Citi 2014 MLP/Midstream

Transcription

1 Citi 2014 MLP/Midstream Infrastructure Presentation Conference Title Presentation Subtitle 9/22/2014 August 20-21, 2014 Crestwood Midstream Partners LP Crestwood Equity Partners LP

2 Forward Looking Statements The statements in this communication regarding future events, occurrences, circumstances, activities, performance, outcomes and results are forward-looking statements. Although these statements reflect the current views, assumptions and expectations of Crestwood Midstream and Crestwood Equity management, the matters addressed herein are subject to numerous risks and uncertainties which could cause actual activities, performance, outcomes and results to differ materially from those indicated. Such forward-looking statements include, but are not limited to, statements about the future financial and operating results, objectives, expectations and intentions and other statements that are not historical facts. Factors that could result in such differences or otherwise materially affect Crestwood Midstream s or Crestwood Equity s financial condition, results of operations and cash flows include, without limitation; the possibility that expected synergies will not be realized, or will not be realized within the expected timeframe; fluctuations in oil, natural gas and NGL prices; the extent and success of drilling efforts, as well as the extent and quality of natural gas volumes produced within proximity of Crestwood Midstream or Crestwood Equity assets; failure or delays by customers in achieving expected production in their natural gas projects; competitive conditions in the industry and their impact on the ability of Crestwood Midstream or Crestwood Equity to connect natural gas supplies to Crestwood Midstream or Crestwood Equity gathering and processing assets or systems; actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers; the ability of Crestwood Midstream or Crestwood Equity to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisition; changes in the availability and cost of capital; operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond Crestwood Midstream or Crestwood Equity s control; timely receipt of necessary government approvals and permits, the ability of Crestwood Midstream or Crestwood Equity to control the costs of construction, including costs of materials, labor and right-of-way and other factors that may impact either company s ability to complete projects within budget and on schedule; the effects of existing and future laws and governmental regulations, including environmental and climate change requirements; the effects of existing and future litigation; and risks related to the substantial indebtedness of either company, as well as other factors disclosed in Crestwood Midstream and Crestwood Equity s filings with the U.S. Securities and Exchange Commission. You should read filings made by Crestwood Midstream and Crestwood Equity with the U.S. Securities and Exchange Commission, including Annual Reports on Form 10-K for the year ended December 31, 2013, and the most recent Quarterly Reports and Current Reports, for a more extensive list of factors that could affect results. 2 2

3 Crestwood is Well Positioned to Create Value Two publicly traded MLPs provides strategic flexibility to enhance value ~$9.0 BB enterprise value Handling ~3 Bcf/d of natural gas;~300 MBbls/d of NGLs; 200 MBbls/d crude oil Well positioned in the Marcellus, Utica, Bakken, PRB Niobrara and Delaware Permian for long-term growth in key liquids rich/crude oil shale plays Sequential QTQ growth in Adjusted EBITDA since Inergy merger Visible 2014/15/16 growth through announced expansion projects Well capitalized for future growth investments due to $650 MM CMLP preferred equity Significant sponsor and management ownership aligned with public ownership CEQP Public Unitholders ~71% Interest CMLP Public Common and Class A Unitholders ~86% Interest First Reserve/Crestwood Holdings ~29% LP Interest 100% Non-economic GP Interest (Control) Crestwood Equity Partners LP (NYSE: CEQP) MM units outstanding ~4% LP Interest GP / IDR Ownership ~10% LP Interest Crestwood Midstream Partners LP (NYSE: CMLP) MM common units outstanding 12.0 MM Class A preferred units outstanding Operating Subsidiaries 3

4 Growing Operations in Key US Shale Plays Assets and operations divided into 4 operating regions to gain scale, reduce costs and generate commercial synergies 4 4

5 Attractive Business Profile and Contract Portfolio Northeast and Rockies primary growth regions Long-term service contracts in the best US resource plays supported by strong producer drilling economics Growth levered to Crude and NGL focused services Material upside to improving natural gas prices in Barnett and Fayetteville shale plays Attractive Growth Areas 2014E EBITDA Central 20% Rockies 25% West 4% Northeast 51% With Stable Contract Profiles 2014E Gross Margin 2014E EBITDA Gathering & Processing NGL & 38% Crude MARC I Arrow Services Barnett 39% Dry COLT Hub Storage & Transportation Inergy Barnett 23% Services Rich 2014E Gross Margin Significant contract stability Minimal direct commodity price exposure 87% of gross margin from firm and take-or-pay contracts Dry Gas Margin 31% Crude Oil & NGL Gross Margin 69% Firm Contracts 38% Short-term Contracts 13% Fixed-Fee 49% 5 5

