Exhibit 99.1
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BARCLAYS CEO ENERGY-POWER CONFERENCE SEPTEMBER 2013 |
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Forward-Looking Statements This presentation contains forward-looking statements and information. These forward-looking statements, which in many instances can be identified by words like “could,” “may,” “will,” “should,” “expects,” “plans,” “project,” “anticipates,” “believes,” “planned,” “proposed,” “potential,” and other comparable words, regarding future or contemplated results, performance, transactions, or events, are based on MarkWest Energy Partners, L.P. (“MarkWest” and the “Partnership”) current information, expectations and beliefs, concerning future developments and their potential effects on MarkWest. Although MarkWest believes that the expectations reflected in the forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct, and actual results, performance, distributions, events or transactions could vary significantly from those expressed or implied in such statements and are subject to a number of uncertainties and risks. Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed with the SEC, including MarkWest’s Annual Report on Form 10-K for the year ended December 31, 2012 and its Quarterly Report on Form 10-Q for the quarter ended June 30, 2013. You are urged to carefully review and consider the cautionary statements and other disclosures, including those under the heading “Risk Factors,” made in those documents. If any of the uncertainties or risks develop into actual events or occurrences, or if underlying assumptions prove incorrect, it could cause actual results to vary significantly from those expressed in the presentation, and MarkWest’s business, financial condition, or results of operations could be materially adversely affected. Key uncertainties and risks that may directly affect MarkWest’s performance, future growth, results of operations, and financial condition, include, but are not limited to: Fluctuations and volatility of natural gas, NGL products, and oil prices; A reduction in natural gas or refinery off-gas production which MarkWest gathers, transports, processes, and/or fractionates; A reduction in the demand for the products MarkWest produces and sells; Financial credit risks / failure of customers to satisfy payment or other obligations under MarkWest’s contracts; Effects of MarkWest’s debt and other financial obligations, access to capital, or its future financial or operational flexibility or liquidity; Construction, procurement, and regulatory risks in our development projects; Hurricanes, fires, and other natural and accidental events impacting MarkWest’s operations, and adequate insurance coverage; Terrorist attacks directed at MarkWest facilities or related facilities; Changes in and impacts of laws and regulations affecting MarkWest operations and risk management strategy; and Failure to integrate recent or future acquisitions. 2 |
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Non-GAAP Measures Distributable Cash Flow, Adjusted EBITDA, and Net Operating Margin are not measures of performance calculated in accordance with GAAP, and should not be considered separately from or as a substitute for net income, income from operations, or cash flow as reflected in our financial statements. The GAAP measure most directly comparable to Distributable Cash Flow and Adjusted EBITDA is net income (loss). The GAAP measure most directly comparable to Net Operating Margin is income (loss) from operations. In general, we define DCF as net income (loss) adjusted for (i) depreciation, amortization, impairment, and other non-cash expense; (ii) amortization of deferred financing costs and discount; (iii) loss on redemption of debt net of current tax benefit; (iv) non-cash (earnings) loss from unconsolidated affiliates; (v) distributions from (contributions to) unconsolidated affiliates (net of affiliate growth capital expenditures); (vi) non-cash compensation expense; (vii) non-cash derivative activity; (viii) losses (gains) on the disposal of property, plant, and equipment (PP&E) and unconsolidated affiliates; (ix) provision for deferred income taxes; (x) cash adjustments for non-controlling interest in consolidated subsidiaries; (xi) revenue deferral adjustment; (xii) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period; and (xiii) maintenance capital expenditures, net of joint venture partner contributions. We define Adjusted EBITDA as net income (loss) adjusted for (i) depreciation, amortization, impairment, and other