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Investor presentation march 2016 v final

The document provides an overview of Crestwood Midstream Partners LP and Crestwood Equity Partners LP. It discusses key investor highlights including 2016 outlook and adjusted EBITDA guidance of $490-520 million. It also summarizes the company's capital structure, debt maturity profile, and operational updates in core areas like the Bakken shale play.

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Presentation Title Presentation Subtitle Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ Presentation Title Presentation Subtitle Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ Presentation Title Presentation Subtitle Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ 2/29/16 Presentation Title Presentation Subtitle Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ Presentation Title Presentation Subtitle Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ Connections for America’s Energy ™ ™ Investor Presentation March 2016
Connections for America’s Energy ™ ™ ™ ™ ™ ™ 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 Contact Information Corporate Headquarters 700 Louisiana Street Suite 2550 Houston, TX 77002 (1)  Market price as of 2/24/2016. (2)  Unit count and balance sheet data as of 12/31/2015. Crestwood Equity Partners LP NYSE Ticker CEQP Market Capitalization ($MM)(1,2) $617 Enterprise Value ($MM)(2) $3,724 Annualized Distribution $5.50 Investor Relations investorrelations@crestwoodlp.com (713) 380-3081
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Key Investor Highlights 3
Connections for America’s Energy ™ ™ ™ ™ ™ ™ •  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 fixed-fee and take-or-pay 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 Key Investor Highlights 4
Connections for America’s Energy ™ ™ ™ ™ ™ ™ 2016 Outlook 5 Marketing, Supply & Logistics •  Adjusted EBITDA: $95MM - $100MM •  Flat cash flows in 2016 •  Marketing business supported by hard assets and long-term relationships 2016E Adjusted EBITDA of $490 million to $520 million; ~60% of the business flat to up in 2016 2016E Segment Cash Flow Reduced CAPEX Gathering & Processing 43% Storage & Transportation 40% Marketing Supply & Logistics 17% 2016E Adj. EBITDA Guidance $490MM - $520MM Segment Outlook Storage & Transportation •  Adjusted EBITDA: $225MM - $235MM •  Volumes trending flat to up 5% in 2016 •  NE S&T and COLT Hub take-or- pay contracts drive stable cash flow Gathering & Processing •  Adjusted EBITDA: $235MM - $250MM •  Volumes trending 15%-20% lower in 2016 •  2016E cash flow forecasts include conservative forecasts for Barnett and PRB Niobrara assets (1) Excludes corporate G&A expenses of $65 million. Segment Contribution (1) (1) ($MM) ($MM)
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Repositioning Crestwood in 2015/16 6 Corporate Structure 69.1 MM common units 62.1 MM preferred units In a challenging market, Crestwood continues to take actionable steps to improve its positioning and broaden its investment appeal No IDRs Key Items •  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 projectsü üSimplification Merger Cost Cutting / Reduced Capex •  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 •  On September 30, 2015, closed merger between Crestwood Equity and Crestwood Midstream •  Improved cost of capital by eliminating IDRs ü ü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 Streamlined Business
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Existing Scale and New Investment Opportunities in the Right Places 7 Bakken •  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 Crestwood’s crude oil and natural gas operations are situated in the highest returning shale plays Marcellus
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Fixed-Fee Contracts Provide Safety Net 8 Contract Portfolio 2016E EBITDA Variable Rate Contracts 8% Take-or-Pay and Fixed-Fee Contracts 92% ü  92% of 2016E EBITDA from take-or-pay and fixed-fee contracts ü  Significant cash flow contribution protected from commodity change and volume reduction 55% of EBITDA is guaranteed through take- or-pay contracts YoY Margin Growth Despite Commodity Prices Adjusted EBITDA Crude Oil and Natural Gas Prices Crude Oil Natural Gas Y-o-Y Adj. EBITDA Growth: 6.4% Crude Oil decline: (61%) Natural Gas decline: (45%)
Connections for America’s Energy ™ ™ ™ ™ ™ ™ $299 $253 $100 $150 $200 $250 $300 $350 4Q14  Annualized FY  2015 Expense / Fixed Charge Reduction Strategy 9 ($MM) Total Expenses Total Expenses by Segment Total Expenses Reduced by 15% 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; 2016+ run-rate savings of >$35MM •  Results drive greater profitability in the current industry environment •  Increased efficiency without sacrificing customer service, safety or compliance •  Simplification adds to coverage improvement through fixed charge elimination (1) Adjusted G&A is defined as general and administrative expenses less unit-based compensation charges and significant transaction and environmental related costs and other items. (1) 4Q14   Annualized FY  2015 ($MM) Total   Expenses Total   Expenses Variance Gathering  &  Processing $109 $89 ($20) Storage  &  Transportation $27 $32 $5 Marketing,  Supply  &  Logistics $79 $70 ($9) Adjusted  G&A $84 $63 ($21) Total  Expenses $299 $253 ($46) %-­‐Change (15.4%)
