rbc capital markets 2014 mlp conference presentation...

Presentation Title Presentation Subtitle

Crestwood Midstream Partners LP Crestwood Equity Partners LP

Connections for America’s Energy ™

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11/18/14




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RBC Capital Markets 2014 MLP Conference November 19-20, 2014

Connections for America’s Energy ™ ™ ™ ™ ™ ™

2

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.

Forward Looking Statements

2


Flexible Ownership Structure

3

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

Crestwood Equity Partners LP (NYSE: CEQP)

186.4 MM units outstanding

First Reserve/Crestwood Holdings

~10% LP Interest

Crestwood Midstream Partners LP

(NYSE: CMLP) 188.0 MM common units outstanding

14.9 MM Class A preferred units outstanding

Operating Subsidiaries

~4% LP Interest GP / IDR Ownership

CEQP Public Unitholders

~71% Interest

CMLP Public Common and

Class A Unitholders ~86% Interest

~29% LP Interest 100% Non-economic GP Interest (Control)


4

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

4


Operations Across the Midstream Value Chain

5 5

Cash flow diversity across operating segments and geography increases stability

Regional Footprint Operating Assets

West 4%

Rockies 31%

Central 16%

Northeast 49%

•  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

Gathering & Processing

38%

Storage & Transportation

21%

NGL & Crude

Services 41%

Operating Segments

West 4%

Stagecoach Barnett

Rich

Marcellus

NGL Supply & Logistics

COLT Hub

Barnett Dry

MARC I / North South

Arrow

US Salt Jackalope

Other

Estimated Annual EBITDA Contribution


CMLP’s Contracts Provide Cash Flow Stability

Contract Profile - 2014 YTD EBITDA

6 6

Variable Rate Contracts

6%

Take-or-Pay and Fixed-Fee Contracts

94%

•  94% of CMLP 2014 EBITDA from Take-or-Pay and Fixed-Fee contracts

•  Crestwood’s major growth assets have substantial downside protection –  COLT Hub rail loading volumes @

149 MBbl/d via take-or-pay contracts with refiners

–  PRB Niobrara Jackalope JV G&P services under 20-year 15% cost of service contract with CHK/RKI

–  Marcellus gathering and compression services for Antero Resources under 7-year minimum volume commitments (2012-19)

–  NE Storage & Transportation firm capacity 100% fully contracted; FT expansions well supported

Limited commodity exposure and long-term duration provide stable cash flows

> 50% of EBITDA is generated from take-or-pay contracts


Improving Consolidated Results Since Merger

7 7

Sequential Consolidated LTM EBITDA growth; record natural gas and crude volumes

(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.

Segment EBITDA

Operating Stats

+30%

($ MMs)Segment Adjusted EBITDA (1)

3Q (2) 4Q 1Q 2Q 3Q

Gathering and Processing 43.2$ 47.5$ 48.2$ 51.0$ 50.3$

Storage and Transportation

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$

NGL and Crude Services

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$

Total 109.6$ 122.9$ 131.2$ 132.6$ 142.3$

Operating Statistics

CMLPNatural gas volumes (MMcf/d) 2,706 2,833 2,982 3,049 3,086

Crude oil volumes (MBbls/d) 83 140 152 203 227

CEQP

Supply and logistics 779 964 922 635 702

(Gallons sold or processed, millions)

2013 2014

+14%

+174%


Improving Balance Sheet Outlook

8 8

Recent equity issuance improves credit metrics; no near-term debt maturities

•  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

•  $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

(1)  Total CMLP Revolver capacity is $1.0 BB. Total CEQP Revolver capacity is $625 MM.

Debt Maturities

December 31, September 30,($ in millions) 2013 2014

CMLP Balance Sheet Profile

Revolver Balance (1) 414.9$ 435.0$

Total Debt 1,870.8$ 1,893.6$

Leverage Ratio 4.91x 4.46x

Max Leverage per Covenant 5.50x 5.00x

CEQP Balance Sheet Profile

Revolver Balance (1) 381.0$ 459.9$

Total Debt 395.2$ 474.1$

Leverage Ratio 4.22x 4.74x

Max Leverage per Covenant 4.75x 5.50x


Improving DCF and Leverage Outlook

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•  Since closing the Crestwood / Inergy merger, Crestwood has invested cumulative capital of ~$1.5 billion

−  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

−  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)

($ millions)

(1)  Represents cumulative organic growth capital and acquisitions.

