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TABLE OF CONTENTS
TABLE OF CONTENTS

Filed Pursuant to Rule 424(B)(3)
Commission File No. 333-116680

The information in this preliminary prospectus supplement is not complete and may be changed. This preliminary prospectus supplement and the attached prospectus are not an offer to sell these securities, and we are not soliciting an offer to buy these securities, in any state where the offer or sale is not permitted.

Subject to Completion, dated September 13, 2004

Preliminary Prospectus Supplement
(To Prospectus dated July 27, 2004)

2,159,138 Common Units

Representing Limited Partner Interests

$            per common unit

We are offering 2,000,000 common units and the selling unitholders named in this prospectus supplement are offering 159,138 common units. We will not receive any proceeds from the sale of the common units by the selling unitholders.

Our common units are listed on the American Stock Exchange under the symbol "MWE." The last reported sales price of our common units on the American Stock Exchange on September 9, 2004 was $44.05 per common unit.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page S-17 of this prospectus supplement and page 1 of the accompanying prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

	Per Common Unit	Total
Public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to MarkWest Energy Partners, L.P.	$	$
Proceeds, before expenses, to the Selling Unitholders	$	$

The underwriters expect to deliver the common units on or about September     , 2004. We have granted the underwriters a 30-day option to purchase up to an additional 323,870 common units on the same terms and conditions as set forth in this prospectus supplement to cover over-allotments of common units, if any.

RBC CAPITAL MARKETS A.G. EDWARDS

WACHOVIA SECURITIES

KEYBANC CAPITAL MARKETS

STIFEL, NICOLAUS & COMPANY

                       Incorporated

September     , 2004

        This document is in two parts. The first part is this prospectus supplement, which describes the specific terms of this offering of common units. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to this offering of common units. If the description of the common unit offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement. The sections captioned "Where You Can Find More Information" and "Legal Matters" in the accompanying prospectus are superseded in their entirety by the similarly titled sections included in this prospectus supplement.

        You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus. We have not authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. We and the selling unitholders are offering to sell the common units, and seeking offers to buy the common units, only in jurisdictions where offers and sales are permitted. You should not assume that the information included in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the dates shown in these documents or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since such dates.

TABLE OF CONTENTS

Prospectus Supplement

Prospectus dated July 27, 2004

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SUMMARY

This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectus. It does not contain all of the information that you should consider before making an investment decision. You should read the entire prospectus supplement, the accompanying prospectus and the documents incorporated by reference for a more complete understanding of this offering. Please read "Risk Factors" beginning on page S-17 of this prospectus supplement and page 1 of the accompanying prospectus for more information about important risks that you should consider before buying our common units. Unless the context otherwise indicates, the information included in this prospectus supplement assumes that the underwriters do not exercise their over-allotment option.

References to the "MarkWest Hydrocarbon Midstream Business" refer to the assets of the MarkWest Hydrocarbon Midstream Business that were contributed to us in connection with our initial public offering, which represented substantially all of MarkWest Hydrocarbon's natural gas gathering and processing and NGL transportation, fractionation and storage businesses. References to "the Partnership," "we," "our," "us," or like terms refer to MarkWest Energy Partners, L.P. and its operating subsidiaries. References to "MarkWest Hydrocarbon" refer to MarkWest Hydrocarbon, Inc. and its direct and indirect consolidated subsidiaries. We refer to natural gas liquids, such as propane, butanes and natural gasoline, as "NGLs."

MARKWEST ENERGY PARTNERS, L.P.

Overview

        We are a rapidly growing, independent midstream energy limited partnership engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of NGLs and the gathering and transportation of crude oil. A substantial portion of our revenues and cash flows are generated from providing fee-based services to our customers, which limits our commodity price exposure and provides us with a relatively stable base of cash flows.

        Since our initial public offering in May 2002, we have completed six acquisitions for an aggregate purchase price of approximately $352 million. On July 30, 2004, we acquired the Carthage gathering system and natural gas processing assets located in East Texas, which we refer to as our East Texas System, from American Central Eastern Texas Gas Company, Limited Partnership for approximately $240 million. Through recent acquisitions, including the East Texas System acquisition, we have significantly expanded our natural gas gathering, processing and transmission operations in the southwestern United States. We are also the largest processor of natural gas in the Appalachian Basin and the primary intrastate pipeline transporter of crude oil in Michigan. Since our initial public offering, we have increased our quarterly cash distribution per unit in six out of eight quarters, resulting in an aggregate increase of 48%, from $0.50 per unit for our quarterly distribution for our first full quarter ended September 30, 2002 to $0.74 per unit for the quarter ended June 30, 2004.

        We operate primarily in three geographic areas:

•

Southwest. We own 19 natural gas gathering systems in Texas, Oklahoma, Louisiana, Mississippi and New Mexico. We also own a natural gas processing plant in Oklahoma and expect to complete construction of a natural gas processing plant in East Texas by the end of 2005. We currently operate five intrastate natural gas transmission pipelines in Texas and New Mexico that transport natural gas to power plants, municipalities and other large industrial end users. On a pro forma basis for the six months ended June 30, 2004, as adjusted for the East Texas System acquisition, our operations in the Southwest area

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accounted for 58% of our total gross margin, of which 31% was attributable to the East Texas System.

