Leveraged Finance Investor Conference June 2015

ADDITIONAL INFORMATION AND WHERE TO FIND IT This press release contains information about the proposed merger involving Crestwood Equity and Crestwood Midstream. In connection with the proposed merger, Crestwood Equity will file with the SEC a registration statement on Form S-4 that will include a proxy statement/prospectus for the unitholders of Crestwood Midstream. Crestwood Midstream will mail the final proxy statement/prospectus to its unitholders. INVESTORS AND UNITHOLDERS ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC CAREFULLY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT CRESTWOOD EQUITY, CRESTWOOD MIDSTREAM, THE PROPOSED MERGER AND RELATED MATTERS. Investors and unitholders will be able to obtain free copies of the proxy statement/prospectus (when available) and other documents filed with the SEC by Crestwood through the website maintained by the SEC at www.sec.gov. In addition, investors and unitholders will be able to obtain free copies of documents filed by Crestwood with the SEC from Crestwood’s website, www.crestwoodlp.com. PARTICIPANTS IN THE SOLICITATION Crestwood Equity, Crestwood Midstream, and their respective general partner’s directors and executive officers may be deemed to be participants in the solicitation of proxies from the unitholders of Crestwood Midstream in respect of the proposed merger transaction. Information regarding the persons who may, under the rules of the SEC, be deemed participants in the solicitation of the unitholders of Crestwood Midstream in connection with the proposed transaction, including a description of their direct or indirect interests, by security holdings or otherwise, will be set forth in the proxy statement/prospectus when it is filed with the SEC. Information regarding Crestwood Midstream’s directors and executive officers is contained in Crestwood Midstream’s Annual Report on Form 10-K for the year ended December 31, 2014, which is filed with the SEC on March 2, 2015, and any subsequent statements of changes in beneficial ownership on file with the SEC. Information regarding Crestwood Equity’s directors and executive officers is contained in Crestwood Equity’s Annual Report on Form 10-K for the year ended December 31, 2014, which is filed with the SEC on March 2, 2015, and any subsequent statements of changes in beneficial ownership on file with the SEC. Free copies of these documents may be obtained from the sources described above. The statements in this communication regarding future events, occurrences, circumstances, activities, performance, outcomes and results are forward-looking statements. Although these statements reflect the current views, assumptions and expectations of Crestwood’s management, the matters addressed herein are subject to numerous risks and uncertainties which could cause actual activities, performance, outcomes and results to differ materially from those indicated. Such forward-looking statements include, but are not limited to, statements about the benefits that may result from the merger and statements about the future financial and operating results, objectives, expectations and intentions and other statements that are not historical facts. Factors that could result in such differences or otherwise materially affect Crestwood’s financial condition, results of operations and cash flows include, without limitation, the possibility that expected cost reductions will not be realized, or will not be realized within the expected timeframe; fluctuations in crude oil, natural gas and NGL prices (including, without limitation, lower commodity prices for sustained periods of time); the extent and success of drilling efforts, as well as the extent and quality of natural gas and crude oil volumes produced within proximity of Crestwood assets; failure or delays by customers in achieving expected production in their oil and gas projects; competitive conditions in the industry and their impact on our ability to connect supplies to Crestwood gathering, processing and transportation assets or systems; actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers; the ability of Crestwood to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisition; changes in the availability and cost of capital; operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond Crestwood’s control; timely receipt of necessary government approvals and permits, the ability of Crestwood to control the costs of construction, including costs of materials, labor and right-of-way and other factors that may impact Crestwood’s ability to complete projects within budget and on schedule; the effects of existing and future laws and governmental regulations, including environmental and climate change requirements; the effects of existing and future litigation; and risks related to the substantial indebtedness, of either company, as well as other factors disclosed in Crestwood’s filings with the U.S. Securities and Exchange Commission. You should read filings made by Crestwood with the U.S. Securities and Exchange Commission, including Annual Reports on Form 10-K and the most recent Quarterly Reports and Current Reports for a more extensive list of factors that could affect results. Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s view only as of the date made. Crestwood does not assume any obligation to update these forward-looking statements. Company Information 2 Forward-Looking Statements Crestwood Midstream Partners LP NYSE Ticker CMLP Market Capitalization ($MM)(1,2) $2,522 Enterprise Value ($MM)(2) $4,971 Annualized Distribution $1.64 Contact Information Corporate Headquarters 700 Louisiana Street Suite 2550 Houston, TX 77002 Investor Relations investorrelations@crestwoodlp.com (713) 380-3081 Market price as of 5/29/2015. Unit count and balance sheet data as of 3/31/2015. Crestwood Equity Partners LP NYSE Ticker CEQP Market Capitalization ($MM)(1,2) $932 Enterprise Value ($MM)(2) $1,315 Annualized Distribution $0.55