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Consistent Operating and Financial Results 10 (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 Q4 2015 shut-in and weather impacts. Adjusted EBITDA and Margins(1) Natural Gas Volumes Improving financial performance demonstrates strong baseline cash flow; Q4 2015 strongly impacted by warm weather (2) Crude Oil Volumes $18.0 Q415 miss of $18mm attributable to unseasonably warm weather; depressed NE regional pricing (3) $118.5
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Capital Structure 11 Capitalization •  Strong liquidity position –  1.5 billion revolving credit facility –  ~50% drawn RCF balance •  No near-term maturities; attractive long-term capital –  $1.8 billion senior notes; 6.00%-6.25% coupon –  Nearest maturity 2020 •  Ample covenant cushion •  Strong fixed charge coverage •  No need to access capital markets in 2016 Crestwood has ample liquidity to execute business plan in challenging market Debt Maturities No near-term debt maturities RCF 6% Notes 6.125% Notes 6.25% Notes ($  millions) 12/31/2015 Cash $0.5 Total  Debt $2,540.3 Total  Partners'  Capital $2,946.9 Total  Capitalization $5,487.2 Credit  &  Liquidity  Stats Total  Leverage  Ratio 4.75x Senior  Secured  Leverage  Ratio 1.37x Total  Leverage  Covenant 5.50x Senior  Secured  Leverage  Covenant 3.75x Summary ($MM)
Connections for America’s Energy ™ ™ ™ ™ ™ ™ •  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 Q4 2015 •  BlueStone Natural Resources emerged as winner bidder; Must close by March 2016 •  Binding agreement in place with the back up bidder •  Long-term resolution likely by Q2 2016 Manageable Counterparty Risk 12 Crestwood has a diverse customer portfolio; producer counterparty risk manageable in the event of continued market deterioration 2016E Cash Flow ExposureCounterparty Risk Overview Manageable counterparty risk in 2016 (1) (1) Represents total annual cash flow contributions from higher risk counterparties.
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Core Operations Update 13
Connections for America’s Energy ™ ™ ™ ™ ™ ™ •  Bakken has continued to produce sufficient producer wellhead returns – 94% of rigs operating in four counties (McKenzie, Williams, Mountrail, Dunn) – ~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 10-12 days •  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 Bakken Producers Remain Active Around Crestwood’s Assets 14 Permits Filed in Last 120 Days Permits Heat Map By Arrow Producers 9 2 38 48 Source: North Dakota Industrial Commission As of February 24, 2016.
Connections for America’s Energy ™ ™ ™ ™ ™ ™ 0 25 50 75 100 125 Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15 Gathering  Volumes  (Mboe/d) Crude  Oil Natural  Gas Water $0 $5 $10 $15 $20 $25 Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15 Adjusted  EBITDA  ($MM) Bakken Arrow Gathering System 15 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 aid- in-construction lateral requests •  Lower operating cost in 2015 improves margin •  Arrow volumes have increased 14% year-over-year and 76% since Q1 2014 •  Arrow system connected to COLT Hub through Tesoro and Hiland crude oil pipelines Long-Term Outlook •  >1,200 estimated future drilling locations •  45-55 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 (1) Natural gas converted to barrels at 6:1. Arrow Adjusted EBITDA Increasing Gathering Volumes from Continued Drilling Activity (1) 142% Growth 76% Growth
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Bakken COLT Hub and Connector 16 COLT Hub is the leading Bakken CBR facility linking Bakken crude supply to prime refinery markets Source: Genscape February 2016; EIA. 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 Top 5 Bakken CBR Facilities COLT Hub Customers Maintaining Market Share Going into 2016 BakkenPipeline/Crude-by-Rail(Bbls/d) •  Pipeline and CBR remain >1,000 Bbls/d −  67% Pipeline / 33% CBR •  Crestwood’s COLT Hub currently ~25% CBR market share
Connections for America’s Energy ™ ™ ™ ™ ™ ™ $10 $15 $20 $25 $30 $35 $40 $45 Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15 Adjusted  EBITDA  ($MM) 17 NE Marcellus Storage and Transportation Summary 200 MMcf/d North-South Expansion Wilmot Receipt Point MARC I Transco Meter Long-Term Outlook •  ~3.5 Bcf/d Marcellus dry gas supply access through upstream gathering and producer connections •  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 Critical infrastructure for NE demand markets (NYC) provide significant level of contracted cash flows and growth opportunities Storage •  Irreplaceable storage position with top East Coast utility customers: Con Ed, NJNG, NYSEG, PSEG •  ~41 Bcf of natural gas storage; 99% subscribed Transportation •  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 Consistent Cash Flow from Take-or-Pay Contracts
Connections for America’s Energy ™ ™ ™ ™ ™ ™ •  20-year, fixed-fee contracts for gathering and compression services with Antero Resources −  ~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 SW Marcellus Gathering & Compression 18 Long-term fee-based contracts in southwest Marcellus core production window Summary Markwest Sherwood Processing Greenbrier Rich Gas Area Crestwood Dedication Area Antero Midstream Dedication Area 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 sales1 −  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 (1)  See November Antero Resources company presentation.
