1. business and industrial
2. energy
3. natural gas

™
Connections for America’s Energy™
Jefferies 2014 Global Energy
Presentation Title
Conference
Presentation Subtitle
11/10/2014
November 11, 2014
Crestwood Midstream Partners LP
Crestwood Equity Partners LP
Forward Looking Statements
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 Midstream and Crestwood Equity 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 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 Midstream’s or Crestwood Equity’s financial condition, results of operations
and cash flows include, without limitation; the possibility that expected synergies will not be realized, or will not be realized within
the expected timeframe; fluctuations in oil, natural gas and NGL prices; the extent and success of drilling efforts, as well as the
extent and quality of natural gas volumes produced within proximity of Crestwood Midstream or Crestwood Equity assets; failure
or delays by customers in achieving expected production in their natural gas projects; competitive conditions in the industry and
their impact on the ability of Crestwood Midstream or Crestwood Equity to connect natural gas supplies to Crestwood Midstream
or Crestwood Equity gathering and processing 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 Midstream or
Crestwood Equity 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 Midstream or Crestwood Equity’s control; timely
receipt of necessary government approvals and permits, the ability of Crestwood Midstream or Crestwood Equity to control the
costs of construction, including costs of materials, labor and right-of-way and other factors that may impact either company’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 Midstream and Crestwood Equity’s
filings with the U.S. Securities and Exchange Commission. You should read filings made by Crestwood Midstream and
Crestwood Equity with the U.S. Securities and Exchange Commission, including Annual Reports on Form 10-K for the year
ended December 31, 2013, and the most recent Quarterly Reports and Current Reports, for a more extensive list of factors that
could affect results.
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2
2
Flexible Ownership Structure
Two publicly traded MLPs provides strategic flexibility to enhance value
• Crestwood / Inergy mergers in
June & October 2013 created a
new platform
• Well positioned in the Marcellus,
Utica, Bakken, PRB Niobrara and
Delaware Permian shale plays
• Fixed fee services across the
midstream value chain in Gas,
NGL and Crude Oil
• Since the Merger:
– Invested ~$1.5 BB acquisition
and organic growth capex
– Four consecutive quarters of
EBITDA and distributable cash
flow growth
– Improved CMLP coverage ratio
to 1.05X and leverage ratio to
~4.4X
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First Reserve/Crestwood
Holdings
CEQP Public
Unitholders
~71% Interest
~29% LP Interest
100% Non-economic
GP Interest (Control)
~10% LP
Interest
Crestwood Equity Partners LP
(NYSE: CEQP)
CMLP Public
Common and
Class A
Unitholders
~86% Interest
186.4 MM units outstanding
~4% LP Interest
GP / IDR Ownership
Crestwood Midstream
Partners LP
(NYSE: CMLP)
188.0 MM common units outstanding
14.9 MM Class A preferred units outstanding
Operating Subsidiaries
3
Operations and Assets in Key Shale Plays
Organized in four operating regions to ensure consistency and synergy
Natural Gas
– 1.4 Bcf/d transportation
– 2.5+ Bcf/d gathering
– 80 Bcf storage
– 615 MMcf/d processing
NGL’s and Crude Oil
– 350 MBbls/d NGL
logistics business
– 3 MMBbls NGL Storage
– ~625 trucking units
– ~1,640 rail units
– 125 MBbls/d crude oil
gathering
– 180 MBbls/d crude oil
rail terminals
– 1.5 MMBbls crude oil storage
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4
Operations across the Midstream Value Chain
Cash flow diversity across operating segments and geography increases stability
2014 EBITDA
Operating Segments
NGL &
Crude
Services
41%
Gathering &
Processing
38%
Storage &
Transportation
21%
•
Regional Footprint
West
West
4%
4%
Central
16%
US Salt
Jackalope
Barnett
Dry
Northeast
49%
Rockies
31%
Operating Assets
Other
Marcellus
Arrow
MARC I /
North South
COLT
Hub
Stagecoach
Barnett
NGL Supply
Rich
& Logistics
Growth levered to crude and NGL focused services
– Material upside to improving natural gas prices in Barnett and Fayetteville shale plays