Key Investor Highlights 3

Diversified platform ensures cash flow stability in current environment of lower commodity prices Substantial operations across the entire midstream value chain Strategically located assets in the most economic US shale plays Fixed fee and take or pay contracts provide safety net Six consecutive quarters of improving financial results Simplification Merger positions Crestwood to create long-term value for investors Lowers cost of capital by permanently eliminating incentive distribution rights for future investments Improves consolidated credit profile by eliminating structural subordination at CMLP Further reduces cost structure; drives substantial improvement in CEQP distributable cash flow Maintains optionality for strategic alternatives Cash Flow Stability and Long Term Growth 4

Balanced and Diverse Business Mix 5 Regional Footprint Operating Assets West 4% Rockies 32% Central 20% Northeast 43% Balanced portfolio of crude, NGL, natural gas and water services Pipeline Services Group to streamline operations and maintain competitive structure Supply & Logistics Group offers volume growth and asset optimization Gathering & Processing 39% Storage & Transportation 26% NGL & Crude Services 35% Operating Segments West 6% Stagecoach Barnett Rich Marcellus NGL Supply & Logistics COLT Hub Barnett Dry MARC I / North South Arrow US Salt Jackalope Other Estimated 2015 EBITDA Contribution Regional focus on best US resource plays Marcellus/Utica, Bakken, PRB Niobrara, Delaware Permian assets located on core, long term acreage dedications Strong producer drilling economics; substantial undrilled wellhead locations Diverse portfolio of operating assets and cash flow profiles 10+ different key assets generating >$15 MM of annual EBITDA 2014 expansion projects provide growth capacity; minimal capex in 2015

Stable Volumes in Current Commodity Cycle Current WTI Price(2): $60.28/Bbl Current Henry Hub Price(2): $2.65/MMBtu Utica Wet Tier 1 Marcellus Wet Scoop Wet Gas MS Lime Fayetteville Tier 1 Marcellus Dry Tier 1 Granite Wash Utica Dry Fayetteville Tier 2 Pinedale Barnett Tier 1 Utica Wet Tier 2 Haynesville Tier 1 Cana Tier 1 Barnett Tier 2 Piceance Tier 1 Utica Gas Marcellus Dry Tier 2 Cana Tier 2 Fayetteville Tier 3 Mancos I Haynesville Tier 2 Piceance Tier 2 Crestwood’s crude oil & natural gas operations situated in highest returning shale plays 6 WTI 5yr Strip Price(1): $67.26/Bbl Henry Hub 5yr Strip Price(1): $3.47/MMBtu Source: HPDI and TPH. Note: Wells shown on the map represent only type curve wells. Assumes 10% IRR at 16:1 Oil-to-Gas ratio. Per CME Group, WTI and Henry Hub 5-year strip prices as of 5/29/2015. Per CME Group, current front month WTI and Henry Hub price as of 5/29/2015. Crude Oil Breakeven Across Shale Plays Natural Gas Breakeven Across Shale Plays $0 $1 $2 $3 $4 $5 $6 Breakeven Henry Hub Price ($/MMbtu) $20 $30 $40 $50 $60 $70 $80 $90 Eagle Ford Oil Tier 1 Bakken Tier 1 TFS Tier 1 Niobrara Tier 1 Eagle Ford Oil Tier 2 Bakken Tier 2 PRB Tier 1 Delaware Bone Spring Midland Wolfcamp Tier 1 Midland Wolfcamp Tier 2 Delaware Wolfcamp Niobrara Tier 2 TFS Tier 2 MS Lime Tier 1 Midland Wolfberry Vt Tier 1 Bakken Tier 3 SCOOP Oil CTM Tier 1 PRB Tier 2 CTM Tier 2 East Texas Eagle Ford Midland Wolfcamp Tier 3 Uinta Oil Eagle Ford Oil Tier 3 CTM Tier 3 MS Lime Tier 2 Midland Wolfberry Vt Tier 2 TMS Breakeven WTI Price ($/bbl)

