro
and Hiland crude oil pipelines
Long-Term Outlook
• >1,200 estimated future drilling locations
• 45-55 new well connects expected in 2016
– XTO, WPX and QEP approximately 90% of 2016
development activity
• Achieved record crude volume of 80 MBbls/d in October
2015
(1) Natural gas converted to barrels at 6:1.
Arrow Adjusted EBITDA
Increasing Gathering Volumes from Continued
Drilling Activity
(1)

™
™
™
™
™
™
Bakken COLT Hub and Connector
16
COLT Hub is the leading Bakken CBR facility linking Bakken crude supply to prime
refinery markets
Source: Genscape February 2016; EIA.
Summary
• Premier crude oil pipeline, storage and CBR facility in
the Bakken
• 160 MBbls/d crude-by-rail facility; 1.2 MMBbls storage
capacity; 70 MBbls/d COLT connector pipeline
• ~300 MBbls/d supply aggregation capacity at COLT
Hub (gathering, truck rack, pipelines)
• Strong refiner customers dependent on the Bakken
barrel and crude-by-rail transportation
Top 5 Bakken CBR Facilities
COLT Hub
Customers
Maintaining Market Share Going into 2016
BakkenPipeline/Crude-by-Rail(Bbls/d)
• Pipeline and CBR remain >1,000 Bbls/d
− 67% Pipeline / 33% CBR
• Crestwood’s COLT Hub currently ~25%
CBR market share

™
™
™
™
™
™
$10
$15
$20
$25
$30
$35
$40
$45
Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15
AdjustedEBITDA($MM)
17
NE Marcellus Storage and Transportation
Summary 200 MMcf/d
North-South
Expansion
Wilmot
Receipt
Point
MARC I
Transco
Meter
Long-Term Outlook
• ~3.5 Bcf/d Marcellus dry gas supply access through
upstream gathering and producer connections
• 530 MMcf/d receipt point at Wilmot in-service
• MARC I – In Q4 2015, secured two anchor shippers for 120
MMcf/d on expansion to Transco
• MARC II – Non-binding indications of interest >700 MMcf/d
support connecting MARC I with PennEast
Critical infrastructure for NE demand markets (NYC) provide significant level of
contracted cash flows and growth opportunities
Storage
• Irreplaceable storage position with top East Coast utility
customers: Con Ed, NJNG, NYSEG, PSEG
• ~41 Bcf of natural gas storage; 99% subscribed
Transportation
• MARC I / North-South pipeline capacity of ~2.0 Bcf/d
connecting to premium north east markets (Millennium,
TGP, Transco)
• North-South Pipeline – 200 MMcf/d expansion completed in
2014; expansion fully contracted
Consistent Cash Flow from
Take-or-Pay Contracts

™
™
™
™
™
™
• 20-year, fixed-fee contracts for gathering and compression
services with Antero Resources
− ~140,000 acre dedication (235 wells connected)
− ~1,850 Antero drilling locations on Crestwood dedication
− Average IP rate for 2015 well connects of 18 MMcf/d on
Crestwood’s acreage
− Current system capacity of 875 MMcf/d
− 450 MMcf/d MVC on gathering system; compression MVC at
~50% of design capacity
• Current YTD average volumes of 480 MMcf/d
SW Marcellus Gathering & Compression
18
Long-term fee-based contracts in southwest Marcellus core production window
Summary
Markwest
Sherwood
Processing Greenbrier
Rich Gas
Area
Crestwood
Dedication Area
Antero Midstream
Dedication Area
Key Drivers for Future Drilling
• Antero has 22 DUCs connected to Crestwood’s system;
Antero expects to bring all of these wells online in 2017
• Q4 2015: Regional gathering pipeline provides access to premium
priced markets
• New Southwest Marcellus / Utica pipeline takeaway projects:
− Antero: 4.0 Bcf/d of firm takeaway by YE2017 will increase
favorable price index exposure to 94% of sales1
− SW Marcellus / Utica region: >20 Bcf/d of new firm takeaway
by YE2018 will dramatically increase SW Marcellus netbacks
• Dry gas economics improving with challenged northeast liquids
prices
(1) See November Antero Resources company presentation.