6 Integrated Value Chain Strategy will lead to Asset Optimization and Improved Performance over time Focused on Liquids-Rich and Crude Oil Shale Plays Supply Aggregation Connectivity & Optionality Integration & Optimization Market Access Targeting investment in liquids-rich gas and crude oil shale plays Wellhead services for producer customers Pipeline gathering Trucking Compression Processing Extending services to provide flow assurance and customer flexibility Control of product from wellhead to end user Improves customer optionality Leveraging asset footprint to realize operational synergies Organic growth projects Bolt-on acquisitions Capturing additional margin/fee opportunities Providing connectivity to premier end markets Serving diverse network of demandside customers Natural gas utilities Power generators Petrochemical Crude oil refining 6 6

7 2014 Mid-Year Performance Update While starting out slower than expected, business plan taking shape Strategic assets in rich gas/crude shale plays Marcellus SW rich gas gathering/compression; NE dry gas storage/transportation Bakken leading CBR loading facility; growing core area oil gathering system PRB Niobrara leading rich gas gathering system; first new processing plant Delaware Permian converted low cost dry gas to rich gas gathering/processing Strong QTQ growth in Adjusted EBITDA and Volumes Adjusting plans to improve long-term performance 2 nd half 2014 projects drive improved coverage and resumption of distribution growth Adjusted EBITDA increased 29% since 3Q 2013 (Oct 2013 merger date) Natural gas volumes up 13% since 3Q 2013 to ~3 Bcf/d in 2Q 2014 NGL supply, logistics and storage volumes support 10-15% CAGR target Crude oil volumes increased from 83 MBbls/d in 3Q 2013 to 200 MBbls/d in 2Q 2014 Delay distribution growth until improvement in distribution coverage ratio to >1.0x $500 MM PIK preferred equity funds 2014/1H 2015 growth capital, reduces leverage ratio, enhances coverage ratio at attractive long-term cost of capital Operations management changes to enhance execution and performance Marcellus gathering/compression capacity in excess of Antero FYE volume target NE storage & transportation expansions ramp volumes by 10-15% Bakken Colt Hub R&D track expansion in service in 3Q 2014 PRB Niobrara Bucking Horse plant in service in October

8 Improving Results since 3Q 2013 Merger Sequential Consolidated LTM EBITDA growth; record natural gas and crude volumes rd Qtr (1) 4th Qtr 1st Qtr 2nd Qtr Segment EBITDA ($ MMs) Gathering and Processing (2) $ 43.2 $ 47.5 $ 48.2 $ 51.0 Segment EBITDA Storage and Transportation CMLP Operations $ 33.4 $ 33.6 $ 36.8 $ 37.8 CEQP Operations $ 1.5 $ 3.1 $ 1.2 $ (2.9) Total $ 34.9 $ 36.7 $ 38.0 $ 34.9 NGL and Crude Services (3) CMLP Operations $ 15.1 $ 20.7 $ 26.3 $ 34.7 CEQP Operations $ 16.4 $ 18.0 $ 18.7 $ 12.0 Total $ 31.5 $ 38.7 $ 45.0 $ 46.7 Total $ $ $ $ Operating Statistics CMLP Natural gas volumes (MMcf/d) 2,706 2,833 2,982 3,049 Crude oil volumes (MBbls/d) Operating Stats CEQP Supply and logistics (Gallons sold or processed, millions) (1) Following the Crestwood-Inergy merger completed in October 2013, Crestwood restated its combined financial and operating results to the beginning of the third quarter (2) All assets in the Gathering and Processing segment are owned by CMLP. Amounts exclude accruals for the Antero earn-out. (3) Excludes non-cash fair value changes on derivative contracts. 8 8

9 Improving Balance Sheet Creates Flexibility Recent Equity issuance improves credit metrics; no near-term debt maturities ($ in millions) 4th Qtr 1st Qtr 2nd Qtr CMLP Balance Sheet Profile Revolver Balance (1) $ $ $ Total Debt $ 1,870.8 $ 1,989.5 $ 1,871.2 Leverage Ratio 4.90x 5.06x 4.56x BB/Ba3 credit rating; stable outlook $300 MM Class A preferred equity issued by CMLP in 2Q 2014 Additional $200 MM Class A equity to be issued by 3Q 2015 $300 MM at-the-market program available to CMLP ~$200 MM 2H 2014 capex estimate CEQP Balance Sheet Profile Revolver Balance (1) $ $ $ Total Debt $ $ $ Targeting < 4.5x FYE 2014 and < 4.0x FYE 2015 leverage ratio at CMLP Debt Maturities Leverage Ratio 4.22x 4.23x 4.13x (1) Total CMLP Revolver capacity is $1.0 BB. Total CEQP Revolver capacity is $550 MM. 9 9