non-cash expense; (ii) interest expense; (iii) amortization of deferred financing costs; (iv) loss on redemption of debt; (v) losses (gains) on the disposal of PP&E and unconsolidated affiliates; (vi) non-cash derivative activity; (vii) non-cash compensation expense; (viii) provision for income taxes; (ix) adjustments for cash flow from unconsolidated affiliates; (x) adjustment related to non-guarantor, consolidated subsidiaries; and (xi) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period. We generally define Operating Income before Items Not Allocated to Segments as (i) revenue, excluding derivative gains and losses and adjusted for certain revenue deferral adjustments less; (ii) purchased product costs, excluding derivative gains and losses less; (iii) facility expenses, adjusted for certain non-cash items not allocated to segments and certain interest payments allocable to the segments less; ( iv) the portion allocable to non-controlling interests. Distributable Cash Flow is a financial performance measure used by management as a key component in the determination of cash distributions paid to unitholders. We believe distributable cash flow is an important financial measure for unitholders as an indicator of cash return on investment and to evaluate whether the Partnership is generating sufficient cash flow to support quarterly distributions. In addition, distributable cash flow is commonly used by the investment community because the market value of publicly traded partnerships is based, in part, on distributable cash flow and cash distributions paid to unitholders. Adjusted EBITDA is a financial performance measure used by management, industry analysts, investors, lenders, and rating agencies to assess the financial performance and operating results of the Partnership’s ongoing business operations. Additionally, we believe Adjusted EBITDA provides useful information to investors for trending, analyzing, and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures. Net Operating Margin is a financial performance measure used by management and investors to evaluate the underlying baseline operating performance of our contractual arrangements. Management also uses Net Operating Margin to evaluate the Partnership’s financial performance for purposes of planning and forecasting. Please see the Appendix for reconciliations of Distributable Cash Flow, Adjusted EBITDA, and Net Operating Margin to the most directly comparable GAAP measure. 3 |
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Key Investment Considerations 4 High-Quality, Diversified Assets Proven Growth and Customer Satisfaction Substantial Growth Opportunities Strong Financial Profile Leading presence in major shale plays including Marcellus, Utica, Huron/Berea, Woodford , Haynesville and Granite Wash formation Largest processor in the Marcellus Shale Largest fractionator in the Northeast Over $8 billion of organic growth and acquisitions since IPO Over $5 billion invested in Marcellus and Utica since 2008 Received top ranking in EnergyPoint’s 2013 Midstream Customer Satisfaction survey 2013 growth capital forecast of $1.5 to $1.8 billion 23 major processing and fractionation projects under construction Long-term agreements with over 25 major producer customers Established relationships & joint venture partners No incentive distribution rights, which drives a lower cost of capital Distributions have increased by 236% (12% CAGR) since IPO Growing fee-based margin to over 70% for full-year 2014 Quarterly Distribution Growth of 236% Since IPO |
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MarkWest Assets: Expansion and Diversification 5 Liberty Largest processor and fractionator in the Marcellus Shale with over 1.6 Bcf/d of processing capacity and 98,000 Bbl/d of fractionation capacity. Growing to 3.6 Bcf/d of processing capacity and 232,000 Bbl/d of fractionation capacity Utica Developing a leading position in the southern core of the Utica Shale with 185 MMcf/d of processing capacity. Growing to over 900 MMcf/d of processing capacity and nearly 140,000 Bbl/d of fractionation capacity by the end of 2014 Northeast Largest processor and fractionator in the southern Appalachian Basin Southwest Best-in-class midstream services in the Granite Wash, Haynesville, Woodford and Eagle Ford Shales and have over 1.6 Bcf/d of gathering capacity and 817 MMcf/d of processing capacity |
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Growth Driven By Customer Satisfaction 6 MarkWest has received the top rating in three of the last four EnergyPoint Research surveys |
