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Connections for Americas Energy Connections for Americas Energy Connections for Americas Energy Connections for Americas Energy Connections for Americas Energy Connections for Americas Energy


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Presentation Title

Presentation Subtitle

Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy

™ ™

Presentation Title

Presentation Subtitle

Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy

™ ™

Presentation Title

Presentation Subtitle

Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy

™ ™

11/10/2014

Presentation Title

Presentation Subtitle

Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy

™ ™

Presentation Title

Presentation Subtitle

Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy

™ ™

Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy

™ ™

Jefferies 2 0 1 4 Global Energy Conference

Novem ber 1 1 , 2 0 1 4

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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

  • f 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,

  • bjectives, 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

  • r 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

  • r 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

  • ther 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.

Forw ard Looking Statem ents

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Flexible Ow nership Structure

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Tw o 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

Crestw ood Equity Partners LP ( NYSE: CEQP)

186.4 MM units outstanding

First Reserve/ Crestw ood Holdings

~ 1 0 % LP I nterest

Crestw ood Midstream Partners LP ( NYSE: CMLP)

188.0 MM common units outstanding 14.9 MM Class A preferred units outstanding

Operating Subsidiaries

~ 4 % LP I nterest GP / I DR Ow nership

CEQP Public Unitholders

~ 71% Interest

CMLP Public Com m on and Class A Unitholders

~ 86% Interest

~ 2 9 % LP I nterest 1 0 0 % Non-econom ic GP I nterest ( Control)

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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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Operations across the Midstream Value Chain

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Cash flow diversity across operating segm ents and geography increases stability

Regional Footprint Operating Assets

W est 4 % Rockies 3 1 % Central 1 6 % Northeast 4 9 %

  • 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 3 8 % Storage & Transportation 2 1 % NGL & Crude Services 4 1 %

Operating Segm ents

W est 4 % Stagecoach Barnett Rich Marcellus NGL Supply & Logistics COLT Hub Barnett Dry MARC I / North South Arrow US Salt Jackalope Other

2 0 1 4 EBI TDA

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Fixed Fee Contracts provide Cash Flow Stability

2 0 1 4 EBI TDA

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Crude Oil & NGL Gross Margin 7 2 % Dry Gas Margin 2 8 % 6 Short-term / Variable 1 3 % Fixed-Fee 4 4 % Firm Contracts 4 3 %

  • Cash flow stability with 87% of EBITDA from

fixed-fee and firm contracts – 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 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) – NE Storage & Transportation firm capacity 100% fully contracted; FT expansions well supported

  • Short-term/variable EBITDA primarily back-to-

back, indexed and fee-based NGL and Crude marketing contracts – Strategy focused on asset optimization (truck, rail, storage, terminal) – Risk Management program to ensure commodity price neutral book

Lim ited com m odity exposure and long-term contract duration provide stable cash flow s

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I m proving Consolidated Results Since Merger

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Sequential Consolidated LTM EBI TDA grow th; record natural gas and crude volum es

(1) See accompanying tables of non-GAAP reconciliations. (2) Following the Crestwood-Inergy merger completed in October 2013, Crestwood restated its combined financial and

  • perating results to the beginning of the third quarter 2013.

Segm ent EBI TDA Operating Stats

($ MMs) Segm ent Adjusted EBI TDA ( 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 CMLP Natural 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

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I m proving Balance Sheet Outlook

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Recent equity issuance im proves credit m etrics; no near-term debt m aturities

  • 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

Decem ber 31, Septem ber 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

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I m proving 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 )

( $ m illions) (1) Represents cumulative organic growth capital and acquisitions.

CMLP

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3 Q 2 0 1 4 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

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Marcellus / Utica Region

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  • >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
  • utlets to Midwest, East & Gulf Coast markets
  • Accounts for ~50% of 2014 EBITDA

Regional Com m entary ( 1 ) Core grow th opportunity in the m ost prolific natural gas play in history Gathering & Com pression Storage & Transportation Supply and Logistics

  • Substantial Antero system build-
  • ut 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.