Fixed-Fee Contracts Provide Safety Net Consolidated Contract Portfolio 2015E EBITDA 7 Variable Rate Contracts 10% Take-or-Pay and Fixed-Fee Contracts 90% ~90% of Consolidated 2015E EBITDA from take-or-pay and fixed-fee contracts Significant cash flow contribution protected from commodity change and volume reduction >50% of EBITDA is guaranteed through take-or-pay contracts Key Asset Contract Type Contract Volume Weighted Avg. Tenor COLT Hub Rail Loading Take-or-Pay 149,300 Bbls/d 2017 Marcellus G&P (Antero) Minimum Volume Commitment 450 MMcf/d 2018 PRB Niobrara G&P (CHK) 15% Cost of Service fee on Cuml. Capex ~$175MM capex to date 2033 NE Marcellus S&T Firm Storage and Transportation Firm Storage: 41 Bcf Transportation: 1.1 Bcf/d Firm Storage: 2017 Transportation: 2020 Select Take-or-Pay Contract Portfolio (1) MVC of 425 MMcf/d in 2015, stepping up to 450 MMcf/d in 2016-2018. Fixed fee contract extends until 12/31/2031. (1) (1)

Consistent Operating and Financial Results 8 See accompanying tables of non-GAAP reconciliations. Segment EBITDA Operating Statistics +19% ($MM) Consolidated Segment Adjusted 2015 EBITDA (1) 1Q 2Q 3Q 4Q 1Q Gathering and Processing 47.7 $ 50.5 $ 51.2 $ 49.4 $ 53.4 $ Storage and Transportation 38.0 $ 34.3 $ 33.2 $ 37.9 $ 39.0 $ NGL and Crude Services 45.0 $ 46.6 $ 58.8 $ 63.1 $ 63.3 $ Total 130.7 $ 131.4 $ 143.2 $ 150.4 $ 155.7 $ Consolidated Operating Statistics Natural gas (MMcf/d) 2,982 3,049 3,086 3,355 3,362 Crude oil (MBbls/d) 152 203 227 214 228 Natural gas liquids (MBbls/d) 244 166 182 221 232 2014 +13% +50% $48 $51 $51 $49 $53 $38 $34 $33 $38 $39 $45 $47 $59 $63 $63 $0 $20 $40 $60 $80 $100 $120 $140 $160 1Q 14 2Q 14 3Q 14 4Q 14 1Q 15 $MMs G&P S&T N&C

Continuing to Execute our Financing Strategy 9 Cash Flow Accretion Liability Management Redeemed in April 2015 Senior Notes Offering in March 2015 March 2015 New Issuance ($MM) (1) 7.75% coupon on $350 MM senior notes due 2019. (2) 6.25% coupon on $350 MM senior notes refinanced into 2023 senior notes. Includes additional revolver borrowings required for $13.6 MM call premium on 2019 senior notes. Annualized Interest Savings on $350 MM Sr. Notes Refinancing ~$4.8 MM interest expense savings contributing to future DCF $27 MM (1) $22 MM (2) Corporate Family Rating - Ba3/BB Issue Rating - B1/BB $700 MM senior notes new issuance in March 2015 Coupon: 6.25% Maturity: 2023 Use of proceeds to fully pay down $1.0 BB CMLP revolving credit facility In April 2015, fully redeemed the $350 MM 7.75% senior notes due 2019 Refinancing results in ~$4.8 MM in annualized interest expense savings Extends long term average debt maturity profile from ~5.5 years to >6.5 years

10 Six consecutive quarters of improving sequential operating results driving improving credit profile 2023 benchmark CMLP Senior Notes issued at par on March 9, 2015, currently trading at 105.3; current yield of 5.9% attractive cost of long-term debt capital Source: FactSet. 6.125% Notes Due Mar 2022 6.0% Notes Due Dec 2020 6.25% Notes Due Dec 2023 Yield-to-Maturity: 5.3% Competitive Cost of Debt Capital 95 100 105 110 Jan-15 Feb-15 Mar-15 Apr-15 May-15 105.3 90 96 102 108 Jan-15 Feb-15 Mar-15 Apr-15 May-15 104.4 90 96 102 108 Jan-15 Feb-15 Mar-15 Apr-15 May-15 104.8

