Investor presentation november 2015 v rbc final

Presentation Title
Presentation Subtitle
Crestwood Midstream Partners LP Crestwood Equity Partners LP
Connections for America’s Energy
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11/17/2015
Presentation Title
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Investor Presentation
November 2015

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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 11/16/2015.
(2) Unit count and balance sheet data as of 9/30/2015.
Crestwood Equity Partners LP
NYSE Ticker CEQP
Market Capitalization ($MM)(1,2) $1,584
Enterprise Value ($MM)(2) $4,629
Annualized Distribution $0.55
Investor Relations
investorrelations@crestwoodlp.com
(713) 380-3081

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Key Investor Highlights
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• Simplified structure positions company for long-term success
• Solid execution continues to drive results; Adj. EBITDA above consensus in all
three quarters in 2015
• YTD performance positions Crestwood to achieve 2015 guidance targets
• Diverse and balanced operations located in the most economic US shale plays
• Strong fixed-fee and take-or-pay contract portfolio
• Strong sponsorship from First Reserve
Key Investor Highlights
4

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Simplified Structure
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Key Items Post-Merger Structure
• On September 30, 2015, Closed merger between
Crestwood Equity and Crestwood Midstream
• Unified corporate strategy; focused business plan
• Improved cost of capital by eliminating IDRs
686 MM common units*
52 MM preferred units
In a challenging market, Crestwood has taken actionable steps to improve its
positioning and broaden its investment appeal
Streamlined
Business
Reverse Unit
Split
Simplification
Merger
• Completed internal organizational restructuring to
improve processes and efficiencies
• Reduced cost structure / fixed charges
• Restructured operating segments: Gathering &
Processing, Storage & Transportation, and
Marketing, Supply & Logistics
• 1-for-10 reverse unit split to be completed after
market November 23, 2015
• Broaden investment appeal for institutional and
retail unitholder
• Removes potential technical limitations to owning
units
No IDRs
* Common units will adjust to 68.6MM units upon
completion of a 1-for-10 reverse split on 11/23/2015.

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Existing Scale and New Investment Opportunities
in the Right Places
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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

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Fixed-Fee Contracts Provide Safety Net
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Contract Portfolio 2015E EBITDA
Variable
Rate Contracts
10%
Take-or-Pay and
Fixed-Fee
Contracts
90%
 ~90% of Consolidated 2015E EBITDA from take-or-pay and fixed-fee contracts
 Significant cash flow contribution protected from commodity change and volume reduction
>50% of EBITDA is
guaranteed through take-
or-pay contracts
LTM Margin Growth Despite Commodity Prices
Adjusted EBITDA
Crude Oil and Natural Gas Prices
Crude Oil
Natural Gas
Y-o-Y Adj. EBITDA
Growth: 3.6%
LTM Crude Oil decline: (57%)
LTM Natural Gas decline: (43%)
$128.9
$133.5
$100
$110
$120
$130
$140
Q3:14 Q3:15

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4Q14
Annualized
2Q/3Q 15
Annualized
($MM)
Total
Expenses
Total
Expenses Variance
Gathering & Processing $109 $81 ($28)
Storage & Transportation $27 $33 $7
Marketing, Supply & Logistics $79 $67 ($12)
Adjusted G&A $84 $51 ($33)
Total Expenses $299 $232 ($67)
Expense / Fixed Charge Reduction Strategy
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($MM)
Total Expenses Total Expenses by Segment
Taking action to materially reduce expense and fixed charges to improve margins
and distribution coverage
• Execution of strategy on-track:
– Reduced O&M and Adj. G&A(1) costs by $13.2 million in Q3 2015 over Q4 2014
– 2015 cost savings of >$15 MM; 2016+ run-rate savings of $25-30 MM
• 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)

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Consistent Operating and Financial Results
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(1) See accompanying tables of non-GAAP reconciliations.
(2) Cash flow margin is calculated by dividing Adj. EBITDA into Net Revenue.
Adjusted EBITDA and Margins(1) Operating Statistics
Improving financial performance demonstrates strong baseline cash flow;
Cost reduction efforts offset leveling volumes; 2015 guidance on-track
(2)

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Strong Liquidity Position
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Capitalization
(1) 9/30/2015 debt balance pro forma for repayment of $10.0 million of CEQP senior notes on 10/1/15.
• New Crestwood $1.5 billion revolving credit facility closed
9/30/15
– ~50% drawn RCF balance expected at 12/31/15
– ~$465 million borrowing capacity given 5.50x total
leverage covenant
• $1.8 billion senior notes
– YTW of 8.9%-9.0%
– Maturities: $500MM 6% notes due 2020, $600MM
6.125% notes due 2022, $700MM 6.25% due 2023
• Class A Preferred commitment fully drawn in Q3 2015
– Units PIK through Q2 2017; cash pay thereafter at
9.25%
• Total leverage ratio of 4.63x at 9/30/15 versus covenant
of 5.50x
Provides flexibility to execute business plan in challenging market conditions
($ millions) 9/30/2015(1)
Cash $0.2
Total Debt $2,522.3
Total Partners' Capital $5,054.0
Total Capitalization $7,576.3
Credit & Liquidity Stats
Total Leverage Ratio 4.63x
Senior Secured Leverage Ratio 1.31x
Total Leverage Covenant 5.50x
Senior Secured Leverage Covenant 3.75x
Undrawn Revolver Balance $732.5
Borrowing Capacity $473.3