10 Strategic Equity Capital Matches Development Profile $650 million preferred equity is the right capital at the right time Significant Equity Support Strategic Rationale Key Economic Terms Execution Strategy Equity support with built-in flexibility to execute growth opportunities $500 MM commitment from Magnetar, GSO Capital and GE Capital to finance ongoing organic growth program ($300 MM funded, 12 MM units) $150 MM commitment from GE Capital to finance PRB Niobrara development (~$130 MM funded) Fulfills 2H 2014 / 2015 equity needs eliminating future execution / market risk Significantly de-levers balance sheet to long-term targets (<4.0x) Financial flexibility from PIK feature to optimally execute organic capital program Fixed cost of preferred favorable to current cost of common equity $500 MM CMLP Class A Preferred units issued at $ % fixed yield, PIK through 2Q 2017, convertible 1-for-1 beginning 2H 2017 $150 MM Crestwood Niobrara Preferred units 9% fixed yield, PIK through 4Q 2014, redeemable any time exclusively at CMLP option for cash or units at targeted minimum IRR Future capital draws timed with capital expenditures through 3Q 2015 PIK flexibility utilized to bridge between project execution and EBITDA ramp-up CMLP distribution growth to resume when coverage ratio >1.0x (targeted in 2H 2014) Prudently manage long-term distribution growth and coverage keeping in mind ultimate conversion of preferred units 10

11 2H 2014 Goals and Objectives Delivering on CMLP near-term initiatives to improve visibility FYE Targeted of long-term Result growth Complete 5 major 2014 capital projects on-time and on-budget to drive continued volume growth into 2015 Achieve revised FY 2014 guidance of $440 MM- $460 MM, a 7.7% midpoint reduction from original 2014 guidance of $460-$510 MM Improve distribution coverage to 1.0X target to resume CMLP distribution growth CEQP Improve Tres Palacios to breakeven performance and more appropriate valuation leading to possible dropdown to CMLP Marcellus gathering expansion to 875 MMcf/d; NE Storage and Transportation North-South pipeline expansion of 200 MMcf/d Bucking Horse 120 MMcf/d processing facility in PRB Niobrara COLT Hub release and departure track completes 160 MBbls/d CBR loading capacity Increase Arrow gathering system throughput to ~70 MBbls/d crude oil and ~50 MMcf/d gas capacity at FYE 2014 Expect 5%-10% QTQ sequential growth in 2H14 Adjusted EBITDA based upon current producer drilling plans 2H 2014 forecast meets coverage ratio target leading to resumption of CMLP distributions FYE Targeted Result Expect FERC abandonment ruling and settlement of local tax issues to result in $7-$10 MM annual cost savings Recent Cardinal and Lodi comparable storage transactions building momentum for valuation at Tres Palacios needed to accomplish drop-down to CMLP or third-party 11 11

12 Operations Update by Region 12 12

13 Northeast Region Marcellus / Utica Core growth opportunity in the most prolific natural gas play in history Regional Commentary (1) >20 Bcf/d and >1 MMBbl/d NGLs out of Marcellus / Utica by 2020 timeframe Distribution constraints for natural gas and NGLs require new infrastructure and export capability Significant SW Marcellus/Utica supply searching for outlets to Midwest and Gulf Coast markets 2014 projected capital spending of ~$200 MM Gathering & Compression Substantial system build-out since MMcf/d capacity by yearend 2014 >1.0 Bcf/d over next 5 years Strong producer drilling economics due to NGL upgrade Key customer: Antero Resources (1) Based on industry forecast data. Storage & Transportation Critical Northeast US storage and transportation facilities 41 Bcf fully contracted capacity >1.4 Bcf/d bi-directional transportation capacity Attractive customer mix of gas and electric utilities, producers and marketers Favorable long-term fundamentals Supply and Logistics Leading purchaser of Marcellus / Utica NGLs 2.2 MMBbls LPG storage, 462 LPG trucking units, 1,300 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 13 13

14 NE Region Southwest Marcellus Gathering Crestwood provides exclusive gathering and compression services for Antero Resources Eastern Area of Dedication in the rich-gas Southwest core of the Marcellus Shale play Antero Resources Marcellus Overview (1) $18 BB E&P company (NYSE:AR) Most active driller in Marcellus 15 rigs running ~140,000 acre Marcellus Eastern Area of Dedication (~40% of total 373,000 net acres) Current Antero Marcellus reserves 8.6 Tcfe proved; 26.4 Tcfe 3P reserves 4.7 Tcfe additional Upper Devonian Committed to ~2 Bcf/d processing and ~4 Bcf/d pipeline downstream capacity (1) Based on Crestwood internal estimate and Antero Resources June 2014 Update. Drilling with +20%-30% ROR Rich/Dry Marcellus well economics 14 14