Simplification Merger 11

Simplification Highlights 12 Elimination of ~$30 million of IDRs drives immediate cost of capital improvement Competitive cost of capital improves positioning for >$3.0 billion of identified expansion opportunities Improved Cost of Capital Improved credit profile due to the elimination of structural subordination Better positions Crestwood to participate in the continuing trend of industry consolidation Simplified Corporate Structure Eliminates $5 million of estimated public company costs Additive to $25 million to $30 million run-rate savings identified as a part of Crestwood’s 2015 cost reduction initiatives Reduced Cost Structure / Fixed Charges Pro forma 2015 CEQP coverage ratio improved to ~1.05x at $0.55 per unit distribution (~$15 million excess cash flow coverage)(1) Expected pro forma DCF growth of ~11% through 2017(2); accelerated with greater M&A and organic investment Improving Distribution Coverage Focus on core strategy of servicing the full midstream value chain in the premier shale plays in North America Greater strategic transparency more attractive to a broader universe of investors Unified Corporate Strategy (1) Assumes January 1, 2015 effective date for the transaction for illustrative purposes. (2) Represents growth rate from 2015E pro forma DCF (assuming January 1, 2015 effective date) to 2017E pro forma DCF.

Simplified Structure Creates One Crestwood! 13 Crestwood Equity Partners LP (NYSE: CEQP) 187.2 MM units First Reserve/ Crestwood Holdings ~11% LP Interest Crestwood Midstream Partners LP (NYSE: CMLP) 188.3 MM common units 18.8 MM Class A preferred units Operating Subsidiaries ~4% LP Interest GP / IDR Ownership CEQP Public Unitholders ~71% LP Interest CMLP Public Common and Preferred Unitholders ~85% LP Interest ~29% LP Interest 100% Non-economic GP Interest (Control) Operating Subsidiaries (NGL Assets) Crestwood Equity Partners LP (NYSE: CEQP) 685 MM common units 52 MM preferred units First Reserve/ Crestwood Holdings Crestwood Midstream Partners LP (private wholly-owned subsidiary) 100% Operating Subsidiaries CEQP Public and Preferred Unitholders ~84% LP Interest ~16% LP Interest 100% Non-economic GP Interest (Control) $495 MM Revolver $14.1 MM Other Debt $1.5 BB Revolver $1.8 BB Sr. Notes $1.0 BB Revolver $500 MM 6.00% Notes due 2020 $600 MM 6.125% Notes due 2022 $700 MM 6.25% Notes due 2023 Current Structure Pro Forma Structure

Expense / Fixed Charge Reduction drives DCF 14 Bold action to materially reduce expense and fixed charges to improve margins and distribution coverage Execution of our current strategy to materially reduce operating cost across the partnership Expected 2015 cost savings of ~$15 MM; 2016+ run-rate savings of $25-30 MM Drives greater profitability in the current industry environment Increased efficiency without sacrificing customer service, reliability, safety or compliance Simplification further adds to coverage improvement through fixed charge elimination Eliminates dual public company costs (~$5 MM) Merger terms provide incremental retained DCF (~$23 MM)(1) Calendar Year 2015 Direct Contribution to Improving DCF and Distribution Coverage Represents the incremental retained DCF pro forma for the simplification transaction at CEQP’s current distribution of $0.55 per unit. Estimated $5 million of reduced administrative expenses through elimination of second publically traded entity. (1) $MM Run-Rate 2015 (2)

Cost of Capital Analysis – Impact of IDR Elimination 15 (1) Current LP distribution on newly issued units. (2) Assumes 1.05x distribution coverage on incremental DCF. (3) Assumes CMLP pricing as of 5/5/2015 ($16.00 / unit). (4) Assumes CEQP pricing as of 5/29/2015 ($5.00 / unit). (5) $500 MM Investment, 50% Equity / 50% Debt Consideration, Cost of Debt = 6.25%. Current Prices (4) 8% Yield Pro Forma CEQP Status Quo CMLP Pre-Announcement (3) Elimination of IDRs drives immediate cost of capital improvement ($ millions except per unit data) $500 MM Investment (5) $500 MM Investment (5) $500 MM Investment (5) Investment Multiple 6.0x 9.0x 12.0x 6.0x 9.0x 12.0x 6.0x 9.0x 12.0x Acquired EBITDA $83 $56 $42 $83 $56 $42 $83 $56 $42 (-) Maintenance Capex (4) (3) (2) (4) (3) (2) (4) (3) (2) (-) Incremental Interest Expense (16) (16) (16) (16) (16) (16) (16) (16) (16) (-) Cost of New Equity (1) (26) (26) (26) (28) (28) (28) (20) (20) (20) Incremental DCF Available to Distribute $38 $12 ($2) $36 $10 ($4) $44 $17 $4 (-) Incremental GP Distribution / IDRs (19) (6) 0 Incremental DCF Available to LPs $19 $5 ($2) $36 $10 ($4) $44 $17 $4 Existing Units 188 188 188 685 685 685 685 685 685 New Units 16 16 16 50 50 50 36 36 36 Pro Forma Total Units 204 204 204 735 735 735 721 721 721 Distribution Summary Current Distribution per Unit $1.64 $1.64 $1.64 $0.55 $0.55 $0.55 $0.55 $0.55 $0.55 (+) Incremental Distribution per Unit (2) 0.08 0.02 (0.01) 0.05 0.01 (0.00) 0.06 0.02 0.01 Pro Forma Distribution per Unit $1.72 $1.66 $1.63 $0.60 $0.56 $0.55 $0.61 $0.57 $0.56 Distribution Growth % 4.8% 1.1% (0.8%) 8.5% 2.3% (0.8%) 10.5% 4.1% 1.0% Current Prices (4) 8% Yield Pro Forma CEQP Status Quo CMLP Pre-Announcement (3)