™
™
™
™
™
™
Delaware-Permian: Reservoir Overview
19
• The Delaware-Permian offers stacked pay potential and low
break-even economics
• Substantial drilling activity in the past five years has focused on
the Wolfcamp and Bone Spring formations
Wolfcamp
Western Frontier
Bone Spring
Western Fairway
Wolfcamp
Reeves Core
NorthernDelawareSouthernDelaware
Source: Wood Mackenzie May playbook.
Willow Lake
3-Stream
Gathering Project
Summary Delaware-Permian Map
Crestwood’s developing position is located in the core of the Wolfcamp and Bone Spring formations
Wolfcamp
Bone Spring
• Crestwood’s developing projects are located in the Western
Frontier and Reeves Core
• Western Frontier
– Largest expected recoveries, primarily condensate, highest avg.
API gravity in the Wolfcamp
– Avg. well profile: 820 Mboe EUR, 723 Boe/d IP-30, and 24% oil
• Reeves Core
– Lowest breakeven sub-play in the Delaware Basin, substantial
de-risking since 2013
• Crestwood’s current asset footprint is located in the Western
Fairway
• Western Fairway
– Top producing Bone Spring sub-play in 2015

™
™
™
™
™
™
Delaware-Permian: Expansion Projects
20
Crestwood is actively expanding its footprint in the heart of the Delaware Permian
Basin, the most active shale play in the US
Other Long-Term Opportunities
• Integrated gas, condensate, and water gathering system
• 600 miles of pipelines spanning over 400,000 acres
• Full development to include 109,200 of horsepower from 65
compression units at 8 centralized compressor stations
3-Stream Gathering System
Proposed Expansion Map
• Orla Terminal:
− Capacity of 200 MBbls of crude oil tankage
− 8 truck loading and unloading bays; up to 64 MBbls/d
− Additional services include blending, condensate
stabilization and 3rd party trucking services
• Delta Pipeline
− Condensate pipeline header from Orla to multiple outlets
providing access to Cushing, Houston, & Corpus Christi
− ~180 mile, 20” pipeline, 200 MBbls/d of capacity
2
3
3
2
1
Willow Lake Expansion
• Expanded processing capacity to 50 MMcf/d
• 41 new wells dedicated to be completed in 2016/2017
• Projects: Dublin Ranch to Willow Lake connector, RJT skid,
upsized interconnects for increased residue take-away options
• Placed into service January 2016; on schedule
1
3
Willow Lake
Delta Pipeline
Orla Terminal
3-Stream
Gathering
System

™
™
™
™
™
™
• Leading marketer of Marcellus/Utica NGLs
• 2.8 MMBbls of Northeast US NGL storage
capacity; >500 NGL trucking units; >1,600
NGL railcars
• Sources, transports, stores and delivers NGLs
to domestic and export markets; >350
customers
• Commenced LPG exports through Marcus
Hook, PA
• New LPG terminals in WY, RI and NC underway
• Strong NGL supply continues to push prices
lower creating a buying opportunity to build
seasonal storage
• Marketing opportunities to diversify in the West
Coast and Rocky Mountain regions
21
Crestwood NGL Assets and Services
Servicing
Blue Chip
Customers
Crestwood is well-positioned to benefit from continued Marcellus/Utica NGL supply growth
through its integrated logistics platform including Bath and Seymour storage, ME2 pipeline
capacity and Marcus Hook export capability
Summary Leading Marcellus/Utica NGL Logistics Platform
Marcus Hook
NGL Exports
Bath
NGL Storage
Seymour
NGL Storage
60
15
34
88
75
218
2015E = 490 MBPD
UEO-CHK
Dominion
Blue Racer
Crestwood
BP
Markwest

™
™
™
™
™
™
The Crestwood Investment Opportunity
No Incentive Distribution
Rights
22
1
Substantial Expense /
Fixed Charge Reduction
2
Solid Financial Results
year-over-year
3
Diversified / Balanced
Portfolio
4
Fixed Fee / Firm Contract
Profile
5
Current Valuation Not Indicative
of Business Fundamentals
Leveraged to Volume Growth
with Commodity Price Upside
1
Cost of Capital Improvement
2
Expansion Opportunities in
Delaware Permian Basin and
NE S&T
3
Strengthened Balance Sheet
in 2016
4
Attractive Valuation Entry Point
5
Execution Drives Significant Upside
Return Opportunity
Strong Liquidity /
No near-term maturities
6