15 NE Region Southwest Marcellus 2Q 2014 Update Marcellus Gathering and Compression Volumes Antero Crestwood 2012 Agreements 20-year, 100% fixed-fee contract with annual escalators 7 year increasing annual minimum volume commitment in East AOD Consistent growth trajectory HZ wells connected to Crestwood s system since inception July 2014 gathering volumes of ~650 MMcf/d; 570 MMcf/d compression volumes Expected 2014 exit rate of 750 MMcf/d; 63% increase from 4Q 2013 Visibility to continued volume growth ~ 1,500 drilling locations in East AOD (1); 23 wells drilled, waiting on completion (1) SSL type curve of 1.7 Bcf/1,000 leads to higher EUR, lower well cost (1) Based on Crestwood internal estimate and Antero Resources June 2014 Update. 15

16 NE Region Marcellus Storage & Transportation 41 Bcf high performance, multicycle natural gas storage Critical supply points for premium NE markets Fully contracted primarily with NE utilities including ConEd, PSEG and NJ Natural Gas >1.4 Bcf/d bi-directional flow across North/South and MARC I FERC regulated transportation assets providing firm contract services Interconnects with TGP, Transco, Millennium and DTI (Atlantic Sunrise TBD) Primary shippers include Anadarko, Chesapeake, Cabot, Southwestern and Statoil Storage Contract Profile Transportation Contract Profile Percentage Contractually Committed Percentage Contractually Committed Weighted Avg. Maturity Facility Commodity Stored Storage Capacity Stagecoach (1 ) Natural Gas 26.2 Bcf 100% 2016 Thomas Corners (1 ) Natural Gas 7.0 Bcf 100% 2015 Seneca Lake Natural Gas 1.5 Bcf 100% 2017 Steuben Natural Gas 6.3 Bcf 100% 2017 Weighted Avg. Maturity Transporation Asset Commodity Transported Transportation Capacity North/South Facilities Natural Gas MMcf/d 100% 2017 MARC I Pipeline Natural Gas MMcf/d 100% 2021 East Pipeline Natural Gas 30.0 MMcf/d 100% 2021 (1) Stagecoach and Thomas Corners are 100% contracted based on operational capacity. 16

17 NE Region Storage & Transport 2Q 2014 Update NE Marcellus dry gas supply growth driving record throughput, margins and expansion opportunities 2Q 2014 Performance Volume growth from increased NE Marcellus production 1H 2014 average throughput up 25% vs 2013 annual average Firm 82%, Interruptible 18% Basis spreads remained strong in 2Q even after winter Capturing higher percentage of spread with new interruptible capacity utilization / pricing strategy Commercial Highlights Incremental 40 MMcf/d of firm transportation on North/South and MARC I began service April 2014 NorthEast Pennsylvania Connector project (NS-1 Expansion) progressing on schedule for 1Q 2015 in-service 117 MMcf/d of firm commitments to date; ~$6.5 MM EBITDA contribution Exploring additional projects on-system in response to continued supply growth around asset base Currently connected to Access and SWN gathering systems (~ 1 Bcf/d receipt capacity) Area producers looking for additional access to market MMDth

18 Rockies Region: Bakken / PRB Niobrara Value chain strategy at work in Bakken and PRB Niobrara Regional Commentary (1) Bakken Shale the premier crude oil shale play in North America ~1.5 MMBbls/d by active rigs running in the Bakken 70% all crude Bbls currently exit basin via rail PRB Niobrara emerging crude oil play Stacked pay zones provides attractive inventory of highly economic development locations Gathering & Processing Storage & Terminalling Crude Logistics Bakken Arrow gathering systems 125 MBbl/d crude oil, 100 MMcf/d natural gas, 40 MBbl/d water Key customers: WPX, Kodiak, Halcon, XTO, QEP and Enerplus PRB Niobrara gas gathering and processing system >180 MMcf/d in 2015 Key Customers: Chesapeake and RKI Exploration (1) Based on industry forecast data. 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: Mbbl/d rail Douglas terminal and 100 Mbbl storage in Converse County, WY Key customers: Tesoro, Sunoco, Flint Hills, US Oil, Statoil, BP, CHK COLT Connector pipeline links COLT Hub and Dry Fork Terminal >40 MBbl/d truck capacity for crude oil and produced water Commenced crude supply and logistics marketing in 2Q 2014 to optimize Crestwood s Bakken assets Key customers: Arrow producers, EOG, Sinclair 2 unit trains (220 rail cars) on order, to be received 1Q