CMLP


3Q 2014 Operations Highlights

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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


Marcellus / Utica Region

11 11

•  >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

Regional Commentary (1)

Core growth opportunity in the most prolific natural gas play in history

Gathering & Compression Storage & Transportation Supply and Logistics

•  Substantial Antero system build-out since 2012

•  875 MMcf/d capacity by year-end 2014

•  ~800 remaining rich gas drilling locations; 1,000+ dry gas locations

•  Key customer: Antero Resources

•  Critical Northeast US storage and transportation facilities

•  41 Bcf fully contracted operational capacity

•  >1.4 Bcf/d bi-directional transportation capacity

•  Attractive customer mix of utilities, producers and marketers

•  Favorable long-term fundamentals

•  Leading purchaser of Marcellus / Utica NGLs

•  2.2 MMBbls LPG storage, >460 LPG trucking units, >1,400 LPG rail cars, and >7,000 Bpd terminals

•  Accessing international markets through East Coast waterborne exports (Mariner East II project)

•  Key customers: Williams, Total, Hilcorp, PBF and Marathon

(1)  Based on industry forecast data.


Gathering +71%, Compression +119%

SW Marcellus (Antero) 3Q 2014 Update 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

•  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

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•  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

Crestwood Dedication Area

Markwest Sherwood Processing

Greenbrier Rich Gas Area

Antero Midstream Dedication Area

Dry Gas Area

Connections for America’s Energy ™ ™ ™ ™ ™ ™ 13

•  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

NE Marcellus S&T Expansion Projects

MARC I Transco Meter Expansion

MARC I / Transco Meter

Wilmot Receipt Point

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

Connections for America’s Energy ™ ™ ™ ™ ™ ™ 14

NE Marcellus Proposed MARC II Pipeline Project

•  Proposed 31-mile, 30” pipeline to connect MARC I to the proposed PennEast 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

•  Proposed in-service year-end 2017

MARC II Pipeline

PennEast Pipeline, 105 mi. (proposed)


Bakken / PRB Niobrara Region

15 15

•  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

Regional Commentary (1)

Gathering & Processing Storage & Terminalling Crude Logistics §  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

•  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

•  160 MBbl/d crude-by-rail terminal facility at COLT Hub

•  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

§  COLT Connector pipeline links COLT Hub and Dry Fork Terminal

§  >40 MBbl/d truck capacity for crude oil and produced water

§  Commenced crude supply and logistics marketing in 2Q 2014 to optimize Crestwood’s Bakken assets

  Key customers: Arrow producers, EOG, Sinclair

§  2 unit trains (220 rail cars) on order, to be received 1Q 2015

Value chain strategy at work in Bakken and PRB Niobrara

(1)  Based on industry forecast data.


Crude Price Impact on Bakken Development

16

North Dakota Oil and Gas Industry Impacts Study 2014-2019: KLJ, Inc

Arrow System

COLT Terminal

•  Report commissioned by North Dakota legislature to forecast the level of production and the trends that impact production

•  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

IP Productivity Map

Average Payback Period Based on IP Rates for Bakken Wells

30-day IP Rate of Crestwood Producers


•  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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Crestwood’s Bakken crude oil value chain strategy begins with Arrow Gathering

Bakken Arrow Gathering

17


Bakken COLT Hub and Connector

18 18

Sourcing Capacity Storage Capacity Takeaway Capacity

COLT Hub links Bakken crude supply to prime markets; currently the leading rail terminal in North Dakota by volume

•  >290,000 Bbls/d −  COLT Connector −  Tesoro pipeline −  Banner pipeline −  Meadowlark pipeline −  Truck deliveries

•  1.2 MM Bbls (working cap) −  Largest storage position in the basin −  Tradable market −  Point of liquidity for buyers and sellers −  Creditworthy counterparties

