Connections for America s Energy. Investor Presentation. Presentation Title. Presentation Subtitle. March /29/2016

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1 Investor Presentation Presentation Title Presentation Subtitle March /29/2016 Crestwood Midstream Partners LP Crestwood Equity Partners LP

2 Company Information Crestwood Equity Partners LP Contact Information NYSE Ticker CEQP Market Capitalization ($MM) (1,2) $617 Enterprise Value ($MM) (2) $3,724 Annualized Distribution $5.50 Corporate Headquarters 700 Louisiana Street Suite 2550 Houston, TX Investor Relations (713) Forward-Looking Statements The statements in this communication regarding future events, occurrences, circumstances, activities, performance, outcomes and results are forward-looking statements. Although these statements reflect the current views, assumptions and expectations of Crestwood 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. (1) Market price as of 2/24/2016. (2) Unit count and balance sheet data as of 12/31/

3 Key Investor Highlights 3

4 Key Investor Highlights Solid execution in 2015 drives results; Adj. EBITDA increased 6%; OPEX and G&A expenses reduced 9%; LTM coverage ratio ~1.0x Stable cash flow generation in 2016; ~60% of asset base flat to up 5% Strong liquidity position; No senior note maturities until 2020 Diverse and balanced operations located in the most economic US shale plays Strong take-or-pay and fixed-fee contract portfolio; 92% take-or-pay and fixed fee in 2016 No Incentive Distribution Rights Strong sponsorship from First Reserve; $90MM units purchased Q415/Q116; Currently owns 23% common units 4

5 2016 Outlook 2016E Adjusted EBITDA of $490 million to $520 million; ~60% of the business flat to up in E Segment Cash Flow Reduced CAPEX ($MM) 2016E Adj. EBITDA Guidance $490MM - $520MM Segment Contribution ($MM) Storage & Transportation 40% Gathering & Processing 43% Marketing Supply & Logistics 17% (1) Excludes corporate G&A expenses of $65 million. (1) (1) Gathering & Processing Adjusted EBITDA: $235MM - $250MM Volumes trending 15%-20% lower in E cash flow forecasts include conservative forecasts for Barnett and PRB Niobrara assets Segment Outlook Storage & Transportation Adjusted EBITDA: $225MM - $235MM Volumes trending flat to up 5% in 2016 NE S&T and COLT Hub take-orpay contracts drive stable cash flow Marketing, Supply & Logistics Adjusted EBITDA: $95MM - $100MM Flat cash flows in 2016 Marketing business supported by hard assets and long-term relationships 5

6 Repositioning Crestwood in 2015/16 In a challenging market, Crestwood continues to take actionable steps to improve its positioning and broaden its investment appeal Key Items Corporate Structure Streamlined Business In 1Q 2015, completed Project Adapt to cut costs and improve processes and efficiencies In 2Q 2015, restructured operations to Pipeline Services and Marketing, Supply & Logistics divisions Cost Cutting / Reduced Capex In 2015, reduced O&M and G&A expenses by $26MM year-over-year through Project Adapt initiatives Limiting growth capital expenditures to previously committed contractual projects 69.1 MM common units 62.1 MM preferred units Simplification Merger On September 30, 2015, closed merger between Crestwood Equity and Crestwood Midstream Improved cost of capital by eliminating IDRs No IDRs Deleverage Strategy In 2016, Crestwood is pursuing strategic steps to strengthen the balance sheet in lower-for-longer environment Evaluating full range of options, including further CAPEX and cost reductions, divesting of assets, and evaluating appropriate distribution level 6

7 Existing Scale and New Investment Opportunities in the Right Places Crestwood s crude oil and natural gas operations are situated in the highest returning shale plays Over 75% of cash flow is sourced from two premier basins: Marcellus and Bakken Marcellus and Bakken cash flow trading multiples illustrate valuation disconnect Delaware-Permian expansion projects provide opportunity to build third franchise position Scale and diversity of remaining cash flows are competitively positioned across multiple resource plays Bakken Marcellus 7