19 Rockies Region Arrow Gathering Crestwood s Bakken crude oil value chain strategy begins with Arrow Gathering $750 MM November 2013 acquisition ~150,000 acreage dedication on Fort Berthold Indian Reservation (FBIR) Long-term crude oil, rich natural gas and produced water gathering contracts with WPX, Kodiak, Halcon, XTO, QEP and Enerplus Recent Arrow producer developments WPX: 2Q 2014 oil production results up 21% over 1Q 2014 Down-spacing creating 10-year drilling inventory at 2014 rate Kodiak: Whiting announced acquisition of Kodiak in July 2014; expected to ramp development activities Halcon: Down-spacing tests indicate potential for up to 16 wells per DSU QEP: Strong 2Q 2014 well results and lower LOE on FBIR 19 19

20 Rockies Region - COLT Hub and Connector COLT Hub links Bakken crude supply to prime markets; currently the leading rail terminal in North Dakota by volume Sourcing Capacity Storage Capacity Takeaway Capacity >290,000 Bbls/d COLT Connector Tesoro pipeline Banner pipeline Meadowlark pipeline Truck deliveries 1.2 MM Bbls (working cap) Largest storage position in the basin Tradable market Buyers and sellers Point of liquidity Creditworthy counterparties >350,000 Bbls/d Rail loading to West/East Coast COLT Connector Tesoro pipeline Enbridge pipeline ETP Bakken project 20 20

21 Rockies Region Arrow/COLT 2Q 2014 Update CMLP handled 200 MBbls/d in 2Q via gathering, trucking, rail loading and pipe Arrow Gathering Update Increased Q volumes following severe winter weather in 1Q 2014 Arrow Gathering 36 wells connected 2Q 2014 compared to 9 in Q1 2014; expect 43 additional wells to be connected 2H 2014 Forecasted Q performance of ~$20 MM is on-target with original acquisition expectation COLT Hub & Connector Update Completion of additional R&D track in Q expected to increase COLT CBR loadings to ~160 MBbls/d COLT Connector 3Q QTD at 35 MBbls/d vs 25 MBbls/d in 2Q 2014 Contracted for 10 MBbls/d capacity on Tesoro Logistics High Plains expansion to directly connect Arrow and COLT COLT Hub & Connector 21 21

22 Rockies Region PRB Niobrara Expanding gathering and processing system in the Powder River Basin (PRB) to serve increasing production Jackalope Gas Gathering 50/50 JV with Access Midstream 20-year cost-of-service agreement with Chesapeake, RKI Exploration and Production and China National Offshore Oil Corporation 311,000 acre dedication Current Q volumes ~ 55 MMcf/d 36 wells drilled, waiting on completion due to capacity constraints 120 MMcf/d Bucking Horse processing plant to be completed in 4Q 2014; will alleviate capacity constraints Recent Jackalope Developments CHK and RKI announced agreement to exchange acreage and interests in Jackalope dedication Jackalope Volumes Increases CHK interest by 66,000 acres and net WI to 79% >2 Billion BOE potential recoverable gross resource Announced increase in operated rigs to 7-9 in

23 Central Region Barnett, Permian, Fayetteville, Granite Wash / Haynesville & Gulf Coast Storage Emerging growth from Permian Delaware basin Regional Commentary Current gas price and forward strip support development in core dry gas operating areas Emerging Delaware Permian Basin with producer activity focused on Wolfcamp, Bone Spring development in SE New Mexico and West Texas Increasing Eagle Ford production, emerging LNG exports, & US exports to Mexico provide potential opportunities for South TX storage Barnett Fayetteville Permian Delaware Granite Wash / Haynesville Tres Palacios (1) Gathering and processing in Barnett core acreage Primary customers: Quicksilver Resources and Devon Energy 100% feebased contracts through 2024 Blue-chip producers including BHP, BP and XTO Phase II expansion to 30 MMcf/d processing capacity completed early Q Potential Phase III expansion to 120 MMcf/d (Delaware Ranch) 36 MMcf/d gathering and processing capacity in the Granite Wash Haynesville gathering and treating assets provide upside potential as dry gas drilling resumes 38.4 Bcf of working gas capacity Southern most highdeliverability gas storage facility in Texas Connected to 10 pipeline systems serving multiple U.S. demand markets (1) Wholly-owned subsidiary of CEQP 23