•  >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


•  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

~ 220 MBbls/d in 3Q via gathering, trucking, rail loading and pipe

Arrow Gathering Update

Bakken Arrow/COLT 3Q 2014 Update

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Arrow Gathering

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

•  Proposed rules by North Dakota Industrial Commission would require vapor pressure < 13.7 psi for Bakken crude oil production -  Proposed rule effective Feb 2015 -  Monthly tests of crude oil at COLT Hub since July

2012 have all been < 13.7 psi (no impact from proposed rule)

Rail Loading +48%

Crude +38%, Water +77%, Gas +191%


Expanding gathering, processing and crude-by-rail (CBR) assets in the Powder River Basin (PRB) to serve increasing production

•  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

PRB Niobrara Gathering, Processing & CBR

20 20

Jackalope Gas Gathering

Bucking Horse Gas Processing •  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

Douglas Crude by Rail Facility •  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


21

Barnett Shale Gathering & Processing Update

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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

–  2014 volumes consistent with 2013 volumes –  < 5% volume decline rate expected in 2015

•  New incentive fee structure to drive further rich-gas development at Cowtown

Barnett Gathering


•  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

•  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

•  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

Tres Palacios Storage & Pipeline Update

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LNG Exports Expected to Avg 9.1 Bcf/d in 2020

Freeport ~2.0 Bcf/d

Strategic Process Update Exports to Mexico to Grow to 4.0 Bcf/d by 2019

Source: Bentek


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Organic Expansion Drives Long-Term Growth >$2.0 billion of identified potential expansion opportunities around asset footprint

Expansion Opportunities

A.  Marcellus Shale: ~$500 to $600 million

B.  South Texas: ~$1.1 to $1.3 billion

C.  Permian Basin: ~$150 million to $200 million

D.  Niobrara Shale: ~$300 to $350 million

E.  Bakken Shale: ~$200 to $250 million

F.  West Coast: ~$75 to $100 million

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E

D

F

C

B

A


•  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

Key Investor Highlights Financial stability with visible growth through execution of value chain strategy

24


Non GAAP Reconciliations

25 25


Crestwood Midstream Partners LP Non-GAAP Reconciliations

26

3 rd Q tr 2 nd Q tr 1s t Q tr 4 th Q tr 3 rd Q tr

Gathering and ProcessingRevenues 85.3$ 83.4$ 79.5$ 76.6$ 71.1$ Costs of product/services sold 18.6 17.6 18.7 16.2 12.9Operations and maintenance expense 15.9 14.7 13.4 14.4 14.9Goodwill impairment — — — — (4.1)Gain (loss) on long-lived assets, net (0.9) 0.5 0.5 1.0 4.4Loss on contingent consideration — (6.5) (2.1) (31.4) —Earnings (loss) from unconsolidated affiliate 0.4 (0.6) 0.3 0.5 (0.4)

EBITDA 50.3$ 44.5$ 46.1$ 16.1$ 43.2$ Significant items impacting EBITDA:

Loss on contingent consideration — 6.5 2.1 31.4 —Adjusted EBITDA 50.3$ 51.0$ 48.2$ 47.5$ 43.2$

Storage and TransportationRevenues 44.2$ 45.4$ 44.3$ 42.5$ 42.1$ Costs of product/services sold 4.3 3.8 3.2 4.3 4.0Operations and maintenance expense 4.2 4.4 4.3 4.6 4.7Gain on long-lived assets — 0.6 — — —

EBITDA and Adjusted EBITDA 35.7$ 37.8$ 36.8$ 33.6$ 33.4$

NGL and Crude ServicesRevenues 608.9$ 546.9$ 413.2$ 246.9$ 26.9$ Costs of product/services sold 552.8 497.7 376.2 219.8 9.7Operations and maintenance expense 19.3 13.6 10.3 6.2 2.1Loss from unconsolidated affiliate (0.1) (0.9) (0.4) (0.2) —


Expenses related to environmental and pre-acquisition matters 4.9 — — — —

Adjusted EBITDA 41.6$ 34.7$ 26.3$ 20.7$ 15.1$

Total Segment Adjusted EBITDA 127.6$ 123.5$ 111.3$ 101.8$ 91.7$

Significant items impacting EBITDA (1) (4.9) (6.5) (2.1) (31.4) —Total Segment EBITDA 122.7$ 117.0$ 109.2$ 70.4$ 91.7$

Corporate (18.2) (21.3) (24.1) (36.7) (25.2)EBITDA 104.5$ 95.7$ 85.1$ 33.7$ 66.5$

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)Segment Data(in millions)(unaudited)

2 0 13

(1) S ignific ant items impac ting E B IT DA repres ents lo s s on contingent cons ideration and pre-‐acquis itio n matters .