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Core Operations Update
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• Bakken has continued to produce sufficient
producer wellhead returns
– 94% of rigs operating in four counties
(McKenzie, Williams, Mountrail, Dunn)
– 650 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 150 permits in the Bakken
– WPX resumed well completions on FBIR in
Q3:15 and plans on 3 rigs on FBIR by year-
end
– Halcon continues to achieve strong results
outperforming 800 MBoe type curve
– Whiting reported 24-hr IP rate of 4,300 Boe/d
with D&C costs of $6.8MM on Crestwood’s
system
Bakken Producers Remain Active Around
Crestwood’s Assets
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Permits Filed in Last 120 Days
71
125
149
312
-
50
100
150
200
250
300
350
Dunn Mountrail Williams McKenzie
Permits Heat Map
By Arrow Producers
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9
42
82
Source: North Dakota Industrial Commission

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Bakken Arrow Gathering System
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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 2015 development through
aid-in-construction lateral requests
• Lower operating cost in 2015 improves margin
• Arrow volumes have increased 13% year-over-year and
74% 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
• 20 wells connected in Q3 2015; ~75-85 new well
connects expected in 2015
• Achieved record crude volume of 80 MBbls/d in October
2015
• 2015E Throughput: Crude oil: 60 – 65 MBbls/d; Natural
gas: 40 – 45 MMcf/d; Water: 20 – 25 MBbls/d
(1) Natural gas converted to barrels at 6:1.
Arrow Adjusted EBITDA
Increasing Gathering Volumes from Continued
Drilling Activity
(1)
0
25
50
75
100
125
Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15
GatheringVolumes(Mboe/d)
Crude Oil Natural Gas Water
$0
$5
$10
$15
$20
$25
Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15
AdjustedEBITDA($MM)

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Bakken COLT Hub and Connector
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COLT Hub is the leading Bakken CBR facility linking Bakken crude supply to prime
refinery markets
Source: Genscape November 2015; 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
− 20-25% market share
• ~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 FacilitiesBakken Transportation
COLT Hub
Customers
Crestwood Maintaining Market Share in 2015
BakkenCrude-by-Rail(Bbls/d)

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$10
$15
$20
$25
$30
$35
$40
Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15
AdjustedEBITDA($MM)
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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 – Secured two anchor shippers for 120 MMcf/d on
expansion to Transco; In-service Q4 2015
• 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 ~1.8 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

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• 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
− Short-term incentive rate agreement in-place to
encourage volumes through 2H 2015
• Q3 2015 average gathering volumes of 522 MMcf/d;
Excludes 30 MMcf/d impacted by downstream
curtailments
• Operating expenses reduced 36% in Q3 2015 vs Q4
2014
• Antero has 22 DUCs connected to Crestwood’s
system; Antero expects to bring all of these wells
online in 2016
SW Marcellus Gathering & Compression
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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

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SW Marcellus Gathering Volume Expectations
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Completion of 22 DUCs will improve volumes in 2016; improved realized gas prices
and increased takeaway capacity drive completions in 2017 & beyond
• 22 well completions in 2016
• Expected completions in Q2/Q3 2016
• Minimum capital required from
Crestwood
(1) See November Antero Resources company presentation.
300
400
500
600
700
Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Dec-17
Historical Volumes & 22 DUCs Yearly Average Forecasted Volumes
300
400
500
600
700
Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Dec-17
Historical Volumes & 22 DUCs Yearly Average Forecasted Volumes
Well Connects
2013 2014 2015E 2016E 2017E
54 60 8 22 12-48
Yearly Avg. 418 MMcf/d 592 MMcf/d ~560 MMcf/d ~520 MMcf/d 480-620 MMcf/d
Historical and Projected Gathering Volumes
(MMcf/d)
Key Drivers for Future Drilling
• Q4 2015: Regional gathering pipeline will provide 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
Near-term Activity
2016-2018 MVC: 450 MMcf/d
1 rig
2 rigs
3 rigs
4 rigs
One rig in 2017 drives
volumes in excess of MVCs

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Delaware-Permian: Reservoir Overview
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• 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
G&P 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

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Delaware-Permian: Expansion Projects
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Crestwood is actively expanding its footprint in the heart of the Delaware Permian
Basin, the most active shale play in the US
Orla Terminal
• 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 G&P System
Delta Pipeline
Proposed Expansion Map
• Initial 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
• Condensate pipeline header from Orla to multiple outlets
providing access to Cushing, Houston, & Corpus Christi
• ~164 mile, 16” pipeline, 200 MBbls/d of capacity
• Expected in-service date second quarter 2017
2
3
4
3
2
1
Willow Lake Expansion
• Expanding processing capacity to 50 MMcf/d
– 6 MMcf/d currently waiting on plant expansion
– 40 new wells dedicated to be completed in 2016/2017
• Projects: Dublin Ranch to Willow Lake connector, JT skid,
upsized interconnects for increased residue take-away options
• In-service date - January 2016
1
4
Willow Lake System
Delta Pipeline
Orla Terminal
3-Stream
G&P System