24 Central Region Barnett Shale 2Q 2014 Update Resumption of Growth in the Barnett Shale Recent Quicksilver (KWK) / Tokyo Gas well completions show improved performance in Barnett dry area Texas Motor Speedway wells 30-day IP rate ~60% higher than average type curve Village Creek well with 25% higher 90- day IP rate KWK development plans currently include ~34 new well completions in 2014 vs Crestwood budget of ~25 wells 2Q 2014 Alliance and Lake Arlington volumes increased 24% from 1Q 2014 Barnett Gathering KWK well work-over program reduced Barnett decline rates New incentive fee structure to drive further rich-gas development at Cowtown 24 24

25 Central Region Delaware Permian 2Q 2014 Update Completed Willow Lake Gathering & Processing Facility in July MMcf/d cryogenic plant 10-year, fixed-fee gathering and processing agreement with Legend Production Holdings; 107,000 acre AMI Legend to kick off development program in 3Q 2014 Potential Phase III - Delaware Ranch Gas Project Developing large scale centralized 120 MMcf/d+ processing facility and pipeline system Target production from Eddy, Lea, Culberson, Reeves and Loving counties In-service date YE 2015 / early 2016 Potential Phase IV Crude trucking, pipeline gathering & transportation Water gathering & disposal NM TX 25

26 Central Region Tres Palacios 2Q 2014 Update Mexico Plans 42 Gas-Fired Power Projects Near-Term Initiatives for Tres Palacios Potential sale of a minority interest in Tres Palacios to a third-party with a simultaneous drop-down of the remaining interest to CMLP Discussions with strategic partners that could improve near-term performance while preserving longer-term upside as storage market conditions improve > 4.0 Bcf/d of Nearby LNG Export Facilities Drop-down to CMLP provides continued CEQP exposure to the upside through IDRs and distributions (versus a 100% third-party sale at low market prices) Recent Lodi and Cardinal storage transactions at $3.4 MM to $4.2 MM per Bcf of working capacity indicate Tres Palacios valuation of $120 MM to $160 MM Corpus Christi Note: Tres Palacios is a wholly-owned subsidiary of CEQP 26

27 NGL Supply, Logistics, Transportation CEQP growing business segment instrumental in executing Crestwood s wellhead-to-burner tip operating model Leading purchaser of Marcellus / Utica liquids Among largest LPG truck fleets in the US Expanding customer relationships with NGL volumes marketed of ~350 MBbl/d during 2013/2014 winter period Strong Bath storage utilization / positive momentum for Watkins Glen approval West Coast business positioned for future growth as Monterrey Shale develops Contracted for 10 MBbl/d Mariner East II pipeline capacity starting in

28 Long-Term Growth Drivers Premier Shale footprint provides attractive backlog of organic projects; successful execution at 5.0x to 7.0x all-in build multiples drives substantial future growth Arrow Midstream crude oil, natural gas and produced water gathering COLT Hub Expansion I Marcellus Shale gathering & compression development for Antero Niobrara Shale gathering and processing development for Chesapeake and RKI Exploration Permian Basin gathering and processing at Willow Lake Watkins Glen NGL Storage ~$1.2 BB backlog of identified opportunities currently under stages of development COLT Hub Expansion II NE Marcellus transportation expansion Third Party M&A Bakken Shale expansion opportunities ~$6.0 BB of identified incremental expansion opportunities currently under evaluation / negotiation Permian Basin organic development opportunities Rail Terminal Expansion opportunities (Canada, Douglas expansion, Bakersfield) Niobrara Shale crude oil expansion opportunities NGL / crude oil marketing and trucking expansions / bolt-on acquisitions Tres Palacios expansion oportunities (Agua Dulce Header, Freeport LNG Lateral, Olefin Storage, NGL Pipeline) Commonwealth pipeline Marcellus Shale (SW Rich Core) / Utica expansion opportunities Drop-Down of CEQP operational assets

29 Key Investor Highlights Financial stability with visible growth through execution of value chain strategy Footprint covers premier US natural gas, liquidsrich and crude oil shale plays Growth underpinned by Marcellus/Utica, Bakken, PRB Niobrara and Permian Basin Material upside leverage to natural gas price improvements Merger integration complete, optimization strategy underway Expanding capital investment opportunity across value chain Expands margins to drive increased returns on capital Stable cash flow from fixed-fee and take-or-pay contracts Dual CMLP and CEQP public currency provides optionality for transformational growth Improving financial flexibility to execute growth objectives 29 29

