Exhibit 99.2

Andy Schroeder – Vice President Finance and Treasurer January 22, 2008

22 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,” “potential,” and other comparable words, regarding future or contemplated performance, transaction, or events, are based on MarkWest’s current information, expectations and beliefs, concerning future developments and their potential effects on MarkWest. Among the factors that could cause results to differ materially are those risks discussed in our Form S-1, as amended, our Annual Report on Form 10-K/A for the year ended December 31, 2006, and our Quarterly Reports on Form 10-Q, as amended, each as filed with the SEC. You are also urged to carefully review and consider the cautionary statements and other disclosures, including those under the heading “Risk Factors,” made in those filings, which identify and discuss significant risks, uncertainties and various other factors that could cause actual results to vary significantly from those expressed or implied in the forward-looking statements. If any of the uncertainties or risks develop into actual events, or if underlying assumptions prove incorrect, it could cause actual results to vary significantly from those expressed in the presentation, and our 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 we gather, transport, process, and/or fractionate; ¦ A reduction in the demand for the products we produce and sell; ¦ Financial credit risks / failure of customers to satisfy payment or other obligations under our contracts; ¦ Effects of our debt and other financial obligations on our future financial or operational flexibility; ¦ Construction, procurement, and regulatory risks in our development projects; ¦ Hurricanes, fires, and other natural and accidental events impacting our operations; ¦ Terrorist attacks directed at our facilities or related facilities; ¦ Changes in and impacts of laws and regulations affecting our operations; and ¦ Failure to integrate recent or future acquisitions.

33 Joint Proxy Statement / Prospectus MarkWest Energy Partners and MarkWest Hydrocarbon filed a definitive joint proxy statement/prospectus and other documents with the Securities and Exchange Commission (the “SEC”) in relation to the merger transaction announced on September 5, 2007. Investors and security holders are urged to read these documents carefully because they contain important information regarding MarkWest Energy Partners, MarkWest Hydrocarbon, and the transaction. A definitive joint proxy statement/prospectus will be sent to security holders of MarkWest Energy Partners and MarkWest Hydrocarbon seeking their approval of the transactions contemplated by the redemption and merger agreement. Investors and security holders may obtain a free copy of the joint proxy statement/prospectus and other documents containing information about MarkWest Energy Partners and MarkWest Hydrocarbon, without charge, at the SEC’s website at www.sec.gov. Copies of the joint proxy statement/prospectus and the SEC filings that will be incorporated by reference in the joint proxy statement/prospectus may also be obtained free of charge by directing a request to the entities’ investor relations department at 866-858-0482, or by accessing the companies’ website at www.markwest.com. MarkWest Energy Partners, MarkWest Hydrocarbon, the officers and directors of the general partner of MarkWest Energy Partners, and the officers and directors of MarkWest Hydrocarbon may be deemed to be participants in the solicitation of proxies from their security holders. Information about these persons can be found in the Annual Report on Form 10-K/A for each of MarkWest Energy Partners and MarkWest Hydrocarbon, as filed with the SEC, and additional information about such persons may be obtained from the joint proxy statement/prospectus when it becomes available. This document shall not constitute an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of the Securities Act of 1933, as amended.

44 Non-GAAP Measures This presentation utilizes the Non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow. We define Adjusted EBITDA as net income or loss before interest, provision for income taxes, depreciation and amortization expense, non-cash compensation expense, and non-cash unrealized derivative gain / loss. Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP, and should not be considered in isolation or as a substitute for net income, income from operations, or cash flow as reflected in our financial statements. Adjusted EBITDA is presented because such information is relevant and is used by management, industry analysts, investors, lenders, and rating agencies to assess the financial performance and operating results of our fundamental business activities. Management believes that the presentation of Adjusted EBITDA is useful to lenders and investors because of its use in the midstream natural gas industry and for master limited partnerships as an indicator of the strength and performance of our ongoing business operations. Additionally, management believes that Adjusted EBITDA provides additional and useful information to our 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. The presentation of Adjusted EBITDA allows investors to view our performance in a manner similar to the methods used by management and provides additional insight to our operating results. In general, we define Distributable Cash Flow as net income or loss plus (i) depreciation, amortization, and accretion expense; (ii) non-cash earnings from unconsolidated affiliates; (iii) contributions to unconsolidated affiliates net of expansion capital expenditures; (iv) non-cash compensation expense; (v) non-cash derivative activity; (vi) gains and losses on the sale of assets; and (vii) the subtraction of sustaining capital expenditures. Distributable Cash Flow is a significant liquidity metric used by our senior management to compare basic cash flows generated by us to the cash distributions we expect to pay partners. Distributable cash flow is also an important Non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Distributable cash flow is also a quantitative standard used by the investment community with respect to publicly traded partnerships such as ours because the value of a partnership unit is in part measured by its yield (which in turn is based on the amount of cash distributions a partnership pays to a unit holder). The GAAP measure most directly comparable to Distributable Cash Flow and Adjusted EBITDA is net income. Please see the Appendix for our calculations of Adjusted EBITDA and Distributable Cash Flow along with the appropriate reconciliations.