•
Northeast and Rockies primary growth regions
– Long-term service contracts in the best US resource plays supported by strong producer
drilling economics
•
Crestwood’s three operating segments provide diversified asset platform
– 10+ different key assets with diverse fundamentals generating >$15 MM of annual EBITDA
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5
Fixed Fee Contracts provide Cash Flow Stability
Limited commodity exposure and long-term contract duration provide stable cash flows
•
Cash flow stability with 87% of EBITDA from
fixed-fee and firm contracts
2014 EBITDA
– COLT Hub rail loading volumes @ 149 MBbl/d
via take-or-pay contracts with refiners
Firm
Contracts
43%
– PRB Niobrara Jackalope JV G&P services
under 20-year cost of service contract with
CHK/RKI
– Marcellus rich gas gathering and compression
services for Antero Resources under 7-year
minimum volume commitments (2012-19)
Short-term /
Variable
13%
Fixed-Fee
44%
– NE Storage & Transportation firm capacity
100% fully contracted; FT expansions well
supported
•
Short-term/variable EBITDA primarily back-toback, indexed and fee-based NGL and Crude
marketing contracts
– Strategy focused on asset optimization
(truck, rail, storage, terminal)
Crude Oil &
NGL Gross Margin
72%
– Risk Management program to ensure
commodity price neutral book
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Dry Gas
Margin
28%
6
6
Improving Consolidated Results Since Merger
Sequential Consolidated LTM EBITDA growth; record natural gas and crude volumes
($ MMs)
2013
Segment Adjusted EBITDA
(1)
3Q
Gathering and Processing
(2)
Segment EBITDA
2014
4Q
1Q
2Q
3Q
$
43.2
$
47.5
$
48.2
$
51.0
$
50.3
CMLP Operations
$
33.4
$
33.6
$
36.8
$
37.8
$
35.7
CEQP Operations
$
1.5
$
3.1
$
1.2
$
(2.9)
$
(2.5)
Total
$
34.9
$
36.7
$
38.0
$
34.9
$
33.2
CMLP Operations
$
15.1
$
20.7
$
26.3
$
34.7
$
41.6
CEQP Operations
$
16.4
$
18.0
$
18.7
$
12.0
$
17.2
Total
$
31.5
$
38.7
$
45.0
$
46.7
$
58.8
Storage and Transportation
NGL and Crude Services
Total
$ 109.6
$ 122.9
$ 131.2
$ 132.6
$ 142.3
2,706
2,833
2,982
3,049
3,086
83
140
152
203
227
779
964
922
635
702
Operating Stats
Operating Statistics
CMLP
Natural gas volumes (MMcf/d)
Crude oil volumes (MBbls/d)
CEQP
Supply and logistics
(Gallons sold or processed, millions)
(1)
See accompanying tables of non-GAAP reconciliations.
(2)
Following the Crestwood-Inergy merger completed in October 2013, Crestwood restated its combined financial and
operating results to the beginning of the third quarter 2013.
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7
Improving Balance Sheet Outlook
Recent equity issuance improves credit metrics; no near-term debt maturities
December 31,
September 30,
2013
2014
($ in millions)
• BB/Ba3 credit rating; stable outlook
• $500 MM Class A preferred equity
commitment received by CMLP; $375 MM
issued with remaining amount to be issued
by 3Q 2015
CMLP Balance Sheet Profile
Revolver Balance
(1)
$
Total Debt
414.9
$
435.0
$ 1,870.8
$ 1,893.6
Leverage Ratio
4.91x
4.46x
Max Leverage per Covenant
5.50x
5.00x
• $300 MM ‘at-the-market’ program available
to CMLP
• Recent CEQP credit facility amendment
executed to increase capacity and leverage
flexibility
• Targeting < 4.5x FYE 2014 and < 4.0x FYE
2015 leverage ratio at CMLP
CEQP Balance Sheet Profile
Revolver Balance
(1)
Total Debt
$
381.0
$
459.9
$
395.2
$
474.1
Leverage Ratio
4.22x
4.74x
Max Leverage per Covenant
4.75x
5.50x
Debt Maturities
(1) Total CMLP Revolver capacity is $1.0 BB. Total CEQP Revolver capacity is $625 MM.
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8
Improving DCF and Leverage Outlook
•
Since closing the Crestwood / Inergy
merger, Crestwood has invested cumulative
capital of ~$1.5 billion
CMLP
($ millions)
− Capital largely allocated to core growth
assets in Marcellus, Bakken and PRB
Niobrara
− Drove heightened leverage and
reduced coverage in 4Q 2013 and 1Q
2014
•
In 1Q 2014, CMLP elected to pause on
distribution growth to allow assets time to
catch up on the growth cycle
(1)
− Successful operational and project
execution drove 38% LTM DCF growth
− 3Q 2014 coverage of 1.05x
•
Expecting CMLP distribution increases to
resume in 4Q 2014
•
CEQP distributable cash flow highly
leveraged to CMLP distributions due to IDR’s
(1) Represents cumulative organic growth capital and acquisitions.