2 0 14


Crestwood Midstream Partners LP Non-GAAP Reconciliations

27


EBITDANet income (loss) 21.3$ 11.7$ 5.5$ (42.3)$ 11.6$ Interest and debt expense, net 27.7 29.0 28.1 28.0 19.5Provision (benefit) for income taxes — 0.1 0.7 (0.3) 0.3Depreciation, amortization and accretion 55.5 54.9 50.8 48.3 35.1

EBITDA (a) 104.5$ 95.7$ 85.1$ 33.7$ 66.5$ Significant items impacting EBITDA:

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 — — — — 4.1Loss on contingent consideration — 6.5 2.1 31.4 —(Earnings) loss from unconsolidated affiliates, net (0.3) 1.5 0.1 (0.3) 0.4Adjusted EBITDA from unconsolidated affiliates, net 1.9 0.4 1.7 1.9 0.6Significant transaction and enviromental related costs and other items 5.1 1.5 5.8 15.9 13.3

Adjusted EBITDA (a) 116.2$ 109.7$ 98.9$ 90.9$ 85.3$

Distributable Cash FlowAdjusted EBITDA (a) 116.2 109.7 98.9 90.9 85.3Cash interest expense (b) (25.8) (27.2) (26.3) (21.9) (18.6)Maintenance capital expenditures (c) (4.0) (4.7) (2.7) (5.0) (3.7)(Provision) benefit for income taxes — (0.1) (0.7) 0.3 (0.3)Deficiency payments 2.3 3.8 1.1 — 1.6

Distributable cash flow attributable to CMLP (d) 88.7$ 81.5$ 70.3$ 64.3$ 64.3$

(c ) Maintenance c apital expenditures are defined as tho s e c apital expenditures which do no t inc reas e operating c apac ity o r revenues from exis ting levels .

(d) D is tributable c as h flow is defined as A djus ted E B IT DA , les s c as h interes t expens e, maintenance c apital expenditures , income taxes , defic iency payments (primarily related to deferred revenue), and o ther adjus tments . D is tributable c as h flow s hould no t be cons idered an alternative to c as h flows from operating ac tiv ities o r any o ther meas ure o f financ ial perfo rmance c alculated in ac co rdance with generally ac cepted ac counting princ iples as tho s e items are us ed to meas ure operating perfo rmance, liquidity, o r the ability to s erv ic e debt obligations . We believe that dis tributable c as h flow pro vides additional info rmation fo r evaluating our ability to dec lare and pay dis tributions to unitho lders . D is tributable c as h flow, as we define it, may no t be comparable to dis tributable c as h flow o r s imilarly titled meas ures us ed by o ther co rpo rations and partners hips .

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)Reconciliation of Non-GAAP Financial Measures

(in millions)(unaudited)

2 0 13

(a) E B IT DA is defined as income befo re income taxes , plus net interes t and debt expens e, and deprec iation, amo rtization and ac c retion expens e. In addition, A djus ted E B IT DA cons iders the adjus ted earnings impac t o f our uncons o lidated affiliates by adjus ting our equity earnings o r lo s s es from our uncons o lidated affiliates fo r our propo rtionate s hare o f their deprec iation and interes t and the impac t o f c ertain s ignific ant items , s uch as non-‐cas h equity compens ation expens es , gains and impairments o f lo ng-‐lived as s ets and goodwill, lo s s es on acquis itio n-‐related contingenc ies , third party co s ts incurred related to po tential and completed acquis itio ns , c ertain environmental remediation co s ts , and o ther trans ac tions identified in a s pec ific repo rting period. E B IT DA and A djus ted E B IT DA are no t meas ures c alculated in ac co rdance with ac counting princ iples generally ac cepted in the United S tates o f A meric a (GA A P ), as they do no t inc lude deduc tions fo r items s uch as deprec iation, amo rtization and ac c retion, interes t and income taxes , which are neces s ary to maintain our bus ines s . E B IT DA and A djus ted E B IT DA s hould no t be cons idered an alternative to net income, operating c as h flow o r any o ther meas ure o f financ ial perfo rmance pres ented in ac co rdance with GA A P . E B IT DA and A djus ted E B IT DA calculations may vary among entities , s o our computation may no t be comparable to meas ures us ed by o ther companies .