55 ¦ MarkWest Overview ¦ Merger Overview ¦ Energy Partners Overview . Geographic footprint . Proven results . Diversified operations . Strategic investments drive increasing returns ¦ Financial Overview ¦ Investment Highlights Agenda

66 Owns 14.3% of MWE MarkWest Overview MarkWest Hydrocarbon, Inc. ¦ Ticker — MWP (AMEX) ¦ 12.0 million shares outstanding ¦ Price (1/17/08) — $63.75 ¦ Market cap (1/17/08) — $765 million . Key assets: • 4.9 million units in MWE • 89.7% of MWE General Partner • Gas and natural gas liquid marketing ¦ No debt outstanding MarkWest Energy Partners, L.P. ¦ Ticker — MWE (NYSE) ¦ 39.4 million units outstanding ¦ Price (1/17/08) — $34.97 ¦ Market cap (1/17/08) — $1.4 billion ¦ Long-term debt: $590 million (9/30/07 balance) ¦ Key assets . Southwest • East Texas gathering systems and processing plants • Oklahoma gathering and processing systems • Lateral pipelines to power plants • 15 gathering systems . Gulf Coast • Javelina Processing Facility • Starfish Pipeline Company . Northeast • Franchise processing position in the prolific Appalachian basin • Largest intrastate crude oil pipeline in Michigan • Gas transmission and processing facilities in Western Michigan

Merger Overview

88 Overview of Merger Agreement ¦ Announced in September 2007, and valued at approximately $734 million ¦ Per share “stated consideration” is 1.285 common units of MWE plus $20.00 cash ¦ The incentive distribution rights will be extinguished ¦ Hydrocarbon will become a direct, wholly owned subsidiary of Energy Partners ¦ Energy Partners will not issue units to raise new equity capital to consummate the merger ¦ The Energy Partners management team will manage the combined company ¦ The merger will result in changes to the corporate governance of Energy Partners . The Board of Directors of Energy Partners will be elected annually by the unitholders ¦ The record date for both companies was January 14, 2008, and the shareholder meetings will be held on February 21, 2008, in Denver, Colorado.

99 Benefits of Merger ¦ Eliminate the IDRs and improve our cost of equity capital . Energy Partners will exchange a new class of limited partner equity units in exchange for the IDRs, as well as for the GP interest and the existing limited units owned by Hydrocarbon . The transaction will reduce our go-forward cost of equity and strengthen our competitive position ¦ Simplify the organization structure . One public company with one board of directors, to be elected annually by the common unitholders . Simplify corporate governance . Reduce or eliminate intercompany transactions and reduce the potential for intercompany conflicts ¦ The MarkWest team will be focused on driving value for one set of public equity owners . Interests of all equity holders aligned

10 10 Post-Merger Corporate Structure Ownership Structure – Pro Forma Ownership Structure – Current Public 34.3 MM MWE Common Units MarkWest Energy GP, L.L.C. MarkWest Energy Partners, L.P. 39.4 MM Total Common Units 2.0% G.P. Interest and IDRs MarkWest Hydrocarbon, Inc. 4.9MM MWE Common Units 89.7% Officers / Directors 0.2 MM MWE Common Units 5.5 MM MWP Common Stock 10.3% 12.2% L.P. Interest 0.5% L.P. Interest 85.3% L.P. Interest Public 6.5MM MWP Common Stock 53.9% 46.1% MarkWest Energy Partners, L.P. 50.9 MM Total Common Units Public 83.1% L.P. Interest MarkWest Operating Subsidiaries MarkWest Energy GP, L.L.C. 100% Interest “Non-economic” G.P. Interest MarkWest Hydrocarbon, Inc. MWE Class A Units 100% Interest MarkWest Operating Subsidiaries Officers / Directors 16.9% L.P. Interest