Attractive Opportunity Set for Long Term Growth Improving cost of capital to capture >$3.0 billion of identified potential expansion opportunities around asset footprint Expansion Opportunities Marcellus Shale: $500 to $600 million (2015-2019) North-South / Marc I Expansion, Marc II Antero Gathering South Texas: $1.1 to $1.3 billion (2016-2019) Connecting Tres to developing demand centers (LNG, Mexico export) Permian Basin: $600 to $1.0 billion (2015-2019) Willow Lake expansion, Delaware Permian Crude and Water Gathering opportunities Niobrara Shale: $300 to $350 million (2015-2019) Jackalope gathering & processing, crude oil gathering, Douglas Terminal expansion Bakken Shale: $500 to $750 million (2015-2019) Arrow gathering expansion, third party crude, gas and water gathering opportunities 16 E D C B A

The New Crestwood Investment Opportunity Simplified Corporate Structure 17 Cash Flow Stability 1 Substantial Expense / Fixed Charge Reduction 2 Improving Financial Results Quarter-over-Quarter 3 Diversified / Balanced Portfolio 4 Fixed Fee / Firm Contract Profile 5 Capital Appreciation Cash Flows Supported by Portfolio Stability Leveraged to Volume Growth with Commodity Price Upside 1 Cost of Capital Improvement 2 Organic Expansion Opportunities 3 Asset and Corporate M&A 4 Improving Credit Profile 5 Execution Drives Significant Upside Opportunity and Credit Improvement

Core Operations Update 18

Bakken Arrow Gathering System 19 Tier 1 acreage dedication with substantial long-term growth through system build out Summary ~150,000 acre dedication under LT contracts Crude, natural gas and water gathering for fee Substantial system build-out completed in 2014 Producers continuing active 2015 development through aid-in-construction lateral requests Lower operating cost in 2015 improves margin Crestwood purchases crude oil up to 60 MBbls/d at Arrow CDP at monthly index prices Arrow system connected to COLT Hub through Tesoro and Hiland crude oil pipelines Long-Term Outlook >1,200 estimated future drilling locations 20 wells connected in Q1 2015; 75-85 new well connects expected in 2015 2015E Throughput: Crude oil: 60 – 65 MBbls/d; Natural gas: 40 – 45 MMcf/d; Water: 20 – 25 MBbls/d Arrow COLT Hub Bakken Asset footprint in concentrated acreage blocks with highly competitive drilling economics(1) 2015E Net Revenue Contribution by Producer (1) Source: BTU Analytics LLC.

Bakken COLT Hub and Connector 20 COLT Hub is the leading Bakken CBR facility linking Bakken crude supply to prime refinery markets Source: Genscape May 2015. Summary Premier crude oil pipeline, storage and CBR facility in North Dakota 160 MBbl/d crude-by-rail facility; 1.2 MMBbls storage capacity;70 MBbls/d COLT connector pipeline ~ 300 MBbls/d supply aggregation capacity at COLT HUB (gathering, truck rack, pipelines) ~ 149 MBbls/d CBR take-or-pay contracts through 2015/16; current customers to 2019 Markets: 73% West Coast, 27% East Coast CBR to Gulf Coast squeezed out by 2018 with new pipeline; No pipeline capacity to service West Coast and East Coast refinery demand Bakken Crude by Rail Loading Facilities Bakken Transportation Colt Hub Contracted Capacity Mix $6.30/bbl $9.00-$10.00/bbl $9.00-$10.00/bbl $8.60/bbl Bakken Price Differentials ANS ($8.86) WTI ($3.15) Brent ($9.31) LLS ($8.65)