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3Q 2014 Operations Highlights
Natural Gas
•
Record Marcellus gathering & compression volumes; 2014
capital projects completed ahead of schedule; 875 MMcf/d
capacity going into 2015
•
Strong utilization of NE storage & transportation by Marcellus
dry gas producers; expanding supply access to 3.3 Bcf/d;
leveraging growing supplies to MARC II project
Natural Gas Liquids
•
Growth in volumes from new third party Marcellus Utica
processing and fractionation facilities; utilizing truck, rail and
storage to capture market share
•
Improved margins offset by seasonally low propane and butane
volumes
•
NE NGL Bath storage continues to create margin opportunities
for Crestwood; optimistic about Watkins Glen expansion
Crude Oil
•
Record Bakken oil volumes in 3Q
•
1,000th unit train loaded at COLT Hub; two refiner contracts
renewed and extended
•
Colt R&D track to be completed in 4Q
•
Substantial 2014 growth in Arrow gathering volumes;
producers well hedged for 2015
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Marcellus / Utica Region
Core growth opportunity in the most prolific natural gas play in history
Regional Commentary
Gathering &
Compression
(1)
•
>20 Bcf/d and >1 MMBbl/d NGLs out of
Marcellus / Utica by 2020 timeframe
•
Distribution constraints for natural gas and NGLs
require new infrastructure and export capability
•
Significant Marcellus/Utica supply searching for
outlets to Midwest, East & Gulf Coast markets
•
Accounts for ~50% of 2014 EBITDA
Storage & Transportation
Supply and Logistics
• Substantial Antero system buildout since 2012
• Critical Northeast US storage and
transportation facilities
• Leading purchaser of Marcellus /
Utica NGLs
• 875 MMcf/d capacity by yearend 2014
• 41 Bcf fully contracted operational
capacity
• ~800 remaining rich gas drilling
locations; 1,000+ dry gas
locations
• >1.4 Bcf/d bi-directional
transportation capacity
• 2.2 MMBbls LPG storage, >460 LPG
trucking units, >1,400 LPG rail cars,
and >7,000 Bpd terminals
• Key customer: Antero Resources
• Attractive customer mix of utilities,
producers and marketers
• Favorable long-term fundamentals
(1)
• Accessing international markets
through East Coast waterborne
exports (Mariner East II project)
• Key customers: Williams, Total,
Hilcorp, PBF and Marathon
Based on industry forecast data.
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11
SW Marcellus (Antero) 3Q 2014 Update
Antero Midstream
Dedication Area
Crestwood
Dedication Area
Crestwood Dedication Area
•
Antero Crestwood 2012 Agreements
– 20-year, fixed-fee gathering and compression
services w/ annual escalators
– 7 year increasing MVC’s on gathering
•
Dry Gas
Area
Markwest
Sherwood
Processing
Greenbrier
Rich Gas Area
• Antero production guidance of 1.5 Bcf/d in 2015 and 2.2
Bcf/d in 2016 from Marcellus/Utica
− Contracted Marcellus firm takeaway capacity of 3
Bcf/d and processing capacity of 1.4 Bcf/d
• Antero 3Q 2014 Marcellus production of 937 MMcf/d
− Crestwood acreage ~645 MMcf/d
− Antero Midstream acreage ~292 MMcf/d
• Year end 2014 estimated total AR Marcellus gathering
and compression capacity ~1.2 Bcf/d
− Crestwood system capacity ~875 MMcf/d
− Antero Midstream system capacity ~370 MMcf/d
• Substantial capacity on Crestwood’s rich gas
acreage for AR to realize production growth
objectives
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Crestwood acreage outlook for continued volume
growth
– > 1,850 drilling locations on Crestwood
acreage
– ~ 800 drilling locations in rich-gas area (>40%
of total dedicated drilling locations)
– ~30 wells drilled, waiting on completion
– Currently 2-3 rigs on Crestwood acreage;
expected to continue through 2015
12
NE Marcellus S&T Expansion Projects
North-South
Millennium Interconnect
• Expansion for additional 200 MMcf/d of firm
transportation service
‒
Project Capex ~$10.9 MM; sub 2x
EBITDA multiple
‒
117 MMcf/d contracted with 5-yr term
‒
Planned in-service date of 1Q 2015
200 MMcf/d
North-South
Expansion
MARC I
Transco Meter Expansion
• New 700 MMcf/d Wilmot receipt point to
expand connectivity with Access Midstream’s
gathering system to accommodate growing
Marcellus production
‒
Negotiating precedent agreements with
producers for 180 MMcf/d
• Evaluating expansion of MARC I / Transco
meter for additional 380 MMcf/d
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Wilmot
Receipt
Point
MARC I /
Transco Meter
13
NE Marcellus Proposed MARC II Pipeline Project
• Proposed 31-mile, 30” pipeline to
connect MARC I to the proposed
PennEast Pipeline
MARC II Pipeline
• Expected pipeline design capacity of
1.0 Bcf/d, scalable from 0.5 Bcf/d to
1.8 Bcf/d with compression
• Estimated capital of $225 MM to
$250 MM
• Non-Binding open season held 3Q
2014 with > 700 MMcf/d demand
indicated
• Binding open season to be held 4Q
2014
PennEast Pipeline, 105 mi.