11 11 Pro-Forma DCF per Unit Analysis for Merger (in millions of $ and units) DCF 170,000 $ Units GP LP Common 50,819 69.3% Distributed (1) 110,680 $ 30,376 $ 80,304 $ Class A 22,500 30.7% Total Limited 73,319 Undistributed 59,320 $ 29,660 $ 29,660 $ Class A Common 60,036 $ DCF from MWE operations 170,000 $ 170,000 $ 30.7% 69.3% Total DCF Allocable to Common Units 109,964 $ 52,169 $ 117,831 $ Common Units 39,358 DCF / Common Unit 2.79 $ Class A Distributable Cash Flow 52,169 $ MWP EBITDA 15,000 Interest Expense (18,750) Current Income Tax (2) (10,908) MWP Cash Flow / Dividend 37,511 $ 37,511 Total DCF Allocable to Common Units 155,342 $ Common Units 50,819 DCF / Common Unit 3.06 $ (1) Based on 3Q07 annualized distribution (2) 37.49% effective rate on $29,095 taxable income including K1 from Class A Units MarkWest Hydrocarbon 2007 Pro-Forma 2008 Forecast Without Merger 2008 Forecast, Pro-forma for Merger DCF Allocation DCF Allocation

12 12 Reduced Cost of Equity * Post transaction, market data as of January 17, 2008. Cost of equity reduction = 2.38% Source: RBC Capital Markets Pipeline / Midstream MLP Cost of Equity 5.10% 3.26% 0.09% 0.05% 0.15% 0.10% 0.10% 0.10% 0.11% 0.00% 0.12% 0.25% 0.00% 0.70% 0.73% 0.26% 1.11% 1.01% 0.09% 0.19% 0.53% 1.22% 0.74% 0.49% 0.94% 0.90% 2.63% 2.38% 0.17% 1.45% 1.78% 2.03% 3.00% 3.57% 0.21% 3.25% 0.00% 2.00% 4.00% 6.00% 8.00% 10.00% 12.00% 14.00% SGLP NGLS GEL EPB RGNC SEP KGS CPNO WMZ BWP MWE* DPM WPZ TLP HLND EPD DEP GLP HEP OKS TCLP MMLP NS EEP MMP MWE EROC TPP SXL PAA BPL ETP CQP XTEX APL KMP Market Yield General Partner 7.60% 10.26% 6.44% 6.95% 6.85% 7.04% 7.32% 6.29% 5.94% 7.29% 7.46% 7.72% 6.56% 7.36% 7.37% 6.44% 6.03% 6.59% 6.29% 5.99% 5.83% 5.15% 5.87% 4.98% 4.89% 4.54% 4.83% 5.65% 8.17% 8.55% 7.18% 7.02% 5.07% 4.92% 5.75% 6.59%

13 13 Financial Benefit of Merger Incremental DCF per Common Unit Impact of $300 million in annual capital investments for projects with a 15% IRR $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 $1.60 $1.80 YR1 YR2 YR3 YR4 YR5 Pro-forma pre merger Pro-forma with merger

Energy Partners Overview

15 15 Geographic Footprint ¦ Michigan . Crude oil pipeline . 250-mile intrastate pipeline . 90-mile gas gathering pipeline . Gas processing plant ¦Western Oklahoma . 150 MMcf/d gathering capacity . 100 MMcf/d processing plant ¦ Southeast Oklahoma . 150 MMcf/d gathering capacity (to grow to 300 MMcf/d by 2010) ¦ Starfish (50% equity ownership). Offshore gas gathering system . West Cameron dehydration facility ¦ Appalachia . 350 MMcf/d processing capacity . 136-mile NGL pipeline . 11 million gallon NGL storage facility ¦ Javelina . Gas processing, fractionation, and transportation facilities ¦ East Texas . 410 MMcf/d gathering capacity . 200 MMcf/d processing plant ¦ Other Southwest . 12 gas gathering systems . 3 lateral gas pipelines