Actively developing a leading position in the PRB to handle both crude and gas PRB Niobrara Gathering, Processing & CBR 21 Summary 50/50 Jackalope Joint Venture with Williams (Access) 20-year, 15% cost of service contract with Chesapeake and RKI; 311,000 acres under dedication ~$250 MM Crestwood capital investment to date 120 MMcf/d processing plant completed in January 2015; 199 miles gathering pipeline and compression 50/50 Douglas Joint Venture with Enserco Douglas Crude-by-Rail Terminal - 20 MBbls/d CBR facility; 120 MBbl storage; connections to Plains and Hiland in 2015 Long term CBR contract with Chesapeake at Douglas 3,000 + potential Chesapeake gross drilling locations (~126 wells drilled to date) in CHK/RKI AMI > 2.0 billion BOE gross recoverable resources per CHK Opportunity to connect full value chain services for CHK and other area producers – gas gathering and processing; crude oil gathering, trucking, CBR and storage Bucking Horse Plant Long-Term Outlook

22 NE Marcellus Storage and Transportation Summary MARC II 200 MMcf/d North-South Expansion Wilmot Receipt Point MARC I / Transco Meter ~41 Bcf of natural gas storage and pipeline capacity of ~1.8 Bcf/d Weighted average contract term of 4 years Storage facilities continue to reflect favorable market dynamics 99% subscribed throughout 2015 ~15% of capacity up for renewal in 2016 Majority of contract renewals at or above existing rates North/South Pipeline – 200 MMcf/d expansion completed in 2014; expansion fully contracted Long-Term Outlook ~3.5 Bcf/d Marcellus dry gas supply access to NS/MARC I pipeline system through upstream gathering and producer connections New ~700 MMcf/d receipt point at Wilmot scheduled in 2015 MARC I Pipeline – Secured 100 MMcf/d anchor shipper on expansion to Transco; currently in FERC process MARC II Non-binding indications of interest >700 MMcf/d in Q414 support potential 30 mile lateral connecting MARC I with PennEast Strategically located NE assets provide significant level of contracted cash flows and growth opportunities

20-year, fixed-fee contracts for gathering and compression services with Antero Resources ~140,000 acre dedication (235 wells connected) Current system capacity of 875 MMcf/d 450 MMcf/d MVC’s on gathering system; compression MVC at ~50% of design capacity 4-well Wagner pad completed in Q4 2014 at 59 MMcf/d IP rate in Greenbriar area Q1 2015 average gathering volumes of 653 MMcf/d 8 new wells completed by Antero in Q1 2015 SW Marcellus Gathering & Compression 23 Crestwood Dedication Area Markwest Sherwood Processing Greenbrier Rich Gas Area Antero Midstream Dedication Area Dry Gas Area ~1,850 Antero drilling locations on Crestwood dedication New 1.4 Bcf/d regional pipeline scheduled for Q4 2015 to increase takeaway capacity to higher priced gas markets 22 drilled but uncompleted wells on CMLP system (Greenbrier rich gas area) to be completed in 2016 Antero expected to use CMLP system/compression over next 3 to 4 years to help fulfill its >4 Bcf/d FT takeaway commitments commencing in 2018 Marcellus Compressor Station Long-term fee-based contracts in southwest Marcellus core production window Summary Long-Term Outlook

24 Crestwood NGL Assets and Services Servicing Blue Chip Customers Across the Full Energy Value Chain NGL Marketing & Logistics 40% West Coast 22% NGL Transportation 17% Terminals & Storage 21% Premier NGL supply and logistics platform servicing the value chain to connect NGL supplies to NGL demand markets Summary 2015E EBITDA Contribution Leading marketer of Marcellus/Utica NGL's 2.8 MMBbls of Northeast US NGL storage capacity >500 NGL trucking units; >1,600 NGL railcars Sources, transports, stores and delivers NGLs to domestic and export markets; >350 customers Commenced LPG exports in 1Q 2015 through Marcus Hook, PA New LPG terminals in WY, RI and NC underway (1) Processing capacity includes 25 MMcf/d West Coast, 120 MMcf/d JGGS JV and 480 MMcf/d CMLP.