(proposed)
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• Proposed in-service year-end 2017
14
Bakken / PRB Niobrara Region
Value chain strategy at work in Bakken and PRB Niobrara
Regional Commentary
(1)
• Bakken Shale the premier crude oil shale play in
North America
– ~1.5 MMBbls/d by 2020
– 194 active rigs running in the Bakken
– 70% all crude Bbls currently exit basin via rail
• PRB Niobrara emerging crude oil play
– Stacked pay zones provides attractive inventory
of highly economic development locations
Gathering & Processing
 Bakken Arrow gathering systems
̶ Capacity of 125 MBbl/d crude
oil, 100 MMcf/d natural gas, 40
MBbl/d water by 4Q 2015
̶ Key customers: WPX, Kodiak,
Halcon, XTO, QEP and Enerplus
• PRB Niobrara gas gathering and
processing system
̶ >120 MMcf/d Bucking Horse
processing plant
̶ Key Customers: Chesapeake
and RKI Exploration
(1)
Storage & Terminalling
Crude Logistics
• Bakken: 1.1 MMBbl crude oil
storage capacity at COLT Hub;
120 MBbl storage at Dry Fork
Terminal; 200 MBbl tank capacity
at Arrow CDP
 COLT Connector pipeline links COLT
Hub and Dry Fork Terminal
• 160 MBbl/d crude-by-rail terminal
facility at COLT Hub
 Commenced crude supply and
logistics marketing in 2Q 2014 to
optimize Crestwood’s Bakken assets
• Niobrara: 10-20 MBbl/d rail
Douglas terminal and 100 Mbbl
storage in Converse County, WY
• Key customers: Tesoro, Sunoco,
Flint Hills, US Oil, Statoil, BP, CHK
 >40 MBbl/d truck capacity for crude
oil and produced water
̶ Key customers: Arrow producers,
EOG, Sinclair
 2 unit trains (220 rail cars) on order,
to be received 1Q 2015
Based on industry forecast data.
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15
Crude Price Impact on Bakken Development
North Dakota Oil and Gas Industry Impacts Study 2014-2019: KLJ, Inc
• Report commissioned by North Dakota legislature to
forecast the level of production and the trends that
impact production
COLT Terminal
• KLJ asserts that IP rates of wells is largest determinant of
return
• Crestwood’s Bakken area producers are located in
hotspots of the play in terms of high IP rates and are well
hedged for 2015 production; no indication of slowing
down drilling activity
Average Payback Period Based on IP Rates for Bakken Wells
30-day IP Rate of
Crestwood Producers
Arrow
System
IP Productivity Map
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Bakken Arrow Gathering
Crestwood’s Bakken crude oil value chain strategy begins with Arrow Gathering
• Acquired in November 2013
• 150,000 acre dedication on Fort
Berthold Indian Reservation (FBIR);
long-term crude, rich-gas and
produced water gathering contracts
• Arrow producer recent developments
– WPX:
 3Q 2014 Williston Basin
production +44% over 3Q 2013
and +7% over 2Q 2014
 Hedged at ~$95/barrel through
2015
– Halcon:
 80% of production hedge target
for next 18-24 months, current
hedges at $89/barrel
– Kodiak:
 Production acceleration expected
following acquisition by Whiting
– QEP:
 3Q 2014 Williston Basin oil
production +29% over 2Q 2014
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17
Bakken COLT Hub and Connector
COLT Hub links Bakken crude supply to prime markets; currently the leading rail
terminal in North Dakota by volume
Sourcing Capacity
• >290,000 Bbls/d
− COLT Connector
− Tesoro pipeline
− Banner pipeline
− Meadowlark pipeline
− Truck deliveries
™
Storage Capacity
• 1.2 MM Bbls (working cap)
−
−
−
−
Largest storage position in the basin
Tradable market
Point of liquidity for buyers and sellers
Creditworthy counterparties
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Takeaway Capacity
• >350,000 Bbls/d
− 160,000 Bbls/d rail loading to
West/East Coast; anchored by
long-term take-or-pay contracts
− COLT Connector
− Take-away pipeline outlets
through Tesoro, Enbridge and
Energy Transfer
18
Bakken Arrow/COLT 3Q 2014 Update
~ 220 MBbls/d in 3Q via gathering, trucking, rail loading and pipe
Arrow Gathering Update
Arrow Gathering
• Continuing volume increases following
severe winter weather in 1Q 2014
• 76 wells connected YTD through 3Q
2014, expect 98 for the full year 2014
• $19MM 3Q 2014 contribution from
Arrow is in line with original acquisition
assumption
COLT Hub & Connector
COLT Hub & Connector Update
• Facility contracted at 149 MBbls/d on
take-or-pay basis with weighted
average contract maturity through
mid-2017
• Completion of additional release and
departure in Q4 2014; expected to
increase current utilization to ~160
MBbls/d
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19
PRB Niobrara Gathering, Processing & CBR
Expanding gathering, processing and crude-by-rail (CBR) assets in the Powder
River Basin (PRB) to serve increasing production