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Delaware-Permian: Reservoir Overview 19 •  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 Wolfcamp Western Frontier Bone Spring Western Fairway Wolfcamp Reeves Core NorthernDelawareSouthernDelaware Source: Wood Mackenzie May playbook. Willow Lake 3-Stream Gathering Project Summary Delaware-Permian Map Crestwood’s developing position is located in the core of the Wolfcamp and Bone Spring formations Wolfcamp Bone Spring •  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 •  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
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Delaware-Permian: Expansion Projects 20 Crestwood is actively expanding its footprint in the heart of the Delaware Permian Basin, the most active shale play in the US Other Long-Term Opportunities •  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-Stream Gathering System Proposed Expansion Map •  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 −  ~180 mile, 20” pipeline, 200 MBbls/d of capacity 2 3 3 2 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 1 3 Willow Lake Delta Pipeline Orla Terminal 3-Stream Gathering System
Connections for America’s Energy ™ ™ ™ ™ ™ ™ •  Leading marketer of Marcellus/Utica NGLs •  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 through Marcus Hook, PA •  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 21 Crestwood NGL Assets and Services Servicing Blue Chip Customers 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 Marcellus/Utica NGL Logistics Platform Marcus Hook NGL Exports Bath NGL Storage Seymour NGL Storage 60 15 34 88 75 218 2015E = 490 MBPD UEO-CHK Dominion Blue Racer Crestwood BP Markwest
Connections for America’s Energy ™ ™ ™ ™ ™ ™ The Crestwood Investment Opportunity No Incentive Distribution Rights 22 1 Substantial Expense / Fixed Charge Reduction 2 Solid Financial Results year-over-year 3 Diversified / Balanced Portfolio 4 Fixed Fee / Firm Contract Profile 5 Current Valuation Not Indicative of Business Fundamentals Leveraged to Volume Growth with Commodity Price Upside 1 Cost of Capital Improvement 2 Expansion Opportunities in Delaware Permian Basin and NE S&T 3 Strengthened Balance Sheet in 2016 4 Attractive Valuation Entry Point 5 Execution Drives Significant Upside Return Opportunity Strong Liquidity / No near-term maturities 6
Connections for America’s Energy ™ ™ ™ ™ ™ ™ Non-GAAP Reconciliations 23
Connections for America’s Energy ™ ™ ™ ™ ™ ™ CEQP Non-GAAP Reconciliations 24 (in millions, unaudited)   4th Qtr 3rd Qtr 2nd Qtr 1st Qtr 4th Qtr 3rd Qtr 2nd Qtr 1st Qtr EBITDA 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 35.4 35.7 35.4 33.6 31.3 31.5 32.6 31.7 Loss on modification/extinguishment of debt 0.2 2.7 17.1 — — — — — Provision (benefit) for income taxes (1.2) (0.3) (0.3) 0.4 — 0.1 0.2 0.8 Depreciation, amortization and accretion 75.6 75.5 74.8 74.2 76.1 71.7 71.2 66.3 EBITDA (a) (1,292.4)$ (509.8)$ (169.0)$ 126.3$ 76.7$ 115.2$ 99.2$ 112.0$ Significant items impacting EBITDA: Unit-based compensation charges 4.1 3.9 5.9 5.8 4.9 4.8 6.2 5.4 (Gain) loss on long-lived assets, net 817.3 2.3 0.6 1.0 2.7 0.9 (1.2) (0.5) Goodwill impairment 515.4 609.9 281.0 — 48.8 — — — Loss on contingent consideration — — — — — — 6.5 2.1 (Earnings) loss from unconsolidated affiliates, net 72.0 (2.8) (5.0) (3.4) (0.6) (0.3) 1.5 0.1 Adjusted EBITDA from unconsolidated affiliates, net 6.9 6.2 5.7 6.5 2.9 1.9 0.4 1.7 Change in fair value of commodity inventory-related derivative contracts (5.3) 8.1 1.5 1.1 (3.5) 1.0 2.9 (10.7) Significant transaction and environmental related costs and other items 0.9 15.7 12.4 4.6 0.8 5.4 2.2 6.5 Adjusted EBITDA (a) 118.9$ 133.5$ 133.1$ 141.9$ 132.7$ 128.9$ 117.7$ 116.6$ Distributable Cash Flow Adjusted EBITDA (a) 118.9 133.5 133.1 141.9 132.7 128.9 117.7 116.6 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 1.2 0.3 0.3 (0.4) — (0.1) (0.2) (0.8) Deficiency payments (0.9) (0.6) 5.7 (0.6) 3.5 2.3 3.8 1.1 Distributable cash flow attributable to CEQP 75.7$ 95.4$ 101.9$ 103.7$ 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)        C as h  interes t  expens e  les s  amortization  of  deferred  financing  cos ts  plus  bond  premium  amortization  plus  or  minus  fair  value  adjus tment  of  interes t  rate  s waps .   (c)        Maintenance  capital  expenditures  are  defined  as  thos e  capital  expenditures  which  do  not  increas e  operating  capacity  or  revenues  from  exis ting  levels .   (d)          D is tributable  cas h  flow  is  defined  as  A djus ted  E B IT D A ,  les s  cas h  interes t  expens e,  maintenance  capital  expenditures ,  income  taxes ,  and  deficiency  payments  (primarily  related  to  deferred  revenue).  D is tributable  cas h  flow  s hould  not  be  cons idered  an  alternative  to  cas h  flows  from  operating   activities  or  any  other  meas ure  of  financial  performance  calculated  in  accordance  with  generally  accepted  accounting  principles  as  thos e  items  are  us ed  to  meas ure  operating  performance,  liquidity,  or  the  ability  to  s ervice  debt  obligations .  We  believe  that  dis tributable  cas h  flow  provides  additional   information  for  evaluating  our  ability  to  declare  and  pay  dis tributions  to  unitholders .  D is tributable  cas h  flow,  as  we  define  it,  may  not  be  comparable  to  dis tributable  cas h  flow  or  s imilarly  titled  meas ures  us ed  by  other  corporations  and  partners hips .   20142015 CRESTWOOD EQUITY PARTNERS LP Reconciliation of Non-GAAP Financial Measures (a)      E B IT D A  is  defined  as  income  before  income  taxes ,  plus  debt-­‐related  cos ts  (net  interes t  and  debt  expens e  and  los s  on  modification/extinguis hment  of  debt)  and  depreciation,  amortization  and  accretion  expens e.  In  addition,  A djus ted  E B IT D A  cons iders  the  adjus ted  earnings  impact  of  our   uncons olidated  affiliates  by  adjus ting  our  equity  earnings  or  los s es  from  our  uncons olidated  affiliates  for  our  proportionate  s hare  of  their  depreciation  and  interes t.  A djus ted  E B IT A  als o  cons iders  the  impact  of  certain  s ignificant  items ,  s uch  as  unit-­‐bas ed  compens ation  charges ,  gains  and   impairments  of  long-­‐lived  as s ets  and  goodwill,  gains  and  los s es  on  acquis ition-­‐related  contingencies ,  third  party  cos ts  incurred  related  to  potential  and  completed  acquis itions ,  certain  environmental  remediation  cos ts ,  certain  cos ts  related  to  our  2015  cos t  s avings  initiatives ,  the  change  in  fair  value  of   commodity  inventory-­‐related  derivative  contracts ,  and  other  trans actions  identified  in  a  s pecific  reporting  period.  T he  change  in  fair  value  of  commodity  inventory-­‐related  derivative  contracts  is  cons idered  in  determining  A djus ted  E B IT D A  given  that  the  timing  of  recognizing  gains  and  los s es  on  thes e   derivative  contracts  differs  from  the  recognition  of  revenue  for  the  related  underlying  s ale  of  inventory  that  thes e  derivatives  relate  to.  C hanges  in  the  fair  value  of  other  derivative  contracts  is  not  cons idered  in  determining  A djus ted  E B IT D A  given  the  relatively  s hort-­‐term  nature  of  thos e  derivative   contracts .  E B IT D A  and  A djus ted  E B IT D A  are  not  meas ures  calculated  in  accordance  with  GA A P ,  as  they  do  not  include  deductions  for  items  s uch  as  depreciation,  amortization  and  accretion,  interes t  and  income  taxes ,  which  are  neces s ary  to  maintain  our  bus ines s .  E B IT D A  and  A djus ted  E B IT D A   s hould  not  be  cons idered  an  alternative  to  net  income,  operating  cas h  flow  or  any  other  meas ure  of  financial  performance  pres ented  in  accordance  with  GA A P .  E B IT D A  and  A djus ted  E B IT D A  calculations  may  vary  among  entities ,  s o  our  computation  may  not  be  comparable  to  meas ures  us ed  by   other  companies .  