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SW Marcellus ( Antero) 3 Q 2 0 1 4 Update

Crestw ood 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%

  • f 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 Crestw ood’s rich gas

acreage for AR to realize production grow th

  • bjectives

Crestw ood Dedication Area

Markw est Sherw ood Processing

Greenbrier Rich Gas Area Antero Midstream Dedication Area Dry Gas Area

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  • 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 W ilm ot Receipt Point

North-South Millennium I nterconnect

  • 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

2 0 0 MMcf/ d North-South Expansion

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NE Marcellus Proposed MARC I I 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 I I Pipeline MARC I I Pipeline PennEast Pipeline, 1 0 5 m i. ( proposed) PennEast Pipeline, 1 0 5 m i. ( proposed)

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Bakken / PRB Niobrara Region

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  • 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

  • f highly economic development locations

Regional Com m entary ( 1 ) Gathering & Processing Storage & Term inalling Crude Logistics

  • Bakken Arrow gathering systems

̶ Capacity of 125 MBbl/d crude

  • il, 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
  • il and produced water
  • Commenced crude supply and

logistics marketing in 2Q 2014 to

  • ptimize 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 w ork in Bakken and PRB Niobrara

(1) Based on industry forecast data.

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Crude Price I m pact on Bakken Developm ent

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

Arrow System COLT Term inal

  • 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

I P Productivity Map Average Payback Period Based on I P Rates for Bakken W ells 3 0 -day I P Rate of Crestw ood Producers

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  • 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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Crestw ood’s Bakken crude oil value chain strategy begins w ith Arrow Gathering

Bakken Arrow Gathering

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Bakken COLT Hub and Connector

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Sourcing Capacity Storage Capacity Takeaw ay Capacity COLT Hub links Bakken crude supply to prim e m arkets; currently the leading rail term inal in North Dakota by volum e

  • >2 9 0 ,0 0 0 Bbls/ d

− COLT Connector − Tesoro pipeline − Banner pipeline − Meadowlark pipeline − Truck deliveries

  • 1 .2 MM Bbls ( w orking cap)

− Largest storage position in the basin − Tradable market − Point of liquidity for buyers and sellers − Creditworthy counterparties

  • > 3 5 0 ,0 0 0 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

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  • 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

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~ 2 2 0 MBbls/ d in 3 Q via gathering, trucking, rail loading and pipe Arrow Gathering Update

Bakken Arrow / COLT 3 Q 2 0 1 4 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

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Expanding gathering, processing and crude-by-rail ( CBR) assets in the Pow der 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

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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

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Barnett Shale Gathering & Processing Update

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New drilling activity & successful w ork-over program s offsetting existing w ell 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

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  • 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 2 0 2 0

Freeport ~ 2 .0 Bcf/ d

Strategic Process Update Exports to Mexico to Grow to 4 .0 Bcf/ d by 2 0 1 9

Source: Bentek

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Organic Expansion Drives Long-Term Grow th

> $ 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 m argins and investm ent

  • A. Marcellus Shale: ~$500

to $600 million

  • B. South Texas: ~$1.1 to

$1.3 billion

  • C. Perm ian Basin: ~$150

million to $200 million

  • D. Niobrara Shale: ~$300

to $350 million

  • E. Bakken Shale: ~$200

to $250 million

  • F. W est Coast: ~$75 to

$100 million

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E D F C B A

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  • 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
  • pportunities around existing footprint

provides visibility to long term growth

Key I nvestor Highlights

Financial stability w ith visible grow th through execution of value chain strategy

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Non GAAP Reconciliations

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Crestw ood Midstream Partners LP Non-GAAP Reconciliations