Jackalope Gas Gathering
• 20-year 15% cost-of-service agreement and
~380,000 acre dedication primarily with
Chesapeake
• > 2 Billion BOE potential recoverable gross resource
estimated in the play
• 3Q 2014 volumes of 60 MMcf/d; 40-50 wells
curtailed due to capacity constraints
• Chesapeake to increase rigs to 7-9 in 2015
• 5-year capex forecast of $325 MM to support new
Chesapeake drilling program
Bucking Horse Gas Processing
Douglas Crude by Rail Facility
•
120 MMcf/d Bucking Horse processing plant to
be completed in 4Q 2014
•
•
Significant volume ramp expected in 1Q 2015
filling much of Bucking Horse capacity
•
•
Increased Chesapeake drilling activity leading to
discussion for a 2nd JGGS plant in 2016/17
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•
•
•
20
20 MBbls/d crude by rail loading capacity;
initiated unit train service in 3Q 2014
Started lease crude purchase program in 3Q with
Crestwood trucking expansion into area
New 120 MBbl storage tank in service in 4Q 2014
Evaluating pipeline connections to Plains, Hiland
Focus on future crude gathering system for
Chesapeake on Jackalope acreage
20
Barnett Shale Gathering & Processing Update
New drilling activity & successful work-over programs offsetting existing well
decline rates
•
Crestwood provides critical services to Quicksilver
(KWK), Tokyo Gas and Eni under existing
contracts in the Barnett
•
Receivable exposure closely monitored;
approximately $6 million monthly net receivable
exposure from KWK
•
Contract law precedent for existing contracts to
stay in-tact under various ownership alternatives
•
Recent well completions show improved
performance
– Texas Motor Speedway wells 30-day IP rate
~60% higher than average type curve
– Village Creek well with 25% higher 90-day IP
rate
•
Well work-over program has reduced Barnett
decline rates
Barnett Gathering
– 2014 volumes consistent with 2013 volumes
– < 5% volume decline rate expected in 2015
•
New incentive fee structure to drive further richgas development at Cowtown
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21
Tres Palacios Storage & Pipeline Update
Exports to Mexico to Grow to 4.0 Bcf/d by 2019
Strategic Process Update
• Long term Gulf Coast storage
fundamentals remain attractive
• Conducted sales/JV process with
strategic storage investors/customers
in 3Q 2014
• Transaction with a third-party could
result in drop-down of the remaining
interest to CMLP expected in 4Q 2014
LNG Exports Expected to Avg 9.1 Bcf/d in 2020
• Drop-down to CMLP provides
continued CEQP exposure to the
upside through IDRs
• Contemplated structure to improve
near-term results and better position
to capture current and long term
business development opportunities
Freeport ~2.0 Bcf/d
• Recent Lodi and Cardinal storage
transactions at $3.4 MM to $4.2 MM
per Bcf of working capacity indicate
potential Tres Palacios valuation of
$120 MM to $160 MM
Source: Bentek
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22
Organic Expansion Drives Long-Term Growth
>$2.0 billion of identified potential expansion opportunities around asset footprint
•
Services across the full value
chain
•
Diverse asset footprint across
all premier shale plays
•
Multiple avenues to
expand margins and
investment
E
A
D
A. Marcellus Shale: ~$500
to $600 million
B. South Texas: ~$1.1 to
$1.3 billion
F
C. Permian Basin: ~$150
million to $200 million
D. Niobrara Shale: ~$300
to $350 million
C
B
E. Bakken Shale: ~$200
to $250 million
F. West Coast: ~$75 to
$100 million
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Key Investor Highlights
Financial stability with visible growth through
execution of value chain strategy
• Attractive operations in premier US natural
gas, liquids-rich and crude oil shale plays
• Strategically located assets in
Marcellus/Utica, Bakken, PRB Niobrara and
Permian Basin
• Largely fixed fee and take or pay contracts
provide cash flow stability
• Merger integration complete, optimization
strategy underway
• Invested ~$1.5 BB in past 15 months to
drive post merger growth
• Strong 2014 quarter-over-quarter growth in
EBITDA and distributable cash flow
• Improving DCF and Leverage metrics
accelerates resumption of CMLP distribution
increases
• $2 BB identified potential expansion
opportunities around existing footprint
provides visibility to long term growth
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Non GAAP Reconciliations
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25
Crestwood Midstream Partners LP Non-GAAP
Reconciliations
CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)
Segment Data
(in millions)
(unaudited)
2 0 13
2 0 14
3 rd Q t r
2 nd Q t r
1s t Q t r
4th Qtr
3 rd Q t r
Gathering and Processing