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Investor presentation march 2016 v final

  • 1.
    Presentation Title Presentation Subtitle CrestwoodMidstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ Presentation Title Presentation Subtitle Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ Presentation Title Presentation Subtitle Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ 2/29/16 Presentation Title Presentation Subtitle Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ Presentation Title Presentation Subtitle Crestwood Midstream Partners LP Crestwood Equity Partners LP Connections for America’s Energy ™ ™ Connections for America’s Energy ™ ™ Investor Presentation March 2016
  • 2.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ 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 Contact Information Corporate Headquarters 700 Louisiana Street Suite 2550 Houston, TX 77002 (1)  Market price as of 2/24/2016. (2)  Unit count and balance sheet data as of 12/31/2015. Crestwood Equity Partners LP NYSE Ticker CEQP Market Capitalization ($MM)(1,2) $617 Enterprise Value ($MM)(2) $3,724 Annualized Distribution $5.50 Investor Relations investorrelations@crestwoodlp.com (713) 380-3081
  • 3.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Key Investor Highlights 3
  • 4.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ •  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 fixed-fee and take-or-pay 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 Key Investor Highlights 4
  • 5.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ 2016 Outlook 5 Marketing, Supply & Logistics •  Adjusted EBITDA: $95MM - $100MM •  Flat cash flows in 2016 •  Marketing business supported by hard assets and long-term relationships 2016E Adjusted EBITDA of $490 million to $520 million; ~60% of the business flat to up in 2016 2016E Segment Cash Flow Reduced CAPEX Gathering & Processing 43% Storage & Transportation 40% Marketing Supply & Logistics 17% 2016E Adj. EBITDA Guidance $490MM - $520MM Segment Outlook Storage & Transportation •  Adjusted EBITDA: $225MM - $235MM •  Volumes trending flat to up 5% in 2016 •  NE S&T and COLT Hub take-or- pay contracts drive stable cash flow Gathering & Processing •  Adjusted EBITDA: $235MM - $250MM •  Volumes trending 15%-20% lower in 2016 •  2016E cash flow forecasts include conservative forecasts for Barnett and PRB Niobrara assets (1) Excludes corporate G&A expenses of $65 million. Segment Contribution (1) (1) ($MM) ($MM)
  • 6.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Repositioning Crestwood in 2015/16 6 Corporate Structure 69.1 MM common units 62.1 MM preferred units In a challenging market, Crestwood continues to take actionable steps to improve its positioning and broaden its investment appeal No IDRs Key Items •  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 projectsü üSimplification Merger Cost Cutting / Reduced Capex •  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 •  On September 30, 2015, closed merger between Crestwood Equity and Crestwood Midstream •  Improved cost of capital by eliminating IDRs ü ü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 Streamlined Business
  • 7.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Existing Scale and New Investment Opportunities in the Right Places 7 Bakken •  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 Crestwood’s crude oil and natural gas operations are situated in the highest returning shale plays Marcellus
  • 8.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Fixed-Fee Contracts Provide Safety Net 8 Contract Portfolio 2016E EBITDA Variable Rate Contracts 8% Take-or-Pay and Fixed-Fee Contracts 92% ü  92% of 2016E EBITDA from take-or-pay and fixed-fee contracts ü  Significant cash flow contribution protected from commodity change and volume reduction 55% of EBITDA is guaranteed through take- or-pay contracts YoY Margin Growth Despite Commodity Prices Adjusted EBITDA Crude Oil and Natural Gas Prices Crude Oil Natural Gas Y-o-Y Adj. EBITDA Growth: 6.4% Crude Oil decline: (61%) Natural Gas decline: (45%)
  • 9.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ $299 $253 $100 $150 $200 $250 $300 $350 4Q14  Annualized FY  2015 Expense / Fixed Charge Reduction Strategy 9 ($MM) Total Expenses Total Expenses by Segment Total Expenses Reduced by 15% 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; 2016+ run-rate savings of >$35MM •  Results drive greater profitability in the current industry environment •  Increased efficiency without sacrificing customer service, safety or compliance •  Simplification adds to coverage improvement through fixed charge elimination (1) Adjusted G&A is defined as general and administrative expenses less unit-based compensation charges and significant transaction and environmental related costs and other items. (1) 4Q14   Annualized FY  2015 ($MM) Total   Expenses Total   Expenses Variance Gathering  &  Processing $109 $89 ($20) Storage  &  Transportation $27 $32 $5 Marketing,  Supply  &  Logistics $79 $70 ($9) Adjusted  G&A $84 $63 ($21) Total  Expenses $299 $253 ($46) %-­‐Change (15.4%)