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Permian Expansion Financing Plan
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• 50/50 joint venture with initial combined capital
commitments of $500 million
• First Reserve will fund 100% of initial build-out capital
• Crestwood to construct and operate on behalf of the
joint venture
• Crestwood to consolidate First Reserve’s 50% interest
in joint venture over time
Strong First Reserve sponsorship for Crestwood’s Delaware Permian development
opportunities
 Largest global private equity firm
focused exclusively on energy and
energy infrastructure
 More than 30 years of industry
experience
 $24 billion of aggregate capital deployed
since inception
 Current Crestwood sponsor with 16% LP
interest and 100% general partner
(control) interest
 First Reserve Fund XIII (2014 vintage)
has ~US$3 billion of remaining equity
capital available
Crestwood & First Reserve – Delaware Basin JV

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• 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
• Q3 2015 EBITDA increased $3.2 million y-o-y
to $27.3 million, due to NGL wholesale and
marketing outperformance
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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

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The Crestwood Investment Opportunity
Simplified Corporate Structure
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1
Substantial Expense / Fixed
Charge Reduction
2
Solid Financial Results
Quarter-over-Quarter
3
Diversified / Balanced
Portfolio
4
Fixed Fee / Firm Contract
Profile
5
Attractive Current Yield
Supported by Portfolio Stability
Leveraged to Volume Growth
with Commodity Price Upside
1
Cost of Capital Improvement2
Expansion Opportunities in
Delaware Permian Basin
3
Asset and Corporate M&A4
Attractive Valuation Entry Point5
Execution Drives Significant Upside
Return Opportunity

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Non-GAAP Reconciliations
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CEQP Non-GAAP Reconciliations
24
(in millions, unaudited)
3rd Qtr 2nd Qtr 1st Qtr 4th Qtr 3rd Qtr 2nd Qtr 1st Qtr
EBITDA
Net income (loss) (623.4)$ (296.0)$ 18.1$ (30.7)$ 11.9$ (4.8)$ 13.2$
Interest and debt expense, net 35.7 35.4 33.6 31.3 31.5 32.6 31.7
Loss on modification/extinguishment of debt 2.7 17.1 — — — — —
Provision (benefit) for income taxes (0.3) (0.3) 0.4 — 0.1 0.2 0.8
Depreciation, amortization and accretion 75.5 74.8 74.2 76.1 71.7 71.2 66.3
EBITDA (a)
(509.8)$ (169.0)$ 126.3$ 76.7$ 115.2$ 99.2$ 112.0$
Significant items impacting EBITDA:
Unit-based compensation charges 3.9 5.9 5.8 4.9 4.8 6.2 5.4
(Gain) loss on long-lived assets, net 2.3 0.6 1.0 2.7 0.9 (1.2) (0.5)
Goodwill impairment 609.9 281.0 — 48.8 — — —
Loss on contingent consideration — — — — — 6.5 2.1
(Earnings) loss from unconsolidated affiliates, net (2.8) (5.0) (3.4) (0.6) (0.3) 1.5 0.1
Adjusted EBITDA from unconsolidated affiliates, net 6.2 5.7 6.5 2.9 1.9 0.4 1.7
Change in fair value of commodity inventory-related
derivative contracts 8.1 1.5 1.1 (3.5) 1.0 2.9 (10.7)
Significant transaction and environmental related costs and
other items 15.7 12.4 4.6 0.8 5.4 2.2 6.5
Adjusted EBITDA (a)
133.5$ 133.1$ 141.9$ 132.7$ 128.9$ 117.7$ 116.6$
Distributable Cash Flow
Adjusted EBITDA (a)
133.5 133.1 141.9 132.7 128.9 117.7 116.6
Cash interest expense (b)
(33.7) (33.3) (31.8) (29.4) (30.3) (31.2) (30.4)
Maintenance capital expenditures (c)
(4.1) (3.9) (5.4) (9.4) (4.8) (5.7) (7.0)
(Provision) benefit for income taxes 0.3 0.3 (0.4) — (0.1) (0.2) (0.8)
Deficiency payments (0.6) 5.7 (0.6) 3.5 2.3 3.8 1.1
Distributable cash flow attributable to CEQP 95.4$ 101.9$ 103.7$ 97.4$ 96.0$ 84.4$ 79.5$
Distirbutions to Niobrara Preferred (3.8) (3.8) (3.8) — — — —
Distributable cash flow attributable to CEQP common (d)
91.6$ 98.1$ 99.9$ 97.4$ 96.0$ 84.4$ 79.5$
(c)    Maintenance 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.
2015
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.
(b)    Cash interest expense less amortization of deferred financing costs plus bond premium amortization plus or minus fair value adjustment of interest rate swaps.
2014

Investor presentation november 2015 v rbc final

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Investor presentation november 2015 v rbc final