Revenues
$
85.3
$
83.4
$
79.5
$
76.6
$
71.1
C osts of product/services sold
18.6
17.6
18.7
16.2
12.9
Operations and maintenance expense
15.9
14.7
13.4
14.4
14.9
—
—
—
—
0.5
0.5
1.0
—
(6.5)
(2.1)
0.4
(0.6)
0.3
Goodwill impairment
Gain (loss) on long-lived assets, net
(0.9)
Loss on contingent consideration
Earnings (loss) from unconsolidated affiliate
EBITDA
$
50.3
$
44.5
$
50.3
$
$
44.2
$
(4.1)
4.4
(31.4)
—
0.5
$
46.1
$
51.0
$
48.2
$
45.4
$
44.3
$
16.1
(0.4)
$
43.2
47.5
$
43.2
42.5
$
42.1
Significant items impacting EBITDA:
Loss on contingent consideration
—
Adjusted EBITDA
6.5
2.1
31.4
—
Storage and Transportation
Revenues
C osts of product/services sold
4.3
3.8
3.2
4.3
4.0
Operations and maintenance expense
4.2
4.4
4.3
4.6
4.7
—
0.6
—
—
Gain on long-lived assets
EBITDA and Adjusted EBITDA
$
35.7
$
608.9
$
37.8
$
546.9
$
36.8
$
413.2
$
—
33.6
$
33.4
246.9
$
26.9
NGL and Crude Services
Revenues
$
C osts of product/services sold
Operations and maintenance expense
Loss from unconsolidated affiliate
Significant items impacting EBITDA:
Expenses related to environmental and pre-acquisition
matters
Adjusted EBITDA
Total Segment Adjusted EBITDA
219.8
9.7
19.3
13.6
10.3
6.2
2.1
36.7
$
(0.9)
$
34.7
41.6
$
$
127.6
$
122.7
$
104.5
(0.4)
$
26.3
34.7
$
$
123.5
$
117.0
4.9
(1)
EBITDA
™
376.2
$
20.7
26.3
$
$
111.3
$
$
109.2
—
(6.5)
(18.2)
95.7
85.1
15.1
20.7
$
15.1
101.8
$
91.7
$
91.7
—
(31.4)
$
(24.1)
$
—
$
—
(2.1)
(21.3)
$
(0.2)
$
—
(4.9)
C orporate
(1)
497.7
(0.1)
EBITDA
Significant items impacting EBITDA
Total Segment EBITDA
552.8
70.4
—
(36.7)
$
33.7
(25.2)
$
66.5
Significant items impacting EB ITDA represents lo ss o n co ntingent co nsideratio n and pre-acquisitio n matters.
Connections for America’s Energy™
26
Crestwood Midstream Partners LP Non-GAAP
Reconciliations
CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)
Reconciliation of Non-GAAP Financial Measures
(in millions)
(unaudited)
2 0 13
2 0 14
3 rd Q t r
2 nd Q t r
1s t Q t r
4th Qtr
3 rd Q t r
EBITDA
Net income (loss)
$
Interest and debt expense, net
21.3
$
27.7
Provision (benefit) for income taxes
Depreciation, amortization and accretion
EBITDA (a)
Significant items impacting EBITDA:
$
11.7
$
29.0
5.5
—
0.1
0.7
55.5
54.9
50.8
104.5
$
95.7
$
28.1
$
85.1
(42.3)
$
28.0
(0.3)
0.3
48.3
$
33.7
11.6
19.5
35.1
$
66.5
Non-cash equity compensation expense
4.1
5.2
4.6
9.3
4.8
(Gain) loss on long-lived assets, net
0.9
(1.1)
(0.5)
(1.0)
(4.4)
Goodwill impairment
—
—
—
—
Loss on contingent consideration
—
6.5
2.1
31.4
(0.3)
1.5
0.1
(0.3)
0.4
1.9
0.4
1.7
1.9
0.6
(Earnings) loss from unconsolidated affiliates, net
Adjusted EBITDA from unconsolidated affiliates, net
Significant transaction and enviromental related costs
and other items
Adjusted EBITDA (a)
5.1
$
116.2
1.5
$
109.7
5.8
$
98.9
4.1
—
15.9
$
90.9
13.3
$
85.3
Distributable Cash Flow
Adjusted EBITDA
(a)
C ash interest expense
(b)
Maintenance capital expenditures (c)
(Provision) benefit for income taxes
109.7
(25.8)
(27.2)
(4.0)
—
Deficiency payments
Distributable cash flow attributable to CMLP
116.2
2.3
(d)
$
88.7
98.9
90.9
85.3
(26.3)
(21.9)
(18.6)
(4.7)
(2.7)
(5.0)
(3.7)
(0.1)
(0.7)
0.3
(0.3)
3.8
$
81.5
1.1
$
70.3
—
$
64.3
1.6
$
64.3
(a) EB ITDA is defined as inco me befo re inco me taxes, plus net interest and debt expense, and depreciatio n, amo rtizatio n and accretio n expense. In additio n, A djusted EB ITDA co nsiders the adjusted
earnings impact o f o ur unco nso lidated affiliates by adjusting o ur equity earnings o r lo sses fro m o ur unco nso lidated affiliates fo r o ur pro po rtio nate share o f their depreciatio n and interest and the impact o f
certain significant items, such as no n-cash equity co mpensatio n expenses, gains and impairments o f lo ng-lived assets and go o dwill, lo sses o n acquisitio n-related co ntingencies, third party co sts incurred
related to po tential and co mpleted acquisitio ns, certain enviro nmental remediatio n co sts, and o ther transactio ns identified in a specific repo rting perio d. EB ITDA and A djusted EB ITDA are no t measures
calculated in acco rdance with acco unting principles generally accepted in the United States o f A merica (GA A P ), as they do no t include deductio ns fo r items such as depreciatio n, amo rtizatio n and
accretio n, interest and inco me taxes, which are necessary to maintain o ur business. EB ITDA and A djusted EB ITDA sho uld no t be co nsidered an alternative to net inco me, o perating cash flo w o r any o ther
measure o f financial perfo rmance presented in acco rdance with GA A P . EB ITDA and A djusted EB ITDA calculatio ns may vary amo ng entities, so o ur co mputatio n may no t be co mparable to measures
used by o ther co mpanies.