  • 10.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Consistent Operating and Financial Results 10 (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 Q4 2015 shut-in and weather impacts. Adjusted EBITDA and Margins(1) Natural Gas Volumes Improving financial performance demonstrates strong baseline cash flow; Q4 2015 strongly impacted by warm weather (2) Crude Oil Volumes $18.0 Q415 miss of $18mm attributable to unseasonably warm weather; depressed NE regional pricing (3) $118.5
  • 11.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Capital Structure 11 Capitalization •  Strong liquidity position –  1.5 billion revolving credit facility –  ~50% drawn RCF balance •  No near-term maturities; attractive long-term capital –  $1.8 billion senior notes; 6.00%-6.25% coupon –  Nearest maturity 2020 •  Ample covenant cushion •  Strong fixed charge coverage •  No need to access capital markets in 2016 Crestwood has ample liquidity to execute business plan in challenging market Debt Maturities No near-term debt maturities RCF 6% Notes 6.125% Notes 6.25% Notes ($  millions) 12/31/2015 Cash $0.5 Total  Debt $2,540.3 Total  Partners'  Capital $2,946.9 Total  Capitalization $5,487.2 Credit  &  Liquidity  Stats Total  Leverage  Ratio 4.75x Senior  Secured  Leverage  Ratio 1.37x Total  Leverage  Covenant 5.50x Senior  Secured  Leverage  Covenant 3.75x Summary ($MM)
  • 12.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ •  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 Q4 2015 •  BlueStone Natural Resources emerged as winner bidder; Must close by March 2016 •  Binding agreement in place with the back up bidder •  Long-term resolution likely by Q2 2016 Manageable Counterparty Risk 12 Crestwood has a diverse customer portfolio; producer counterparty risk manageable in the event of continued market deterioration 2016E Cash Flow ExposureCounterparty Risk Overview Manageable counterparty risk in 2016 (1) (1) Represents total annual cash flow contributions from higher risk counterparties.
  • 13.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Core Operations Update 13
  • 14.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ •  Bakken has continued to produce sufficient producer wellhead returns – 94% of rigs operating in four counties (McKenzie, Williams, Mountrail, Dunn) – ~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 10-12 days •  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 Bakken Producers Remain Active Around Crestwood’s Assets 14 Permits Filed in Last 120 Days Permits Heat Map By Arrow Producers 9 2 38 48 Source: North Dakota Industrial Commission As of February 24, 2016.
  • 15.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ 0 25 50 75 100 125 Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15 Gathering  Volumes  (Mboe/d) Crude  Oil Natural  Gas Water $0 $5 $10 $15 $20 $25 Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15 Adjusted  EBITDA  ($MM) Bakken Arrow Gathering System 15 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 aid- in-construction lateral requests •  Lower operating cost in 2015 improves margin •  Arrow volumes have increased 14% year-over-year and 76% since Q1 2014 •  Arrow system connected to COLT Hub through Tesoro and Hiland crude oil pipelines Long-Term Outlook •  >1,200 estimated future drilling locations •  45-55 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 (1) Natural gas converted to barrels at 6:1. Arrow Adjusted EBITDA Increasing Gathering Volumes from Continued Drilling Activity (1) 142% Growth 76% Growth
  • 16.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Bakken COLT Hub and Connector 16 COLT Hub is the leading Bakken CBR facility linking Bakken crude supply to prime refinery markets Source: Genscape February 2016; EIA. 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 Top 5 Bakken CBR Facilities COLT Hub Customers Maintaining Market Share Going into 2016 BakkenPipeline/Crude-by-Rail(Bbls/d) •  Pipeline and CBR remain >1,000 Bbls/d −  67% Pipeline / 33% CBR •  Crestwood’s COLT Hub currently ~25% CBR market share
  • 17.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ $10 $15 $20 $25 $30 $35 $40 $45 Q1:14 Q2:14 Q3:14 Q4:14 Q1:15 Q2:15 Q3:15 Q4:15 Adjusted  EBITDA  ($MM) 17 NE Marcellus Storage and Transportation Summary 200 MMcf/d North-South Expansion Wilmot Receipt Point MARC I Transco Meter Long-Term Outlook •  ~3.5 Bcf/d Marcellus dry gas supply access through upstream gathering and producer connections •  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 Critical infrastructure for NE demand markets (NYC) provide significant level of contracted cash flows and growth opportunities Storage •  Irreplaceable storage position with top East Coast utility customers: Con Ed, NJNG, NYSEG, PSEG •  ~41 Bcf of natural gas storage; 99% subscribed Transportation •  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 Consistent Cash Flow from Take-or-Pay Contracts
  • 18.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ •  20-year, fixed-fee contracts for gathering and compression services with Antero Resources −  ~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 SW Marcellus Gathering & Compression 18 Long-term fee-based contracts in southwest Marcellus core production window Summary Markwest Sherwood Processing Greenbrier Rich Gas Area Crestwood Dedication Area Antero Midstream Dedication Area 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 sales1 −  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 (1)  See November Antero Resources company presentation.