26

3rd Qtr 2nd Qtr 1st Qtr 4th Qtr 3rd Qtr

Ga the r ing a nd Pr oce ssing Revenues 85.3 $ 83.4 $ 79.5 $ 76.6 $ 71.1 $ Costs 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 Goodwill impairment — — — — (4.1) Gain (loss) on long-lived assets, net (0.9) 0.5 0.5 1.0 4.4 Loss 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 $ Stor a ge a nd Tr a nspor ta tion Revenues 44.2 $ 45.4 $ 44.3 $ 42.5 $ 42.1 $ Costs 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 Gain on long-lived assets — 0.6 — — — EBITDA and Adjusted EBITDA 35.7 $ 37.8 $ 36.8 $ 33.6 $ 33.4 $ NGL a nd Cr ude Se r v ice s Revenues 608.9 $ 546.9 $ 413.2 $ 246.9 $ 26.9 $ Costs of product/services sold 552.8 497.7 376.2 219.8 9.7 Operations and maintenance expense 19.3 13.6 10.3 6.2 2.1 Loss from unconsolidated affiliate (0.1) (0.9) (0.4) (0.2) — EBITDA 36.7 $ 34.7 $ 26.3 $ 20.7 $ 15.1 $ Significant items impacting EBITDA: Expenses related to environmental and pre-acquisition matters 4.9 — — — — Adjusted EBITDA 41.6 $ 34.7 $ 26.3 $ 20.7 $ 15.1 $ Tota l Se gm e nt Adj uste d EBI TDA 1 2 7 .6 $ 1 2 3 .5 $ 1 1 1 .3 $ 1 0 1 .8 $ 9 1 .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) EBI TDA 1 0 4 .5 $ 9 5 .7 $ 8 5 .1 $ 3 3 .7 $ 6 6 .5 $

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

2013

(1) Significant items impacting EBITDA represents loss on contingent consideration and pre-acquisition matters.

2014

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Connections for America’s Energy

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Crestw ood Midstream Partners LP Non-GAAP Reconciliations

27

3rd Qtr 2nd Qtr 1st Qtr 4th Qtr 3rd Qtr

EBI TDA Net 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 19.5 Provision (benefit) for income taxes — 0.1 0.7 (0.3) 0.3 Depreciation, amortization and accretion 55.5 54.9 50.8 48.3 35.1 EBI TDA ( a ) 1 0 4 .5 $ 9 5 .7 $ 8 5 .1 $ 3 3 .7 $ 6 6 .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 — — — — 4.1 Loss on contingent consideration — 6.5 2.1 31.4 — (Earnings) loss from unconsolidated affiliates, net (0.3) 1.5 0.1 (0.3) 0.4 Adjusted EBITDA from unconsolidated affiliates, net 1.9 0.4 1.7 1.9 0.6 Significant transaction and enviromental related costs and other items 5.1 1.5 5.8 15.9 13.3 Adj uste d EBI TDA ( a ) 1 1 6 .2 $ 1 0 9 .7 $ 9 8 .9 $ 9 0 .9 $ 8 5 .3 $ Distr ibuta ble Ca sh Flow Adjusted EBITDA (a) 116.2 109.7 98.9 90.9 85.3 Cash 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 Distr ibuta ble ca sh flow a ttr ibuta ble to CMLP ( d) 8 8 .7 $ 8 1 .5 $ 7 0 .3 $ 6 4 .3 $ 6 4 .3 $

(c) M aintenance capital expenditures are defined as those capital expenditures which do not increase operating capacity or revenues from existing levels. (d) Distributable cash flow is defined as Adjusted EBITDA, less cash interest expense, maintenance capital expenditures, income taxes, deficiency payments (primarily related to deferred revenue), and

  • ther adjustments. 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.

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

2013 (a) EBITDA is defined as income before income taxes, plus net interest and debt expense, 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 and the impact of certain significant items, such as non-cash equity compensation expenses, gains and impairments of long-lived assets and goodwill, losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, and other transactions identified in a specific reporting period. EBITDA and Adjusted EBITDA are not measures calculated in accordance with accounting principles generally accepted in the United States of America (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. 2014 (b) Cash interest expense is book interest expense less amortization of deferred financing costs plus bond premium amortization.

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Connections for America’s Energy

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Crestw ood Equity Partners LP Non-GAAP Reconciliations