(b) Cash interest expense is bo o k interest expense less amo rtizatio n o f deferred financing co sts plus bo nd premium amo rtizatio n.
(c) M aintenance capital expenditures are defined as tho se capital expenditures which do no t increase o perating capacity o r revenues fro m existing levels.
(d) Distributable cash flo w is defined as A djusted EB ITDA , less cash interest expense, maintenance capital expenditures, inco me taxes, deficiency payments (primarily related to deferred revenue), and
o ther adjustments. Distributable cash flo w sho uld no t be co nsidered an alternative to cash flo ws fro m o perating activities o r any o ther measure o f financial perfo rmance calculated in acco rdance with
generally accepted acco unting principles as tho se items are used to measure o perating perfo rmance, liquidity, o r the ability to service debt o bligatio ns. We believe that distributable cash flo w pro vides
additio nal info rmatio n fo r evaluating o ur ability to declare and pay distributio ns to unitho lders. Distributable cash flo w, as we define it, may no t be co mparable to distributable cash flo w o r similarly titled
measures used by o ther co rpo ratio ns and partnerships.
™
Connections for America’s Energy™
27
Crestwood Equity Partners LP Non-GAAP
Reconciliations
CRESTWOOD EQUITY PARTNERS LP (FORMERLY INERGY, L.P.)
Segment Data
(in millions)
(unaudited)
2 0 13
2 0 14
3 rd Q t r
2 nd Q t r
1s t Q t r
4th Qtr
3 rd Q t r
Gathering and Processing
Revenues
$
85.3
$
83.4
$
79.5
$
76.6
$
71.1
C osts of product/services sold
18.6
17.6
18.7
16.2
12.9
Operations and maintenance expense
15.9
14.7
13.4
14.4
14.9
—
—
—
—
0.5
0.5
1.0
—
(6.5)
(2.1)
0.4
(0.6)
0.3
Goodwill impairment
Gain (loss) on long-lived assets, net
(0.9)
Loss on contingent consideration
Earnings (loss) from unconsolidated affiliate
EBITDA
$
50.3
$
44.5
$
50.3
$
$
46.6
$
(4.1)
4.4
(31.4)
—
0.5
$
46.1
$
51.0
$
48.2
$
47.8
$
51.0
$
16.1
(0.4)
$
43.2
47.5
$
43.2
49.1
$
48.8
Significant items impacting EBITDA:
Loss on contingent consideration
—
Adjusted EBITDA
6.5
2.1
31.4
—
Storage and Transportation
Revenues
C osts of product/services sold
7.4
7.2
6.8
8.0
7.1
Operations and maintenance expense
6.0
6.3
6.2
4.4
6.8
—
0.6
—
—
38.0
36.7
$
34.9
682.5
$
307.3
Gain on long-lived assets
EBITDA and Adjusted EBITDA
$
33.2
$
904.9
$
34.9
$
795.1
$
—
NGL and Crude Services
Revenues
$
C osts of product/services sold
Operations and maintenance expense
Gain (loss) on long-lived assets
Loss from unconsolidated affiliate
$
$
722.8
760.5
622.6
270.0
34.0
27.7
24.5
20.3
15.5
—
0.1
—
(0.1)
EBITDA
841.1
817.9
52.9
(0.9)
$
43.8
(0.1)
(0.4)
$
55.7
—
(0.2)
$
39.3
—
$
21.8
Significant items impacting EBITDA:
C hange in fair value of commodity inventory-related
derivative contracts
1.0
Expenses related to environmental and pre-acquisition
matters
Adjusted EBITDA
Total Segment Adjusted EBITDA
Significant items impacting EBITDA
4.9
(a)
™
—
(0.6)
—
9.7
—
—
58.8
$
46.7
$
45.0
$
38.7
$
31.5
$
142.3
$
132.6
$
131.2
$
122.9
$
109.6
$
136.4
$
123.2
$
139.8
$
99.9
$
115.2
$
112.0
(5.9)
C orporate
EBITDA
(10.7)
$
(a)
Total Segment EBITDA
2.9
(9.4)
(21.2)
8.6
(24.0)
$
99.2
(30.8)
$
(27.8)
92.1
(9.7)
(40.6)
$
51.5
(29.1)
$
70.8
Significant items impacting EB ITDA represents lo ss o n co ntingent co nsideratio n, change in fair value o f co mmo dity invento ry-related derivative co ntracts and pre-acquisitio n matters.
Connections for America’s Energy™
28
Crestwood Equity Partners LP Non-GAAP
Reconciliations
CRESTWOOD EQUITY PARTNERS LP (FORMERLY INERGY, L.P.)