8 Fixed-Fee Contracts Provide Safety Net 92% of 2016E EBITDA from take-or-pay and fixed-fee contracts Significant cash flow contribution protected from commodity change and volume reduction Contract Portfolio 2016E EBITDA YoY Margin Growth Despite Commodity Prices Crude Oil and Natural Gas Prices Variable Rate Contracts 8% Crude Oil decline: (61%) Natural Gas decline: (45%) Crude Oil Natural Gas Take-or-Pay and Fixed-Fee Contracts 92% Adjusted EBITDA Y-o-Y Adj. EBITDA Growth: 6.4% 55% of EBITDA is guaranteed through takeor-pay contracts 8

9 Expense / Fixed Charge Reduction Strategy Crestwood exceeded stated cost reduction goals in 2015; On-track to remove an additional $10MM in 2016 In 2015, Crestwood materially reduced expenses and fixed charges to improve margins and coverage: Reduced O&M and Adj. G&A (1) costs by $26.4 million in 2015 over 2014 Additional 2016 cost savings of >$10MM; run-rate savings of >$35MM Results drive greater profitability in the current industry environment Increased efficiency without sacrificing customer service, safety or compliance Simplification adds to coverage improvement through fixed charge elimination Total Expenses Total Expenses by Segment ($MM) $350 $300 $250 $299 $253 ($MM) 4Q14 Annualized FY 2015 Total Total Expenses Expenses Variance Gathering & Processing $109 $89 ($20) $200 $150 $100 4Q14 Annualized FY 2015 (1) Adjusted G&A is defined as general and administrative expenses less unit-based compensation charges and significant transaction and environmental related costs and other items. Storage & Transportation $27 $32 $5 Marketing, Supply & Logistics $79 $70 ($9) (1) Adjusted G&A $84 $63 ($21) Total Expenses $299 $253 ($46) %-Change (15.4%) 9

10 Consistent Operating and Financial Results Improving financial performance demonstrates strong baseline cash flow; Q strongly impacted by warm weather Adjusted EBITDA and Margins (1) $18.0 (3) $118.5 Q415 miss of $18mm attributable to unseasonably warm weather; depressed NE regional pricing (2) Natural Gas Volumes Crude Oil Volumes (1) See accompanying tables of non-gaap reconciliations. (2) Cash flow margin is calculated by dividing Adj. EBITDA into Net Revenue. (3) Cash flow margin adjusted for Q shut-in and weather impacts. 10

11 Capital Structure Crestwood has ample liquidity to execute business plan in challenging market Summary Strong liquidity position 1.5 billion revolving credit facility ~50% drawn RCF balance No near-term maturities; attractive long-term capital $1.8 billion senior notes; 6.00%-6.25% coupon Nearest maturity 2020 Capitalization ($ millions) 12/31/2015 Cash $0.5 Total Debt $2,540.3 Total Partners' Capital $2,946.9 Total Capitalization $5,487.2 Credit & Liquidity Stats Total Leverage Ratio 4.75x Senior Secured Leverage Ratio 1.37x Total Leverage Covenant 5.50x Senior Secured Leverage Covenant 3.75x Ample covenant cushion Debt Maturities Strong fixed charge coverage No need to access capital markets in 2016 ($MM) No near-term debt maturities RCF 6% Notes 6.125% Notes 6.25% Notes 11

12 Manageable Counterparty Risk Crestwood has a diverse customer portfolio; producer counterparty risk manageable in the event of continued market deterioration Counterparty Risk Overview 2016E Cash Flow Exposure Diverse customer base is comprised of integrated producers, refiners, utilities, and petrochemical companies The majority of customers well-positioned to navigate a lower-for-longer environment Crestwood is actively monitoring at-risk counterparties to mitigate cash flow risk in 2016 Highly confident in contractual positioning to mitigate cash flow loss from potential bankruptcies Quicksilver Resources Filed for bankruptcy March 2015; Began sales process in Q BlueStone Natural Resources emerged as winning bidder; Must close by March 2016 Binding agreement in place with the back up bidder Long-term resolution likely by Q Manageable counterparty risk in 2016 (1) (1) Represents total annual cash flow contributions from higher risk counterparties. 12