30 Non GAAP Reconciliations 30 30

31 Crestwood Midstream Partners LP Non-GAAP Reconciliations CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.) Segment Data (in millions) (unaudited) Gathering and Processing nd Qtr 1st Qtr 4th Qtr 3rd Qtr Operating revenues $ 83.4 $ 79.5 $ 76.6 $ 71.1 Costs of product/services sold Operations and maintenance expense Goodwill impairment (4.1) Gain on long-lived assets Loss on contingent consideration (6.5) (2.1) (31.4) Earnings (loss) from unconsolidated affiliate (0.6) (0.4) EBITDA $ 44.5 $ 46.1 $ 16.1 $ 43.2 Significant items impacting EBITDA: Loss on contingent consideration Adjusted EBITDA $ 51.0 $ 48.2 $ 47.5 $ 43.2 Storage and Transportation Operating revenues $ 45.4 $ 44.3 $ 42.5 $ 42.1 Costs of product/services sold Operations and maintenance expense Gain on long-lived assets 0.6 EBITDA and Adjusted EBITDA $ 37.8 $ 36.8 $ 33.6 $ 33.4 NGL and Crude Services Operating revenues $ $ $ $ 26.9 Costs of product/services sold Operations and maintenance expense Loss from unconsolidated affiliate (0.9) (0.4) (0.2) EBITDA and Adjusted EBITDA $ 34.7 $ 26.3 $ 20.7 $ 15.1 Total Segment Adjusted EBITDA $ $ $ $ 91.7 Significant items impacting EBITDA (1) (6.5) (2.1) (31.4) Total Segment EBITDA $ $ $ 70.4 $ 91.7 Corporate (21.3) (24.1) (36.7) (25.2) EBITDA $ 95.7 $ 85.1 $ 33.7 $ 66.5 (1) Significant items impacting EBITDA represents loss on contingent consideration 31

32 Crestwood Midstream Partners LP Non-GAAP Reconciliations CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.) Reconciliation of Non-GAAP Financial Measures (in millions) (unaudited) EBITDA nd Qtr 1st Qtr 4th Qtr 3rd Qtr Net income (loss) $ 11.7 $ 5.5 $ (42.3) $ 11.6 Interest and debt expense, net Provision (benefit) for income taxes (0.3) 0.3 Depreciation, amortization and accretion EBITDA (1) $ 95.7 $ 85.1 $ 33.7 $ 66.5 Significant items impacting EBITDA: Non-cash equity compensation expense Gain on long-lived assets (1.1) (0.5) (1.0) (4.4) Goodwill impairment 4.1 Loss on contingent consideration (Earnings) loss from unconsolidated affiliates, net (0.3) 0.4 Adjusted EBITDA from unconsolidated affiliates Significant transaction related costs and other items Adjusted EBITDA (1) $ $ 98.9 $ 90.9 $ 85.3 (1) EBITDA is defined as income bef ore income t axes, plus net int erest and debt expense, and depreciation, amortization and accretion expense. In addition, Adjust ed EBITDA considers t he adjust ed earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates for our proportionat e share of their depreciat ion and int erest, the impact of certain signif icant it ems, such as non-cash equity compensation expenses, gains and impairments of long-lived asset s and goodwill, third party costs incurred related to potential and completed acquisit ions, loss on contingent considerat ion, and ot her t ransactions ident ified in a specific reporting period. EBITDA and Adjusted EBITDA are not measures calculat ed in accordance wit h account ing principles generally accepted in t he United St ates of America (GAAP), as they do not include deduct ions f or items such as depreciat ion, amortization and accret ion, int erest and income t axes, which are necessary t o maint ain our business. EBITDA and Adjusted EBITDA should not be considered an alt ernat ive to net income, operating cash flow or any other measure of f inancial 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. 32

33 Crestwood Equity Partners LP Non-GAAP Reconciliations Gathering and Processing CRESTWOOD EQUITY PARTNERS LP (FORMERLY INERGY, L.P.) Segment Data (in millions) (unaudited) nd Qtr 1st Qtr 4th Qtr 3rd Qtr Operating revenues $ 83.4 $ 79.5 $ 76.6 $ 71.1 Costs of product/services sold Operations and maintenance expense Goodwill impairment (4.1) Gain on long-lived assets Loss on contingent consideration (6.5) (2.1) (31.4) Earnings (loss) from unconsolidated affiliate (0.6) (0.4) EBITDA $ 44.5 $ 46.1 $ 16.1 $ 43.2 Significant items impacting EBITDA: Loss on contingent consideration Adjusted EBITDA $ 51.0 $ 48.2 $ 47.5 $ 43.2 Storage and Transportation Operating revenues $ 47.8 $ 51.0 $ 49.1 $ 48.8 Costs of product/services sold Operations and maintenance expense Gain on long-lived assets 0.6 EBITDA and Adjusted EBITDA $ 34.9 $ $ 34.9 NGL and Crude Services Operating revenues $ $ $ $ Costs of product/services sold Operations and maintenance expense Gain (loss) on long-lived assets 0.1 (0.1) Loss from unconsolidated affiliate (0.9) (0.4) (0.2) EBITDA $ 43.8 $ 55.7 $ 39.3 $ 21.8 Significant items impacting EBITDA: Change in fair value of commodity inventory-related derivative contracts 2.9 (10.7) (0.6) 9.7 Adjusted EBITDA $ 46.7 $ 45.0 $ 38.7 $ 31.5 Total Segment Adjusted EBITDA $ $ $ $ Significant items impacting EBITDA (1) (9.4) 8.6 (30.8) (9.7) Total Segment EBITDA $ $ $ 92.1 $ 99.9 Corporate (24.0) (27.8) (40.6) (29.1) EBITDA $ 99.2 $ $ 51.5 $ 70.8 (1) Significant items impacting EBITDA represents loss on contingent consideration and change in fair value of commodity inventory-relat ed derivat ive cont ract s 33