16 16 (1) Adjusted for the 2:1 unit split effective on February 28, 2007. (2) From year ended December 31, 2002, to LTM as of September 30, 2007. See appendix for reconciliation of Adjusted EBITDA to Net Income. (3) As of September 30, 2007. Proven Results Since IPO $85.9 million $1,342.9 million(3) +1,463% Total Assets $11.0 million $184.1 million Adjusted EBITDA(2) +1,574% $1.00 $2.20 Annualized Distribution(1) +120% $10.25 $34.97 Unit Price(1) +241% IPO (May 2002) Current (Jan. 17, 2008)

17 17 MWE vs. Alerian Index -50.0% 0.0% 50.0% 100.0% 150.0% 200.0% 250.0% 300.0% May-02 Sep - 02 Jan-03 Apr-03 Aug-03 Dec -03 Apr-04 Jul- 04 Nov -04 Mar-05 Jul -05 Oct -05 Feb -06 Jun -06 Oct -06 Jan -07 May-07 Sep - 07 Jan-08 MWE 241.2% AMZ 71.7%

18 18 Consistent Distribution Growth Since IPO 120% Distribution Growth since IPO in May 2002 (16% CAGR) Common Unit Distribution $0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 3Q02 4Q02 1Q03 2Q03 3Q03 4Q03 1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07

19 19 Diversified Operations (1) As defined in our Quarterly Report on Form 10-Q, Net Operating Margin is calculated as total revenues less purchased product costs. (2) Keep-whole exposure largely offset by long natural gas position derived from POI and natural gas contracts. POI & Natural Gas 0%(2) Net Operating Margin(1) for the Nine Months Ended 9/30/07 By Geographic Region By Contract Type By Contract Type By Geographic Region Oklahoma 22% Appalachia 10% Other Southwest 8% Michigan 3% Javelina 27% East Texas 30% Keep-Whole 4% POP&NGL 63% Fee-Based 33%

20 20 “MarkWest Energy Named #1 in Natural Gas Customer Satisfaction” EnergyPoint Research, Inc. 2006 Customer Satisfaction Survey Growth Driven by Customer Satisfaction

21 21 Capital Investment $ millions $ millions Adjusted EBITDA* *See appendix for reconciliation of Adjusted EBITDA to Net Income. Acquisitions Expansion capital Strategic Investments Drive Increasing Return Upside expansion capital $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 2003 2004 2005 2006 2007F 2008F $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 2003 2004 2005 2006 LTM 3Q07

22 22 • Compressor additions/other expansion $21.6M • Centerpoint connection $7.0M 2007 Expansion Capex Summary 2007 expansion capital forecast of $301.4 million ($229.1 million actual expenditures thru 3Q07) Woodford Appalachia Other Southwest Javelina Oklahoma East Texas Oklahoma • Compressor additions / other expansion $11.0M • Processing plant expansion $5.0M • Well connects $3.8M • Grimes $3.8M • ANR connection $2.0M • Appleby new compressor/system upgrade $6.9M • Hobbs pipeline expansion $3.0M • Well connects $1.8M • Other expansion $4.0M • C5 enhancement $7.5M • PSA absorbment $1.2M • Residue pipelines $0.4M East Texas Other Southwest Javelina $221.4 $28.6 $15.7 $9.1 $1.0 $25.6

23 23 2008 Expansion Capex Forecast $280MM to $320MM Woodford $120MM-$130MM Appalachia $50MM-$55MM Other Southwest $5MM-$10MM Javelina $50MM-$55MM Oklahoma $15MM-$20MM East Texas $40MM-$50MM

Financial Overview

25 25 Capital Structure Pro-forma $ 41.3 4.5x 3.2x 51.1% $ 184.1 $ 1,154.0 $ 564.4 $ 589.6 272.1 225.0 92.5 $ 53.7 As of September 30, 2007 $ 49.8 3.5x 3.0x 53.8% $ 175.8 $ 979.5 $ 452.6 $ 526.9 271.9 225.0 30.0 $ 34.4 As of December 31, 2006 As of September 30, 2007 ($ in millions) 3.4x LTM Adjusted EBITDA(1) / Interest Expense $ 59.0 LTM Interest expense 48.6% Total Debt / Capitalization 4.0x Total Debt / LTM Adjusted EBITDA(1) $ 1,642.9 Total Capitalization $ 798.7 Total Debt 275.0 8-1/2% Senior Notes due 2016 $ 844.2 Total Partners’ Capital 225.0 6-7/8% Senior Notes due 2014 298.7 Credit Facility $ 199.1 LTM Adjusted EBITDA(1) $ 14.0 Cash (1) LTM Adjusted EBITDA calculated in accordance with Credit Facility covenants.