13 Core Operations Update 13

14 Bakken Producers Remain Active Around Crestwood s Assets Bakken has continued to produce sufficient producer wellhead returns 94% of rigs operating in four counties (McKenzie, Williams, Mountrail, Dunn) Permits Filed in Last 120 Days By Arrow Producers 48 ~340 permits have been filed in those four counties in last 120 days Estimated breakeven WTI pricing of $24- $41/bbl in these four core counties Producers improved IP rates, realized cost reductions, and minimized cost to market Reducing days to drill to days As of February 24, Permits Heat Map Crestwood producers continue to achieve strong results: In the last 120 days, Arrow producers have filed approximately 100 permits in the Bakken Halcon expects 2016 wells put online to have an EUR of ~900 Mboe; average D&C of $6.2MM Whiting reported 24-hr IP rate of 4,300 Boe/d on Crestwood s system Source: North Dakota Industrial Commission 14

15 Gathering Volumes (Mboe/d) Adjusted EBITDA ($MM) Bakken Arrow Gathering System Tier 1 acreage dedication with substantial long-term growth through system build out Summary ~150,000 acre dedication under LT contracts Crude, natural gas and water gathering Producers continuing active development through aidin-construction lateral requests Lower operating cost in 2015 improves margin Arrow volumes have increased 14% year-over-year and 76% since Q $25 $20 $15 $10 $5 $0 Arrow Adjusted EBITDA Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15 Arrow system connected to COLT Hub through Tesoro and Hiland crude oil pipelines Long-Term Outlook >1,200 estimated future drilling locations new well connects expected in 2016 XTO, WPX and QEP approximately 90% of 2016 development activity Achieved record crude volume of 80 MBbls/d in October 2015 Increasing Gathering Volumes from Continued Drilling Activity Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15 (1) Crude Oil Natural Gas Water (1) Natural gas converted to barrels at 6:1. 15

16 Bakken Pipeline /Crude-by-Rail (Bbls/d) Bakken COLT Hub and Connector COLT Hub is the leading Bakken CBR facility linking Bakken crude supply to prime refinery markets Summary Premier crude oil pipeline, storage and CBR facility in the Bakken 160 MBbls/d crude-by-rail facility; 1.2 MMBbls storage capacity; 70 MBbls/d COLT connector pipeline ~300 MBbls/d supply aggregation capacity at COLT Hub (gathering, truck rack, pipelines) Strong refiner customers dependent on the Bakken barrel and crude-by-rail transportation COLT Hub Customers Top 5 Bakken CBR Facilities Maintaining Market Share Going into 2016 Pipeline and CBR remain >1,000 Bbls/d 67% Pipeline / 33% CBR Crestwood s COLT Hub currently ~25% CBR market share Source: Genscape February 2016; EIA. 16

17 Adjusted EBITDA ($MM) NE Marcellus Storage and Transportation Critical infrastructure for NE demand markets (NYC) provide significant level of contracted cash flows and growth opportunities Storage Summary Irreplaceable storage position with top East Coast utility customers: Con Ed, NJNG, NYSEG, PSEG ~41 Bcf of natural gas storage; 99% subscribed Transportation 200 MMcf/d North-South Expansion MARC I / North-South pipeline capacity of ~2.0 Bcf/d connecting to premium north east markets (Millennium, TGP, Transco) 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 through upstream gathering and producer connections MARC I Transco Meter Wilmot Receipt Point 530 MMcf/d receipt point at Wilmot in-service MARC I In Q4 2015, secured two anchor shippers for 120 MMcf/d on expansion to Transco MARC II Non-binding indications of interest >700 MMcf/d support connecting MARC I with PennEast $45 $40 $35 $30 $25 $20 $15 $10 Consistent Cash Flow from Take-or-Pay Contracts Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15 17

18 SW Marcellus Gathering & Compression Long-term fee-based contracts in southwest Marcellus core production window 20-year, fixed-fee contracts for gathering and compression services with Antero Resources Summary ~140,000 acre dedication (235 wells connected) ~1,850 Antero drilling locations on Crestwood dedication Average IP rate for 2015 well connects of 18 MMcf/d on Crestwood s acreage Current system capacity of 875 MMcf/d 450 MMcf/d MVC on gathering system; compression MVC at ~50% of design capacity Current YTD average volumes of 480 MMcf/d Key Drivers for Future Drilling Antero has 22 DUCs connected to Crestwood s system; Antero expects to bring all of these wells online in 2017 Q4 2015: Regional gathering pipeline provides access to premium priced markets New Southwest Marcellus / Utica pipeline takeaway projects: Antero: 4.0 Bcf/d of firm takeaway by YE2017 will increase favorable price index exposure to 94% of sales 1 SW Marcellus / Utica region: >20 Bcf/d of new firm takeaway by YE2018 will dramatically increase SW Marcellus netbacks Dry gas economics improving with challenged northeast liquids prices Antero Midstream Dedication Area Markwest Sherwood Processing Crestwood Dedication Area Greenbrier Rich Gas Area (1) See November Antero Resources company presentation. 18