Reconciliation of Non-GAAP Financial Measures
(in millions)
(unaudited)
2 0 13
2 0 14
3 rd Q t r
2 nd Q t r
1s t Q t r
4th Qtr
3 rd Q t r
EBITDA
Net income (loss)
$
Interest and debt expense, net
Provision (benefit) for income taxes
Depreciation, amortization and accretion
EBITDA (a)
Significant items impacting EBITDA:
11.9
$
31.5
$
(4.8)
$
32.6
13.2
0.1
0.2
0.8
71.7
71.2
66.3
115.2
$
99.2
$
31.7
$
112.0
(42.1)
$
31.7
(0.2)
0.5
62.1
$
51.5
(7.9)
22.8
55.4
$
70.8
Non-cash equity compensation expense
4.8
6.2
5.4
9.8
5.6
(Gain) loss on long-lived assets, net
0.9
(1.2)
(0.5)
(0.9)
(4.4)
Goodwill impairment
—
—
—
—
Loss on contingent consideration
—
6.5
2.1
31.4
(0.3)
1.5
0.1
(0.3)
0.4
1.9
0.4
1.7
1.9
0.6
1.0
2.9
(0.6)
9.7
(Earnings) loss from unconsolidated affiliates, net
Adjusted EBITDA from unconsolidated affiliates, net
C hange in fair value of commodity inventory-related
derivative contracts
Significant transaction and environmental related costs
and other items
Adjusted EBITDA (a)
5.4
$
128.9
(10.7)
2.2
$
117.7
6.5
$
116.6
4.1
—
17.8
$
110.6
13.1
$
99.9
Distributable Cash Flow
Adjusted EBITDA
(a)
C ash interest expense
(b)
128.9
117.7
116.6
110.6
(30.3)
(31.2)
(30.4)
(26.1)
(22.1)
99.9
Maintenance capital expenditures (c)
(4.8)
(5.5)
(6.4)
(5.9)
(4.5)
(Provision) benefit for income taxes
(0.1)
(0.2)
(0.8)
0.2
(0.5)
2.3
3.8
1.1
Deficiency payments
Public C restwood Midstream LP unitholders interest in
C MLP distributable cash flow (d)
Distributable cash flow attributable to CEQP (e)
(78.1)
$
17.9
(71.2)
$
13.4
—
(60.4)
$
19.7
1.6
(54.5)
$
24.3
(58.2)
$
16.2
(a) EB ITDA is defined as inco me befo re inco me taxes, plus net interest and debt expense, and depreciatio n, amo rtizatio n and accretio n expense. In additio n, A djusted EB ITDA co nsiders the adjusted
earnings impact o f o ur unco nso lidated affiliates by adjusting o ur equity earnings o r lo sses fro m o ur unco nso lidated affiliates fo r o ur pro po rtio nate share o f their depreciatio n and interest and the impact o f
certain significant items, such as no n-cash equity co mpensatio n expenses, gains and impairments o f lo ng-lived assets and go o dwill, lo sses o n acquisitio n-related co ntingencies, third party co sts incurred
related to po tential and co mpleted acquisitio ns, certain enviro nmental remediatio n co sts and change in fair value o f certain co mmo dity derivative co ntracts, and o ther transactio ns identified in a specific
repo rting perio d. EB ITDA and A djusted EB ITDA are no t measures calculated in acco rdance with GA A P , as they do no t include deductio ns fo r items such as depreciatio n, amo rtizatio n and accretio n,
interest and inco me taxes, which are necessary to maintain o ur business. EB ITDA and A djusted EB ITDA sho uld no t be co nsidered an alternative to net inco me, o perating cash flo w o r any o ther measure
o f financial perfo rmance presented in acco rdance with GA A P . EB ITDA and A djusted EB ITDA calculatio ns may vary amo ng entities, so o ur co mputatio n may no t be co mparable to measures used by
o ther co mpanies.
(b) Cash interest expense less amo rtizatio n o f deferred financing co sts plus bo nd premium amo rtizatio n plus o r minus fair value adjustment o f interest rate swaps.
(c) M aintenance capital expenditures are defined as tho se capital expenditures which do no t increase o perating capacity o r revenues fro m existing levels.
(d)
Crestwo o d M idstream distributable cash flo w less incentive distributio ns paid to the general partner and the public LP o wnership interest in Crestwo o d M idstream.
(e) Distributable cash flo w is defined as A djusted EB ITDA , less cash interest expense, maintenance capital expenditures, inco me taxes, deficiency payments (primarily related to deferred revenue), and
public Crestwo o d M idstream LP unitho lders interest in CM LP distributable cash flo w. Distributable cash flo w sho uld no t be co nsidered an alternative to cash flo ws fro m o perating activities o r any o ther
measure o f financial perfo rmance calculated in acco rdance with generally accepted acco unting principles as tho se items are used to measure o perating perfo rmance, liquidity, o r the ability to service debt
o bligatio ns. We believe that distributable cash flo w pro vides additio nal info rmatio n fo r evaluating o ur ability to declare and pay distributio ns to unitho lders. Distributable cash flo w, as we define it, may no t
be co mparable to distributable cash flo w o r similarly titled measures used by o ther co rpo ratio ns and partnerships.
™
Connections for America’s Energy™
29