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Barbour Brooke Doddridge Hancock Harrison Marion Marshall Monongalia Ohio Pleasants Preston Ritchie Taylor Tyler Wetzel Wood Belmont Carroll Columbiana Coshocton Guernsey Harrison Holmes Mahoning Medina Monroe Morgan Muskingum Noble Portage Stark Summit Trumbull Tuscarawas Washington Wayne Allegheny Armstrong Beaver Butler Clarion Crawford Fayette Greene Lawrence Mercer Venango Washington Westmoreland West Virginia Ohio MWE Utica Counties MWE Marcellus Counties MWE Plants ATEX Express Pipeline TEPPCO Product Pipeline Jefferson Marcellus and Utica: 16 Major Projects Complete Mariner Projects Rich Utica Rich Marcellus MWE Gathering Area 7 MWE NGL Pipelines... 22 Major projects under construction MOBLEY COMPLEX Mobley I & II – 320 MMcf/d – Complete Mobley III – 200 MMcf/d – 4Q13 Mobley IV – 200 MMcf/d – 1Q15 HOUSTON COMPLEX Houston I, II & III – 355 MMcf/d – Complete Houston IV – 200 MMcf/d – 2015 C3+ Fractionation – 60,000 Bbl/d – Complete De-ethanization – 38,000 Bbl/d – Complete SHERWOOD COMPLEX Sherwood I & II – 400 MMcf/d – Complete Sherwood III – 200 MMcf/d – 4Q13 Sherwood IV – 200 MMcf/d – 2Q14 De-ethanization – 38,000 Bbl/d – 1Q15 HOPEDALE FRACTIONATOR C3+ Fractionation – 60,000 Bbl/d – 1Q14 KEYSTONE COMPLEX Bluestone I & Sarsen I – 90 MMcf/d – Complete Bluestone II – 120 MMcf/d – 2Q14 Bluestone III – 200 MMcf/d – TBD De-ethanization – 10,000 Bbl/d – 1Q14 C3+ Fractionation – 10,000 Bbl/d –1Q14 SENECA COMPLEX Seneca I – 200 MMcf/d – 4Q13 Seneca II – 200 MMcf/d – 4Q13 Seneca III – 200 MMcf/d – 2Q14 De-ethanization – 38,000 Bbl/d – 4Q14 MAJORSVILLE COMPLEX Majorsville I - III – 470 MMcf/d – Complete Majorsville IV – 200 MMcf/d – 1Q14 Majorsville V – 200 MMcf/d – 4Q13 Majorsville VI – 200 MMcf/d – 2016 De-ethanization I – 38,000 Bbl/d – 4Q13 De-ethanization II – 38,000 Bbl/d – TBD CADIZ COMPLEX Cadiz I & Refrig – 185 MMcf/d – Complete Cadiz II – 200 MMcf/d – 3Q14 De-ethanization – 40,000 Bbl/d – 1Q14 |
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Liberty Segment 2013 Forecasted Segment Operating Income Key Considerations We are the largest processor of natural gas and fractionator of natural gas liquids in the Marcellus Shale Areas of Operation Southwest and Northwest Pennsylvania and northern West Virginia Resource Plays Marcellus Shale Gathering 615 MMcf/d capacity Processing 1.6 Bcf/d cryogenic capacity Fractionation 98,000 Bbl/d C2+capacity NGL Marketing & Storage NGL Marketing by truck and large-scale rail facility 90,000 Bbl NGL storage capacity with access to over 900,000 Bbls of propane storage Under Construction Processing 2.0 Bcf/d cryogenic capacity Fractionation 134,000 Bbl/d C2+ capacity NGL Transportation Extensive NGL gathering system with access to purity ethane projects Operate fully integrated gathering, processing, fractionation, storage and marketing operations 8 |
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MarkWest Liberty: Current Processing Capacity of 1.6 Bcf/d 9 Sarsen Bluestone I Houston I-III Majorsville I-III Mobley I, II Sherwood I, II Majorsville V Mobley III Sherwood III Bluestone II Majorsville IV Sherwood IV 2014 2013 Current Growing to over 3.5 Bcf/d of processing capacity in the Marcellus Shale Bluestone III Houston IV Majorsville VI Mobley IV 2015+ |
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Areas of Operation Eastern Ohio Resource Plays Utica Shale Gathering 185 MMcf/d capacity Processing 185 MMcf/d capacity Utica Segment 10 Key Considerations We are developing a leading position in the southern core of the highly prospective Utica Shale We have partnered with The Energy & Minerals Group (EMG) to develop fully integrated gathering, processing, fractionation, storage and marketing operations 2013 Forecasted Segment Operating Income Under Construction Processing 800 MMcf/d cryogenic capacity 200 MMcf/d at Cadiz Complex 600 MMcf/d at Seneca Complex Fractionation 138,000 Bbl/d C2+ capacity NGL Transportation Extensive NGL gathering system, interconnects to TEPPCO and ATEX pipelines Marketing Large scale rail and truck loading in Harrison County, Ohio |
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Utica Processing Capacity 11 Cadiz I & Refrigeration Seneca I Seneca II Cadiz II Seneca III 2014 2013 Current Growing to over 900 MMcf/d in the Utica Shale by the end of 2014 |
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Northeast: Supply & Demand – NGLs 12 Continued growth in NGL production creates the potential need for an NGL pipeline to the Gulf Coast Source: Wells Fargo NGL Snapshot: May 2013 |