34 Crestwood Equity Partners LP Non-GAAP Reconciliations CRESTWOOD EQUITY PARTNERS LP (FORMERLY INERGY, L.P.) Reconciliation of Non-GAAP Financial Measures (in millions) (unaudited) EBITDA nd Qtr 1st Qtr 4th Qtr 3rd Qtr Net income (loss) $ (4.8) $ 13.2 $ (42.1) $ (7.9) Interest and debt expense, net Provision (benefit) for income taxes (0.2) 0.5 Depreciation, amortization and accretion EBITDA (1) $ 99.2 $ $ 51.5 $ 70.8 Significant items impacting EBITDA: Non-cash equity compensation expense Gain on long-lived assets (1.2) (0.5) (0.9) (4.4) Goodwill impairment 4.1 Loss on contingent consideration (Earnings) loss from unconsolidated affiliates, net (0.3) 0.4 Adjusted EBITDA from unconsolidated affiliates Change in fair value of commodity inventory-related derivative contracts 2.9 (10.7) (0.6) 9.7 Significant transaction related costs and other items Adjusted EBITDA (1) $ $ $ $ 99.9 (1) EBITDA is def ined as income bef ore income t axes, plus net interest and debt expense, and depreciation, amortizat ion and accret ion expense. In addition, Adjust ed EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates f or our proportionate share of their depreciat ion and interest, t he impact of certain significant items, such as non-cash equity compensat ion expenses, gains and impairments of long-lived asset s and goodwill, third party costs incurred related to potential and completed acquisit ions, loss on cont ingent considerat ion, and ot her t ransact ions identif ied in a specific reporting period. EBITDA and Adjust ed EBITDA are not measures calculat ed in accordance with accounting principles generally accept ed in t he United St ates of America (GAAP), as t hey do not include deduct ions f or items such as depreciation, amortizat ion and accret ion, int erest and income taxes, which are necessary t o maintain our business. EBITDA and Adjusted EBITDA should not be considered an alt ernat ive to net income, operat ing cash f low or any other measure of f inancial performance present ed 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. 34

35 Crestwood Midstream Partners LP Non-GAAP Reconciliations CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.) Full Year 2014 Adjusted EBITDA and Distributable Cash Flow Guidance Reconciliation to Net Income (in millions) (unaudited) Net income $90 - $110 Interest and debt expense, net $120 Depreciation, amortization and accretion $230 Adjusted EBITDA $440 - $460 Cash interest expense (a) ($100) Maintenance capital expenditures (b) ($20) Distributable cash flow attributable to CMLP $320 - $340 (a) Cash interest expense is book interest expense less amortization of deferred financing costs plus bond premium amortization. (b) Maintenance capital expenditures are defined as those capital expenditures which do not increase operating capacity or revenues from existing levels

36 Crestwood Equity Partners LP Non-GAAP Reconciliations CRESTWOOD EQUITY PARTNERS LP (FORMERLY INERGY, L.P.) Full Year 2014 Adjusted EBITDA and Distributable Cash Flow Guidance Reconciliation to Net Income (in millions) (unaudited) Net income $115 - $140 Interest and debt expense, net $135 Depreciation, amortization and accretion $240 Adjusted EBITDA $490 - $515 Cash interest expense (a) ($115) Maintenance capital expenditures (b) ($25) Public Crestwood Midstream LP unitholders interest in CMLP distributable cash flow (c) ($285) - ($305) Distributable cash flow attributable to CEQP (d) $65 - $70 (a) Cash interest expense less amortization of deferred financing costs plus bond premium amortization plus or minus fair value adjustment of interest rate swaps. (b) Maintenance capital expenditures are defined as those capital expenditures which do not increase operating capacity or revenues from existing levels. (c) Crestwood Midstream distributable cash flow less incentive distributions paid to the general partner and the public LP ownership interest in Crestwood Midstream. (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 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