19 Delaware-Permian: Reservoir Overview Crestwood s developing position is located in the core of the Wolfcamp and Bone Spring formations The Delaware-Permian offers stacked pay potential and low break-even economics Substantial drilling activity in the past five years has focused on the Wolfcamp and Bone Spring formations Source: Wood Mackenzie May playbook. Summary Wolfcamp Crestwood s developing projects are located in the Western Frontier and Reeves Core Western Frontier Largest expected recoveries, primarily condensate, highest avg. API gravity in the Wolfcamp Avg. well profile: 820 Mboe EUR, 723 Boe/d IP-30, and 24% oil Reeves Core Lowest breakeven sub-play in the Delaware Basin, substantial de-risking since 2013 Avg. well profile: 600 Mboe EUR, 720 Boe/d IP-30, and 59% oil Bone Spring Crestwood s current asset footprint is located in the Western Fairway Western Fairway Top producing Bone Spring sub-play in 2015 Avg. well profile: 589 Mboe EUR, 687 Boe/d IP-30, and 30% oil Wolfcamp Western Frontier Bone Spring Western Fairway Wolfcamp Reeves Core Willow Lake 3-Stream Gathering Project Delaware-Permian Map Northern Delaware Southern Delaware 19

20 Delaware-Permian: Expansion Projects Crestwood is actively expanding its footprint in the heart of the Delaware Permian Basin, the most active shale play in the US 1 Willow Lake Expansion Expanded processing capacity to 50 MMcf/d 41 new wells dedicated to be completed in 2016/2017 Projects: Dublin Ranch to Willow Lake connector, RJT skid, upsized interconnects for increased residue take-away options Placed into service January 2016; on schedule Proposed Expansion Map 2 3-Stream Gathering System 1 Willow Lake Integrated gas, condensate, and water gathering system 600 miles of pipelines spanning over 400,000 acres Full development to include 109,200 of horsepower from 65 compression units at 8 centralized compressor stations 3 Other Long-Term Opportunities Orla Terminal: Capacity of 200 MBbls of crude oil tankage 8 truck loading and unloading bays; up to 64 MBbls/d Additional services include blending, condensate stabilization and 3rd party trucking services Delta Pipeline Condensate pipeline header from Orla to multiple outlets providing access to Cushing, Houston, & Corpus Christi 3-Stream Gathering System 2 3 Orla Terminal 3 Delta Pipeline ~180 mile, 20 pipeline, 200 MBbls/d of capacity 20

21 Crestwood NGL Assets and Services Crestwood is well-positioned to benefit from continued Marcellus/Utica NGL supply growth through its integrated logistics platform including Bath and Seymour storage, ME2 pipeline capacity and Marcus Hook export capability Summary Leading marketer of Marcellus/Utica NGLs Leading Marcellus/Utica NGL Logistics Platform 2.8 MMBbls of Northeast US NGL storage capacity; >500 NGL trucking units; >1,600 NGL railcars Bath NGL Storage Sources, transports, stores and delivers NGLs to domestic and export markets; >350 customers Commenced LPG exports through Marcus Hook, PA Seymour NGL Storage New LPG terminals in WY, RI and NC underway Strong NGL supply continues to push prices lower creating a buying opportunity to build seasonal storage Marketing opportunities to diversify in the West Coast and Rocky Mountain regions 2015E = 490 MBPD UEO-CHK Dominion Blue Racer Crestwood BP Markwest Marcus Hook NGL Exports Servicing Blue Chip Customers 21