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Kinder Morgan/MarkWest Utica EMG – Joint Venture 13 Conversion of Existing Pipeline Kinder Morgan has received FERC approval to convert a portion of an existing 26” TGP pipeline into rich-gas service. Once converted, this pipeline would deliver gas to the new JV processing complex. This pipeline would support producers in Carroll, Columbiana, Mahoning, and Trumbull counties in northern Ohio. NGL and Rich-Gas Connections NGL connection would link MarkWest’s existing infrastructure to JV NGL pipeline. Rich-gas connection would link MarkWest’s existing infrastructure to JV processing complex. Joint Venture Processing JV would develop a large-scale processing complex in Tuscarawas County, OH. The JV would initially construct a 200 MMcf/d facility with a second facility shortly thereafter, based on producer commitments. The complex would be expandable to accommodate more than 1 Bcf/d of processing capacity. Processing Joint Venture provides opportunity in northern Ohio and complements existing infrastructure |
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Kinder Morgan/MarkWest Utica EMG – Joint Venture Joint Venture Fractionation JV would develop new fractionation facilities as well as utilize third-party facilities in the Gulf Coast. New JV Processing Facility, JV NGL Connection and Conversion of TGP Pipeline to Rich-Gas Service JV would develop a large-scale processing complex in Tuscarawas County, OH and connect the JV NGL pipeline to existing MarkWest Utica EMG infrastructure. North of the processing complex, Kinder Morgan has received approval to convert a portion of an existing 26” TGP pipeline into rich-gas service. Joint Venture NGL Pipeline Subject to FERC approval, the JV would convert over 900 miles of existing 24-inch/26-inch Tennessee Gas Pipeline (TGP) to NGL service from Ohio to Louisiana. The JV would construct approximately 200 miles of new pipeline from Natchitoches, LA to Mont Belvieu, TX. By converting over 900 miles of existing pipeline, the Joint Venture is the most efficient project to access Gulf Coast NGL markets 14 |
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Granite Wash: Expanding our Presence Chesapeake Indian Corn Gathering & Treating Dedicated to MarkWest Chesapeake Briscoe Gathering & Processing Dedicated to MarkWest MarkWest’s Foss Lake and Grimes Gathering Arapahoe Processing MarkWest’s Stiles System Chesapeake Texas and Oklahoma Granite Wash Dedicated to MarkWest for Processing Buffalo Creek Processing Plant Recently acquired midstream assets from a subsidiary of Chesapeake Energy for $225 million and executed long-term, fee-based agreements As part of the processing agreement, Chesapeake has dedicated 130,000 acres to MarkWest In August, we connected the assets to our existing gathering system and are processing approximately 50 MMcf/d Buffalo Creek plant to be operational by 1Q14 15 |
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DCF and Capital Investments 16 2013 Capital Expenditure Forecast DCF Growth ($ millions) 35% CAGR 16 2013 DCF Forecast of $500 million to $540 million 2013 Capital Expenditures Forecast of $1.5 to $1.8 billion From 2004 to 2012, DCF has grown at a CAGR of 35% and has increased by over 1,000% in the same time period 2013F |
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Note: Forecast Assumes Crude Oil ($/bbl) range of $93.55 to $95.00 and Natural Gas ($/mmbtu) range of $3.80 to $4.30 17 For the full-year 2014, net operating margin is expected to be over 70% fee-based Increasing Fee-Based Margin |
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Total Return Since 2009 18 Source: Bloomberg as of 8/30/13 (Cumulative Total Return, Net Dividends) MarkWest Provides Superior Total Return 237% 100% 1,124% |
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Keys to Success EXECUTE, EXECUTE, EXECUTE!!! 19 |
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APPENDIX |
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Reconciliation of DCF and Distribution Coverage 21 |
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Reconciliation of Adjusted EBITDA 22 Includes derivative activity related to interest expense, amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer. |
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Reconciliation of Net Operating Margin 23 |
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1515 Arapahoe Street Tower 1, Suite 1600 Denver, Colorado 80202 Phone: 303-925-9200 Investor Relations: 866-858-0482 Email: investorrelations@markwest.com Website: www.markwest.com |