2 0 14

(b) C as h interes t expens e is book interes t expens e les s amo rtization o f deferred financ ing co s ts plus bond premium amo rtization.


Crestwood Equity Partners LP Non-GAAP Reconciliations

28


Gathering and ProcessingRevenues 85.3$ 83.4$ 79.5$ 76.6$ 71.1$ Costs of product/services sold 18.6 17.6 18.7 16.2 12.9Operations and maintenance expense 15.9 14.7 13.4 14.4 14.9Goodwill impairment — — — — (4.1)Gain (loss) on long-lived assets, net (0.9) 0.5 0.5 1.0 4.4Loss on contingent consideration — (6.5) (2.1) (31.4) —Earnings (loss) from unconsolidated affiliate 0.4 (0.6) 0.3 0.5 (0.4)


Loss on contingent consideration — 6.5 2.1 31.4 —Adjusted EBITDA 50.3$ 51.0$ 48.2$ 47.5$ 43.2$

Storage and TransportationRevenues 46.6$ 47.8$ 51.0$ 49.1$ 48.8$ Costs of product/services sold 7.4 7.2 6.8 8.0 7.1Operations and maintenance expense 6.0 6.3 6.2 4.4 6.8Gain on long-lived assets — 0.6 — — —

EBITDA and Adjusted EBITDA 33.2$ 34.9$ 38.0$ 36.7 34.9$

NGL and Crude ServicesRevenues 904.9$ 795.1$ 841.1$ 682.5$ 307.3$ Costs of product/services sold 817.9 722.8 760.5 622.6 270.0Operations and maintenance expense 34.0 27.7 24.5 20.3 15.5Gain (loss) on long-lived assets — 0.1 — (0.1) —Loss from unconsolidated affiliate (0.1) (0.9) (0.4) (0.2) —


Change in fair value of commodity inventory-related derivative contracts 1.0 2.9 (10.7) (0.6) 9.7Expenses related to environmental and pre-acquisition matters 4.9 — — — —

Adjusted EBITDA 58.8$ 46.7$ 45.0$ 38.7$ 31.5$

Total Segment Adjusted EBITDA 142.3$ 132.6$ 131.2$ 122.9$ 109.6$

Significant items impacting EBITDA (a) (5.9) (9.4) 8.6 (30.8) (9.7)Total Segment EBITDA 136.4$ 123.2$ 139.8$ 92.1$ 99.9$

Corporate (21.2) (24.0) (27.8) (40.6) (29.1)EBITDA 115.2$ 99.2$ 112.0$ 51.5$ 70.8$

CRESTWOOD EQUITY PARTNERS LP (FORMERLY INERGY, L.P.)Segment Data(in millions)(unaudited)

2 0 13

(a) S ignific ant items impac ting E B IT DA repres ents lo s s on contingent cons ideration, change in fair value o f commodity invento ry-‐related derivative contrac ts and pre-‐acquis itio n matters .

2 0 14


Crestwood Equity Partners LP Non-GAAP Reconciliations

29


EBITDANet income (loss) 11.9$ (4.8)$ 13.2$ (42.1)$ (7.9)$ Interest and debt expense, net 31.5 32.6 31.7 31.7 22.8Provision (benefit) for income taxes 0.1 0.2 0.8 (0.2) 0.5Depreciation, amortization and accretion 71.7 71.2 66.3 62.1 55.4

EBITDA (a) 115.2$ 99.2$ 112.0$ 51.5$ 70.8$ Significant items impacting EBITDA:

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 — — — — 4.1Loss on contingent consideration — 6.5 2.1 31.4 —(Earnings) loss from unconsolidated affiliates, net (0.3) 1.5 0.1 (0.3) 0.4Adjusted EBITDA from unconsolidated affiliates, net 1.9 0.4 1.7 1.9 0.6Change in fair value of commodity inventory-related derivative contracts 1.0 2.9 (10.7) (0.6) 9.7Significant transaction and environmental related costs and other items 5.4 2.2 6.5 17.8 13.1

Adjusted EBITDA (a) 128.9$ 117.7$ 116.6$ 110.6$ 99.9$

Distributable Cash FlowAdjusted EBITDA (a) 128.9 117.7 116.6 110.6 99.9Cash interest expense (b) (30.3) (31.2) (30.4) (26.1) (22.1)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)Deficiency payments 2.3 3.8 1.1 — 1.6Public Crestwood Midstream LP unitholders interest in CMLP distributable cash flow (d) (78.1) (71.2) (60.4) (54.5) (58.2)

Distributable cash flow attributable to CEQP (e) 17.9$ 13.4$ 19.7$ 24.3$ 16.2$

(c ) Maintenance c apital expenditures are defined as tho s e c apital expenditures which do no t inc reas e operating c apac ity o r revenues from exis ting levels .

(d) C res twood M ids tream dis tributable c as h flow les s incentive dis tributions paid to the general partner and the public L P owners hip interes t in C res twood M ids tream.

(e) D is tributable c as h flow is defined as A djus ted E B IT DA , les s c as h interes t expens e, maintenance c apital expenditures , income taxes , defic iency payments (primarily related to deferred revenue), and public C res twood M ids tream LP unitho lders interes t in C MLP dis tributable c as h flow. D is tributable c as h flow s hould no t be cons idered an alternative to c as h flows from operating ac tiv ities o r any o ther meas ure o f financ ial perfo rmance c alculated in ac co rdance with generally ac cepted ac counting princ iples as tho s e items are us ed to meas ure operating perfo rmance, liquidity, o r the ability to s erv ic e debt obligations . We believe that dis tributable c as h flow pro vides additional info rmation fo r evaluating our ability to dec lare and pay dis tributions to unitho lders . D is tributable c as h flow, as we define it, may no t be comparable to dis tributable c as h flow o r s imilarly titled meas ures us ed by o ther co rpo rations and partners hips .

CRESTWOOD EQUITY PARTNERS LP (FORMERLY INERGY, L.P.)Reconciliation of Non-GAAP Financial Measures

(in millions)(unaudited)

2 0 13

(a) E B IT DA is defined as income befo re income taxes , plus net interes t and debt expens e, and deprec iation, amo rtization and ac c retion expens e. In addition, A djus ted E B IT DA cons iders the adjus ted earnings impac t o f our uncons o lidated affiliates by adjus ting our equity earnings o r lo s s es from our uncons o lidated affiliates fo r our propo rtionate s hare o f their deprec iation and interes t and the impac t o f c ertain s ignific ant items , s uch as non-‐cas h equity compens ation expens es , gains and impairments o f lo ng-‐lived as s ets and goodwill, lo s s es on acquis itio n-‐related contingenc ies , third party co s ts incurred related to po tential and completed acquis itio ns , c ertain environmental remediation co s ts and change in fair value o f c ertain commodity derivative contrac ts , and o ther trans ac tions identified in a s pec ific repo rting period. E B IT DA and A djus ted E B IT DA are no t meas ures c alculated in ac co rdance with GA A P , as they do no t inc lude deduc tions fo r items s uch as deprec iation, amo rtization and ac c retion, interes t and income taxes , which are neces s ary to maintain our bus ines s . E B IT DA and A djus ted E B IT DA s hould no t be cons idered an alternative to net income, operating c as h flow o r any o ther meas ure o f financ ial perfo rmance pres ented in ac co rdance with GA A P . E B IT DA and A djus ted E B IT DA calculations may vary among entities , s o our computation may no t be comparable to meas ures us ed by o ther companies .

2 0 14

(b) C as h interes t expens e les s amo rtization o f deferred financ ing co s ts plus bond premium amo rtization plus o r minus fair value adjus tment o f interes t rate s waps .

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