™
™
™
™
™
™
Non-GAAP Reconciliations
23

™
™
™
™
™
™
CEQP Non-GAAP Reconciliations
24
(in millions, unaudited)
4th Qtr 3rd Qtr 2nd Qtr 1st Qtr 4th Qtr 3rd Qtr 2nd Qtr 1st Qtr
EBITDA
Net income (loss) (1,402.4)$ (623.4)$ (296.0)$ 18.1$ (30.7)$ 11.9$ (4.8)$ 13.2$
Interest and debt expense, net 35.4 35.7 35.4 33.6 31.3 31.5 32.6 31.7
Loss on modification/extinguishment of debt 0.2 2.7 17.1 — — — — —
Provision (benefit) for income taxes (1.2) (0.3) (0.3) 0.4 — 0.1 0.2 0.8
Depreciation, amortization and accretion 75.6 75.5 74.8 74.2 76.1 71.7 71.2 66.3
EBITDA (a)
(1,292.4)$ (509.8)$ (169.0)$ 126.3$ 76.7$ 115.2$ 99.2$ 112.0$
Significant items impacting EBITDA:
Unit-based compensation charges 4.1 3.9 5.9 5.8 4.9 4.8 6.2 5.4
(Gain) loss on long-lived assets, net 817.3 2.3 0.6 1.0 2.7 0.9 (1.2) (0.5)
Goodwill impairment 515.4 609.9 281.0 — 48.8 — — —
Loss on contingent consideration — — — — — — 6.5 2.1
(Earnings) loss from unconsolidated affiliates, net 72.0 (2.8) (5.0) (3.4) (0.6) (0.3) 1.5 0.1
Adjusted EBITDA from unconsolidated affiliates, net 6.9 6.2 5.7 6.5 2.9 1.9 0.4 1.7
Change in fair value of commodity inventory-related
derivative contracts (5.3) 8.1 1.5 1.1 (3.5) 1.0 2.9 (10.7)
Significant transaction and environmental related costs and
other items 0.9 15.7 12.4 4.6 0.8 5.4 2.2 6.5
Adjusted EBITDA (a)
118.9$ 133.5$ 133.1$ 141.9$ 132.7$ 128.9$ 117.7$ 116.6$
Distributable Cash Flow
Adjusted EBITDA (a)
118.9 133.5 133.1 141.9 132.7 128.9 117.7 116.6
Cash interest expense (b)
(33.5) (33.7) (33.3) (31.8) (29.4) (30.3) (31.2) (30.4)
Maintenance capital expenditures (c)
(10.0) (4.1) (3.9) (5.4) (9.4) (4.8) (5.7) (7.0)
(Provision) benefit for income taxes 1.2 0.3 0.3 (0.4) — (0.1) (0.2) (0.8)
Deficiency payments (0.9) (0.6) 5.7 (0.6) 3.5 2.3 3.8 1.1
Distributable cash flow attributable to CEQP 75.7$ 95.4$ 101.9$ 103.7$ 97.4$ 96.0$ 84.4$ 79.5$
Distirbutions to Niobrara Preferred (3.8) (3.8) (3.8) (3.8) — — — —
Distributable cash flow attributable to CEQP common (d)
71.9$ 91.6$ 98.1$ 99.9$ 97.4$ 96.0$ 84.4$ 79.5$
(b) Cash interest expense less amortization of deferred financing costs plus bond premium amortization plus or minus fair value adjustment of interest rate swaps.
(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 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.
20142015
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 loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense. In addition, Adjusted EBITDA considers the adjusted earnings impact of our
unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates for our proportionate share of their depreciation and interest. Adjusted EBITA also considers the impact of certain significant items, such as unit-based compensation charges, gains and
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 2015 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.

Investor presentation march 2016

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Similar to Investor presentation march 2016

Similar to Investor presentation march 2016 (20)

Recently uploaded

Recently uploaded (20)

Investor presentation march 2016