22 The Crestwood Investment Opportunity Current Valuation Not Indicative of Business Fundamentals Execution Drives Significant Upside Return Opportunity 1 Diversified / Balanced Portfolio 1 Attractive Valuation Entry Point 2 Fixed Fee / Firm Contract Profile 2 Strengthened Balance Sheet in Solid Financial Results year-over-year Substantial Expense / Fixed Charge Reduction Strong Liquidity / No near-term maturities No Incentive Distribution Rights Leveraged to Volume Growth with Commodity Price Upside Cost of Capital Improvement Expansion Opportunities in Delaware Permian Basin and NE S&T 22

23 Non-GAAP Reconciliations 23

24 CEQP Non-GAAP Reconciliations CRESTWOOD EQUITY PARTNERS LP Reconciliation of Non-GAAP Financial Measures (in millions, unaudited) EBITDA 4th Qtr 3rd Qtr 2nd Qtr 1st Qtr 4th Qtr 3rd Qtr 2nd Qtr 1st Qtr Net income (loss) $ (1,402.4) $ (623.4) $ (296.0) $ 18.1 $ (30.7) $ 11.9 $ (4.8) $ 13.2 Interest and debt expense, net Loss on modification/extinguishment of debt Provision (benefit) for income taxes (1.2) (0.3) (0.3) Depreciation, amortization and accretion EBITDA (a) $ (1,292.4) $ (509.8) $ (169.0) $ $ 76.7 $ $ 99.2 $ Significant items impacting EBITDA: Unit-based compensation charges (Gain) loss on long-lived assets, net (1.2) (0.5) Goodwill impairment Loss on contingent consideration (Earnings) loss from unconsolidated affiliates, net 72.0 (2.8) (5.0) (3.4) (0.6) (0.3) Adjusted EBITDA from unconsolidated affiliates, net Change in fair value of commodity inventory-related derivative contracts (5.3) (3.5) (10.7) Significant transaction and environmental related costs and other items Adjusted EBITDA (a) $ $ $ $ $ $ $ $ Distributable Cash Flow Adjusted EBITDA (a) Cash interest expense (b) (33.5) (33.7) (33.3) (31.8) (29.4) (30.3) (31.2) (30.4) Maintenance capital expenditures (c) (10.0) (4.1) (3.9) (5.4) (9.4) (4.8) (5.7) (7.0) (Provision) benefit for income taxes (0.4) (0.1) (0.2) (0.8) Deficiency payments (0.9) (0.6) 5.7 (0.6) Distributable cash flow attributable to CEQP $ 75.7 $ 95.4 $ $ $ 97.4 $ 96.0 $ 84.4 $ 79.5 Distirbutions to Niobrara Preferred (3.8) (3.8) (3.8) (3.8) Distributable cash flow attributable to CEQP common (d) $ 71.9 $ 91.6 $ 98.1 $ 99.9 $ 97.4 $ 96.0 $ 84.4 $ 79.5 (b) Cash interest expense less amortization of deferred financing costs plus bond premium amortization plus or minus fair value adjustment of interest rate swaps (a) EBITDA is defined as income before income taxes, plus debt-related costs (net interest and debt expense and loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense. In addition, Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates for our proportionate share of their depreciation and interest. Adjusted EBITA also considers the impact of certain significant items, such as unit-based compensation charges, gains and impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, certain costs related to our 2015 cost savings initiatives, the change in fair value of commodity inventory-related derivative contracts, and other transactions identified in a specific reporting period. The change in fair value of commodity inventory-related derivative contracts is considered in determining Adjusted EBITDA given that the timing of recognizing gains and losses on these derivative contracts differs from the recognition of revenue for the related underlying sale of inventory that these derivatives relate to. Changes in the fair value of other derivative contracts is not considered in determining Adjusted EBITDA given the relatively short-term nature of those derivative contracts. EBITDA and Adjusted EBITDA are not measures calculated in accordance with GAAP, as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies. (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, and deficiency payments (primarily related to deferred revenue). Distributable cash flow should not be considered an alternative to cash flows from operating activities or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity, or the ability to service debt obligations. We believe that distributable cash flow provides additional information for evaluating our ability to declare and pay distributions to unitholders. Distributable cash flow, as we define it, may not be comparable to distributable cash flow or similarly titled measures used by other corporations and partnerships