28

3rd Qtr 2nd Qtr 1st Qtr 4th Qtr 3rd Qtr

Ga the r ing a nd Pr oce ssing Revenues 85.3 $ 83.4 $ 79.5 $ 76.6 $ 71.1 $ Costs 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 Goodwill impairment — — — — (4.1) Gain (loss) on long-lived assets, net (0.9) 0.5 0.5 1.0 4.4 Loss 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 $ Stor a ge a nd Tr a nspor ta tion Revenues 46.6 $ 47.8 $ 51.0 $ 49.1 $ 48.8 $ Costs 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 Gain on long-lived assets — 0.6 — — — EBITDA and Adjusted EBITDA 33.2 $ 34.9 $ 38.0 $ 36.7 34.9 $ NGL a nd Cr ude Se r v ice s Revenues 904.9 $ 795.1 $ 841.1 $ 682.5 $ 307.3 $ Costs of product/services sold 817.9 722.8 760.5 622.6 270.0 Operations and maintenance expense 34.0 27.7 24.5 20.3 15.5 Gain (loss) on long-lived assets — 0.1 — (0.1) — Loss from unconsolidated affiliate (0.1) (0.9) (0.4) (0.2) — EBITDA 52.9 $ 43.8 $ 55.7 $ 39.3 $ 21.8 $ Significant items impacting EBITDA: Change in fair value of commodity inventory-related derivative contracts 1.0 2.9 (10.7) (0.6) 9.7 Expenses related to environmental and pre-acquisition matters 4.9 — — — — Adjusted EBITDA 58.8 $ 46.7 $ 45.0 $ 38.7 $ 31.5 $ Tota l Se gm e nt Adj uste d EBI TDA 1 4 2 .3 $ 1 3 2 .6 $ 1 3 1 .2 $ 1 2 2 .9 $ 1 0 9 .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) EBI TDA 1 1 5 .2 $ 9 9 .2 $ 1 1 2 .0 $ 5 1 .5 $ 7 0 .8 $

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

2013

(a) Significant items impacting EBITDA represents loss on contingent consideration, change in fair value of commodity inventory-related derivative contracts and pre-acquisition matters.

2014

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SLIDE 29

Connections for America’s Energy

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Crestw ood Equity Partners LP Non-GAAP Reconciliations

29

3rd Qtr 2nd Qtr 1st Qtr 4th Qtr 3rd Qtr

EBI TDA Net 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 22.8 Provision (benefit) for income taxes 0.1 0.2 0.8 (0.2) 0.5 Depreciation, amortization and accretion 71.7 71.2 66.3 62.1 55.4 EBI TDA ( a) 1 1 5 .2 $ 9 9 .2 $ 1 1 2 .0 $ 5 1 .5 $ 7 0 .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 — — — — 4.1 Loss on contingent consideration — 6.5 2.1 31.4 — (Earnings) loss from unconsolidated affiliates, net (0.3) 1.5 0.1 (0.3) 0.4 Adjusted EBITDA from unconsolidated affiliates, net 1.9 0.4 1.7 1.9 0.6 Change in fair value of commodity inventory-related derivative contracts 1.0 2.9 (10.7) (0.6) 9.7 Significant transaction and environmental related costs and other items 5.4 2.2 6.5 17.8 13.1 Adj uste d EBI TDA ( a ) 1 2 8 .9 $ 1 1 7 .7 $ 1 1 6 .6 $ 1 1 0 .6 $ 9 9 .9 $ Distr ibuta ble Ca sh Flow Adjusted EBITDA (a) 128.9 117.7 116.6 110.6 99.9 Cash 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 — 1.6 Public Crestwood Midstream LP unitholders interest in CMLP distributable cash flow (d) (78.1) (71.2) (60.4) (54.5) (58.2) Distr ibuta ble ca sh flow a ttributa ble to CEQP ( e) 1 7 .9 $ 1 3 .4 $ 1 9 .7 $ 2 4 .3 $ 1 6 .2 $

(c) M aintenance capital expenditures are defined as those capital expenditures which do not increase operating capacity or revenues from existing levels. (d) Crestwood M idstream distributable cash flow less incentive distributions paid to the general partner and the public LP ownership interest in Crestwood M idstream. (e) Distributable cash flow is defined as Adjusted EBITDA, less cash interest expense, maintenance capital expenditures, income taxes, deficiency payments (primarily related to deferred revenue), and public Crestwood M idstream LP unitholders interest in CM LP distributable cash flow. Distributable cash flow should not be considered an alternative to cash flows from operating activities or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity, or the ability to service debt

  • bligations. 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.

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

2013 (a) EBITDA is defined as income before income taxes, plus net interest and debt expense, 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 and the impact of certain significant items, such as non-cash equity compensation expenses, gains and impairments of long-lived assets and goodwill, losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs and change in fair value of certain commodity derivative contracts, and other transactions identified in a specific reporting period. 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

  • f 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
  • ther companies.

2014 (b) Cash interest expense less amortization of deferred financing costs plus bond premium amortization plus or minus fair value adjustment of interest rate swaps.