26 26 Distributable Cash Flow Summary $37MM $44MM $118MM $152MM $160MM – $180MM $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 2004 2005 2006 2007F 2008F

27 27 1.59x $ 74.0 $ 117.9 (2.3) 10.2 (6.2) 46.1 $ 70.1 Year ended December 31, 2006 1.46x $ 78.6 $ 114.9 (3.3) 16.4 23.8 40.8 $ 37.2 Nine months ended September 30, 2007 ($ in millions) Depreciation, amortization, accretion, and impairments Non-cash derivative activity Plus: Distribution coverage ratio Distributions paid Maintenance capital expenditures Less: Distributable cash flow (DCF) Other Net income Distribution Coverage

28 28 Risk Management Program ¦ Energy Partners has an ongoing hedge program, designed to manage exposure to commodity price risk, which is primarily due to our long NGL position . Hedges are executed on a 36-month time horizon, using a combination of collars and swaps, and direct product and crude proxy hedges ¦ Energy Partners is fully hedged through the third quarter of 2010, allowing for operational flexibility . Energy Partners’ DCF sensitivity to downside price changes is approximately $1.6 million for every $1/BBL change in NYMEX crude price

29 29 2007 and 2008 Guidance and Key Assumptions ¦ 2007 Financial Guidance . Distributable cash flow of approximately $152 million . Expansion capital expenditures of approximately $300 million . The 2007 forecast would allow for an increase in distributions of approximately 15% to our limited unit holders ¦ 2008 Financial Guidance . Distributable cash flow of $160 million to $180 million . Expansion capital expenditures of $280 million to $320 million

30 30 Investment Highlights ¦High-quality, diverse portfolio of midstream assets serving very prolific natural gas basins in the US ¦Ranked #1 in natural gas customer satisfaction (EnergyPoint Research, Inc. 2006 Customer Satisfaction Survey) ¦Successful track record of accretive acquisitions and organic expansions ¦Experienced management team with significant alignment of interests with unitholders ¦Superior and sustainable distribution growth

1515 Arapahoe Street Tower 2 Suite 700 Denver, CO 80202 Phone: 303-925-9200 Investor Relations: 866-858-0482 Email: investorrelations@markwest.com Website: www.markwest.com

Appendix

33 33 $ 117.9 (2.3) 9.7 (6.2) 15.2 (9.4) (5.3) 46.1 $ 70.1 Year ended December 31, 2006 $ 114.9 (3.3) 2.4 23.8 9.4 9.3 (4.7) 40.8 $ 37.2 Nine months ended September 30, 2007 ($ in millions) Maintenance capital expenditures Non-cash derivative activity Depreciation, amortization, accretion and impairments Non-cash losses from unconsolidated affiliates Distributable cash flow Other Non-cash compensation expense Distributions from (contributions to) unconsolidated affiliates, net of expansion capital Net income Reconciliation of Distributable Cash Flow to Net Income

34 34 Nine months ended September 30, Year ended December 31, $ 10.0 (3.3) (0.1) (14.5) – (19.2) $ 47.1 2004 (30.4) (49.8) (29.2) Interest expense (0.4) (0.8) – Taxes (23.8) 6.2 (0.7) Non-cash derivative activity $ 2.4 (40.8) (46.1) (29.2) Depreciation and amortization (9.4) (15.2) (3.1) Non-cash compensation expense $ 64.6 2005 $ 70.1 $ 175.8 2006 2007 ($ in millions) $ 37.2 Net Income $ 142.0 Adjusted EBITDA Reconciliation of Adjusted EBITDA to Net Income

MARKWEST HYDROCARBON INC 8-K