Non-GAAP Reconciliations 25

CMLP Non-GAAP Reconciliations 26 (in millions, unaudited) 2015 2014 2014 EBITDA Net income (loss) 21.7 $ 5.5 $ (60.4) $ Interest and debt expense, net 29.9 28.1 26.6 Provision (benefit) for income taxes 0.3 0.7 (0.1) Depreciation, amortization and accretion 59.9 50.8 60.5 EBITDA (a) 111.8 $ 85.1 $ 26.6 $ Significant items impacting EBITDA: Unit-based compensation charges 5.2 4.6 4.2 (Gain) loss on long-lived assets, net 0.8 (0.5) 34.3 Goodwill impairment — — 48.8 Loss on contingent consideration — 2.1 — (Earnings) loss from unconsolidated affiliates, net (3.4) 0.1 (0.6) Adjusted EBITDA from unconsolidated affiliates, net 6.5 1.7 2.9 Significant transaction and environmental related costs and other items 3.8 5.8 1.5 Adjusted EBITDA (a) 124.7 $ 98.9 $ 117.7 $ Distributable Cash Flow Adjusted EBITDA (a) 124.7 $ 98.9 $ 117.7 $ Cash interest expense (b) (28.0) (26.3) (24.8) Maintenance capital expenditures (c) (2.7) (3.3) (7.4) (Provision) benefit for income taxes (0.3) (0.7) 0.1 Deficiency payments (0.6) 1.1 3.5 Distributable cash flow attributable to CMLP (d) 93.1 $ 69.7 $ 89.1 $ (a) (b) Cash interest expense is book interest expense less amortization of deferred financing costs plus bond premium amortization. (c) (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 other 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. Three Months Ended March 31, Three Months Ended December 31, 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 unit-based compensation expenses, gains and impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, change in fair value of certain commodity derivative contracts, certain costs related to our 2015 cost savings initiatives, 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 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. Maintenance capital expenditures are defined as those capital expenditures which do not increase operating capacity or revenues from existing levels.

CEQP Segment Data 27 (in millions, unaudited) 2015 1st Qtr 4th Qtr 3rd Qtr 2nd Qtr 1st Qtr Gathering and Processing Revenues 78.5 $ 84.3 $ 85.3 $ 83.4 $ 79.5 $ Costs of product/services sold 12.7 16.4 18.6 17.6 18.7 Operations and maintenance expense 14.9 18.9 15.9 14.7 13.4 Gain (loss) on long-lived assets, net (0.3) (32.8) (0.9) 0.5 0.5 Goodwill impairment — (18.5) — — — Loss on contingent consideration — — — (6.5) (2.1) Earnings (loss) from unconsolidated affiliate 2.5 0.4 0.4 (0.6) 0.3 EBITDA 53.1 $ (1.9) $ 50.3 $ 44.5 $ 46.1 $ Significant items impacting EBITDA: (Gain) loss on long-lived assets, net 0.3 32.8 0.9 (0.5) (0.5) Goodwill impairment — 18.5 — — — Loss on contingent consideration — — — 6.5 2.1 Adjusted EBITDA 53.4 $ 49.4 $ 51.2 $ 50.5 $ 47.7 $ Storage and Transportation Revenues 45.7 $ 47.5 $ 46.6 $ 47.8 $ 51.0 $ Costs of product/services sold 3.3 3.4 7.4 7.2 6.8 Operations and maintenance expense 4.3 4.8 6.0 6.3 6.2 Gain on long-lived assets (0.7) 33.2 — 0.6 — Earnings (loss) from unconsolidated affiliate 0.9 0.2 — — — EBITDA 38.3 $ 72.7 $ 33.2 $ 34.9 $ 38.0 $ Significant items impacting EBITDA: (Gain) loss on long-lived assets, net 0.7 (33.2) — (0.6) — Expenses related to pre-acquisition matters — (1.6) — — — Adjusted EBITDA 39.0 $ 37.9 $ 33.2 $ 34.3 $ 38.0 $ NGL and Crude Services Revenues 607.5 $ 865.8 $ 904.9 $ 795.1 $ 841.1 $ Costs of product/services sold 513.9 769.0 817.9 722.8 760.5 Operations and maintenance expense 31.4 30.9 34.0 27.7 24.5 Gain (loss) on long-lived assets — (3.1) — 0.1 — Goodwill impairment — (30.3) — — — Loss from unconsolidated affiliate — — (0.1) (0.9) (0.4) EBITDA 62.2 $ 32.5 $ 52.9 $ 43.8 $ 55.7 $ Significant items impacting EBITDA: (Gain) loss on long-lived assets, net — 3.1 — (0.1) — Goodwill impairment — 30.3 — — — Change in fair value of commodity inventory-related derivative contracts 1.1 (3.5) 1.0 2.9 (10.7) Expenses related to environmental and pre-acquisition matters — 0.7 4.9 — — Adjusted EBITDA 63.3 $ 63.1 $ 58.8 $ 46.6 $ 45.0 $ Total Segment Adjusted EBITDA 155.7 $ 150.4 $ 143.2 $ 131.4 $ 130.7 $ Significant items impacting EBITDA (a) (2.1) (47.1) (6.8) (8.2) 9.1 Total Segment EBITDA 153.6 $ 103.3 $ 136.4 $ 123.2 $ 139.8 $ Corporate (27.3) (26.6) (21.2) (24.0) (27.8) EBITDA 126.3 $ 76.7 $ 115.2 $ 99.2 $ 112.0 $ 2014 (a) Significant items impacting EBITDA represents gains and impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, certain environmental remediation costs, change in fair value of commodity inventory-related derivative contracts and pre-acquisition matters.