  • 19.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Delaware-Permian: Reservoir Overview 19 •  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 Wolfcamp Western Frontier Bone Spring Western Fairway Wolfcamp Reeves Core NorthernDelawareSouthernDelaware Source: Wood Mackenzie May playbook. Willow Lake 3-Stream Gathering Project Summary Delaware-Permian Map Crestwood’s developing position is located in the core of the Wolfcamp and Bone Spring formations Wolfcamp Bone Spring •  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 •  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
  • 20.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Delaware-Permian: Expansion Projects 20 Crestwood is actively expanding its footprint in the heart of the Delaware Permian Basin, the most active shale play in the US Other Long-Term Opportunities •  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-Stream Gathering System Proposed Expansion Map •  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 −  ~180 mile, 20” pipeline, 200 MBbls/d of capacity 2 3 3 2 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 1 3 Willow Lake Delta Pipeline Orla Terminal 3-Stream Gathering System
  • 21.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ •  Leading marketer of Marcellus/Utica NGLs •  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 through Marcus Hook, PA •  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 21 Crestwood NGL Assets and Services Servicing Blue Chip Customers 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 Marcellus/Utica NGL Logistics Platform Marcus Hook NGL Exports Bath NGL Storage Seymour NGL Storage 60 15 34 88 75 218 2015E = 490 MBPD UEO-CHK Dominion Blue Racer Crestwood BP Markwest
  • 22.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ The Crestwood Investment Opportunity No Incentive Distribution Rights 22 1 Substantial Expense / Fixed Charge Reduction 2 Solid Financial Results year-over-year 3 Diversified / Balanced Portfolio 4 Fixed Fee / Firm Contract Profile 5 Current Valuation Not Indicative of Business Fundamentals Leveraged to Volume Growth with Commodity Price Upside 1 Cost of Capital Improvement 2 Expansion Opportunities in Delaware Permian Basin and NE S&T 3 Strengthened Balance Sheet in 2016 4 Attractive Valuation Entry Point 5 Execution Drives Significant Upside Return Opportunity Strong Liquidity / No near-term maturities 6
  • 23.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ Non-GAAP Reconciliations 23
  • 24.
    Connections for America’sEnergy ™ ™ ™ ™ ™ ™ CEQP Non-GAAP Reconciliations 24 (in millions, unaudited)   4th Qtr 3rd Qtr 2nd Qtr 1st Qtr 4th Qtr 3rd Qtr 2nd Qtr 1st Qtr EBITDA 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 35.4 35.7 35.4 33.6 31.3 31.5 32.6 31.7 Loss on modification/extinguishment of debt 0.2 2.7 17.1 — — — — — Provision (benefit) for income taxes (1.2) (0.3) (0.3) 0.4 — 0.1 0.2 0.8 Depreciation, amortization and accretion 75.6 75.5 74.8 74.2 76.1 71.7 71.2 66.3 EBITDA (a) (1,292.4)$ (509.8)$ (169.0)$ 126.3$ 76.7$ 115.2$ 99.2$ 112.0$ Significant items impacting EBITDA: Unit-based compensation charges 4.1 3.9 5.9 5.8 4.9 4.8 6.2 5.4 (Gain) loss on long-lived assets, net 817.3 2.3 0.6 1.0 2.7 0.9 (1.2) (0.5) Goodwill impairment 515.4 609.9 281.0 — 48.8 — — — Loss on contingent consideration — — — — — — 6.5 2.1 (Earnings) loss from unconsolidated affiliates, net 72.0 (2.8) (5.0) (3.4) (0.6) (0.3) 1.5 0.1 Adjusted EBITDA from unconsolidated affiliates, net 6.9 6.2 5.7 6.5 2.9 1.9 0.4 1.7 Change in fair value of commodity inventory-related derivative contracts (5.3) 8.1 1.5 1.1 (3.5) 1.0 2.9 (10.7) Significant transaction and environmental related costs and other items 0.9 15.7 12.4 4.6 0.8 5.4 2.2 6.5 Adjusted EBITDA (a) 118.9$ 133.5$ 133.1$ 141.9$ 132.7$ 128.9$ 117.7$ 116.6$ Distributable Cash Flow Adjusted EBITDA (a) 118.9 133.5 133.1 141.9 132.7 128.9 117.7 116.6 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 1.2 0.3 0.3 (0.4) — (0.1) (0.2) (0.8) Deficiency payments (0.9) (0.6) 5.7 (0.6) 3.5 2.3 3.8 1.1 Distributable cash flow attributable to CEQP 75.7$ 95.4$ 101.9$ 103.7$ 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)        C as h  interes t  expens e  les s  amortization  of  deferred  financing  cos ts  plus  bond  premium  amortization  plus  or  minus  fair  value  adjus tment  of  interes t  rate  s waps .   (c)        Maintenance  capital  expenditures  are  defined  as  thos e  capital  expenditures  which  do  not  increas e  operating  capacity  or  revenues  from  exis ting  levels .   (d)          D is tributable  cas h  flow  is  defined  as  A djus ted  E B IT D A ,  les s  cas h  interes t  expens e,  maintenance  capital  expenditures ,  income  taxes ,  and  deficiency  payments  (primarily  related  to  deferred  revenue).  D is tributable  cas h  flow  s hould  not  be  cons idered  an  alternative  to  cas h  flows  from  operating   activities  or  any  other  meas ure  of  financial  performance  calculated  in  accordance  with  generally  accepted  accounting  principles  as  thos e  items  are  us ed  to  meas ure  operating  performance,  liquidity,  or  the  ability  to  s ervice  debt  obligations .  We  believe  that  dis tributable  cas h  flow  provides  additional   information  for  evaluating  our  ability  to  declare  and  pay  dis tributions  to  unitholders .  D is tributable  cas h  flow,  as  we  define  it,  may  not  be  comparable  to  dis tributable  cas h  flow  or  s imilarly  titled  meas ures  us ed  by  other  corporations  and  partners hips .   20142015 CRESTWOOD EQUITY PARTNERS LP Reconciliation of Non-GAAP Financial Measures (a)      E B IT D A  is  defined  as  income  before  income  taxes ,  plus  debt-­‐related  cos ts  (net  interes t  and  debt  expens e  and  los s  on  modification/extinguis hment  of  debt)  and  depreciation,  amortization  and  accretion  expens e.  In  addition,  A djus ted  E B IT D A  cons iders  the  adjus ted  earnings  impact  of  our   uncons olidated  affiliates  by  adjus ting  our  equity  earnings  or  los s es  from  our  uncons olidated  affiliates  for  our  proportionate  s hare  of  their  depreciation  and  interes t.  A djus ted  E B IT A  als o  cons iders  the  impact  of  certain  s ignificant  items ,  s uch  as  unit-­‐bas ed  compens ation  charges ,  gains  and   impairments  of  long-­‐lived  as s ets  and  goodwill,  gains  and  los s es  on  acquis ition-­‐related  contingencies ,  third  party  cos ts  incurred  related  to  potential  and  completed  acquis itions ,  certain  environmental  remediation  cos ts ,  certain  cos ts  related  to  our  2015  cos t  s avings  initiatives ,  the  change  in  fair  value  of   commodity  inventory-­‐related  derivative  contracts ,  and  other  trans actions  identified  in  a  s pecific  reporting  period.  T he  change  in  fair  value  of  commodity  inventory-­‐related  derivative  contracts  is  cons idered  in  determining  A djus ted  E B IT D A  given  that  the  timing  of  recognizing  gains  and  los s es  on  thes e   derivative  contracts  differs  from  the  recognition  of  revenue  for  the  related  underlying  s ale  of  inventory  that  thes e  derivatives  relate  to.  C hanges  in  the  fair  value  of  other  derivative  contracts  is  not  cons idered  in  determining  A djus ted  E B IT D A  given  the  relatively  s hort-­‐term  nature  of  thos e  derivative   contracts .  E B IT D A  and  A djus ted  E B IT D A  are  not  meas ures  calculated  in  accordance  with  GA A P ,  as  they  do  not  include  deductions  for  items  s uch  as  depreciation,  amortization  and  accretion,  interes t  and  income  taxes ,  which  are  neces s ary  to  maintain  our  bus ines s .  E B IT D A  and  A djus ted  E B IT D A   s hould  not  be  cons idered  an  alternative  to  net  income,  operating  cas h  flow  or  any  other  meas ure  of  financial  performance  pres ented  in  accordance  with  GA A P .  E B IT D A  and  A djus ted  E B IT D A  calculations  may  vary  among  entities ,  s o  our  computation  may  not  be  comparable  to  meas ures  us ed  by   other  companies .