CEQP Non-GAAP Reconciliations 28 (in millions, unaudited) 2015 1st Qtr 4th Qtr 3rd Qtr 2nd Qtr 1st Qtr EBITDA Net income (loss) 18.1 $ (30.7) $ 11.9 $ (4.8) $ 13.2 $ Interest and debt expense, net 33.6 31.3 31.5 32.6 31.7 Provision (benefit) for income taxes 0.4 — 0.1 0.2 0.8 Depreciation, amortization and accretion 74.2 76.1 71.7 71.2 66.3 EBITDA (a) 126.3 $ 76.7 $ 115.2 $ 99.2 $ 112.0 $ Significant items impacting EBITDA: Unit-based compensation compensation 5.8 4.9 4.8 6.2 5.4 (Gain) loss on long-lived assets, net 1.0 2.7 0.9 (1.2) (0.5) Goodwill impairment — 48.8 — — — Loss on contingent consideration — — — 6.5 2.1 (Earnings) loss from unconsolidated affiliates, net (3.4) (0.6) (0.3) 1.5 0.1 Adjusted EBITDA from unconsolidated affiliates, net 6.5 2.9 1.9 0.4 1.7 Change in fair value of commodity inventory-related derivative contracts 1.1 (3.5) 1.0 2.9 (10.7) Significant transaction and environmental related costs and other items 4.6 0.8 5.4 2.2 6.5 Adjusted EBITDA (a) 141.9 $ 132.7 $ 128.9 $ 117.7 $ 116.6 $ Distributable Cash Flow Adjusted EBITDA (a) 141.9 132.7 128.9 117.7 116.6 Cash interest expense (b) (31.8) (29.4) (30.3) (31.2) (30.4) Maintenance capital expenditures (c) (5.4) (9.4) (5.5) (5.7) (7.0) (Provision) benefit for income taxes (0.4) — (0.1) (0.2) (0.8) Deficiency payments (0.6) 3.5 2.3 3.8 1.1 Public Crestwood Midstream LP unitholders interest in CMLP distributable cash flow (d) (82.3) (77.0) (78.1) (71.2) (60.4) Distributable cash flow attributable to CEQP (e) 21.4 $ 20.4 $ 17.2 $ 13.2 $ 19.1 $ (d) Crestwood Midstream distributable cash flow less incentive distributions paid to the general partner and the public LP ownership interest in Crestwood Midstream. (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 Midstream LP unitholders interest in CMLP 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 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. 2014 (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 unit-based compensation expenses, gains and impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, change in fair value of certain commodity derivative contracts, certain costs related to our 2015 cost savings initiatives, 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 of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies. (b) Cash interest expense less amortization of deferred financing costs plus bond premium amortization plus or minus fair value adjustment of interest rate swaps. (c) Maintenance capital expenditures are defined as those capital expenditures which do not increase operating capacity or revenues from existing levels. The year ended December 31, 2014, includes $1.5 million of maintenance capital expenditures for January 1, 2014 to September 30, 2014 that was reclassified from growth capital expenditures to maintenance capital expenditures.