•

Appalachia. We are the largest processor of natural gas in the Appalachian Basin, one of the country's oldest natural gas producing regions, with fully integrated processing, fractionation, storage and marketing operations. Our Appalachian assets include five natural gas processing plants, 136 miles of NGL pipeline, an NGL fractionation plant and an 11-million-gallon NGL storage facility. On a pro forma basis for the six months ended June 30, 2004, as adjusted for the East Texas System acquisition, our operations in Appalachia accounted for 31% of our total gross margin.



•

Michigan. We own a 90-mile natural gas gathering pipeline and a natural gas processing plant in Michigan. We also own approximately 250 miles of intrastate crude oil gathering pipeline, which we refer to as the Michigan Crude Pipeline, the primary intrastate crude oil pipeline in Michigan. On a pro forma basis for the six months ended June 30, 2004, as adjusted for the East Texas System acquisition, our operations in Michigan accounted for 11% of our total gross margin.

        We provide midstream services to our customers under four types of contracts. On a pro forma basis for the six months ended June 30, 2004, as adjusted for the East Texas System acquisition, we generated approximately 60% of our gross margin (revenues less purchased products costs) from contracts under which we charge fees for providing midstream services. Gross margin from these fee-based services largely depends on throughput volume and is typically less affected by short-term changes in commodity prices. On a pro forma basis for the six months ended June 30, 2004, as adjusted for the East Texas System acquisition, our remaining gross margin was generated pursuant to percent-of-index (19%), percent-of-proceeds (15%) and keep-whole contracts (6%). Under percent-of-index contracts, we purchase natural gas at a percentage discount to a specified index price and then deliver the natural gas to pipelines, where we resell the natural gas at the index price or at a different percentage discount to the index price. Under percent-of-proceeds arrangements, we gather and process natural gas on behalf of producers, sell the resulting residue natural gas and NGL volumes at market prices and remit to the producers an agreed-upon percentage of the proceeds based on an index price. Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices. The extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas. Therefore, we must replace these Btus by either purchasing natural gas at market prices for return to producers or making a cash payment to the producers equal to the value of this natural gas.

        Our net income was $6.6 million for the six months ended June 30, 2004. On a pro forma basis, as adjusted for our East Texas System acquisition, our net income for the six months ended June 30, 2004 would have been $6.5 million. Our earnings before income taxes, plus depreciation and amortization expense and interest expense, or EBITDA, was $16.0 million for the six months ended June 30, 2004. On a pro forma basis, as adjusted for our East Texas System acquisition, our EBITDA for the six months ended June 30, 2004 would have been $25.7 million. For a discussion of EBITDA and a reconciliation of EBITDA to net income, please read footnote (2) to "Summary Historical and Pro Forma Financial and Operating Data."

        On a pro forma basis for the six months ended June 30, 2004, as adjusted for the East Texas System acquisition, our gathering, processing, and fractionation and storage activities accounted for 55%, 36% and 9%, respectively, of our gross margin.

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Recent Developments

        East Texas System Acquisition.    On July 30, 2004, we completed the acquisition of American Central Eastern Texas Gas Company, Limited Partnership's Carthage gathering system and natural gas processing assets located in East Texas for approximately $240 million. The acquired assets include 185 miles of existing natural gas gathering system pipelines connected to 1,730 wells with approximately 78 miles of additional pipeline under construction. The natural gas gathering system includes 14 centralized compressor stations with a throughput capacity of 350 MMcf/d. Average throughput volume for August 2004 was 245 MMcf/d. See "Overview of the East Texas System Acquisition."

        We believe that the East Texas System complements our existing operations and provides us with growth opportunities through its attractive characteristics, including the following:

•

majority of cash flows generated from long-term contracts;



•

relatively newer assets than our major competitors in the area;



•

operations in fields characterized by long-lived reserves and recently increased drilling permit activity; and



•

platform for vertically integrating operations by adding processing and other midstream services.

        Financing of East Texas System Acquisition.    Concurrently with the closing of the East Texas System acquisition, we completed a private placement of approximately 1.3 million of our common units and amended and restated our existing credit facility to provide for additional short term-borrowings. We used total net proceeds of $45.1 million from our private placement and borrowings under our amended and restated credit facility to finance the East Texas System acquisition. We intend to apply the net proceeds from this offering to repay a portion of amounts outstanding under our credit facility. Following completion of this offering, we anticipate repaying substantially all of the then-remaining outstanding indebtedness under our credit facility through the issuance of senior notes or other long-term financing. Our ability to complete, and the timing of, these long-term financing transactions will depend on market conditions and other factors. See "Risk Factors."

        Distribution Increase.    On August 13, 2004, we paid a quarterly cash distribution of $0.74 per unit, or $2.96 per unit on an annualized basis, for the quarter ended June 30, 2004. Our 2004 second quarter distribution represents a 7.2% increase over our 2004 first quarter distribution of $0.69 per unit.

Competitive Strengths

        Our competitive strengths include:

•

Strategic position and growing presence in the Southwest. Our East Texas System, Pinnacle, Lubbock and western Oklahoma acquisitions have allowed us to expand our presence in long-lived natural gas basins in the Southwest, particularly in Texas and Oklahoma. The East Texas System and Pinnacle gathering systems are strategically located in the East Texas and Permian Basins in Texas and the western Oklahoma assets are located in the Anadarko Basin in Oklahoma. Each of these areas is experiencing significant development and exploration activities and provides us with an opportunity to capture additional supplies of natural gas. We believe we can use our proven acquisition experience to further develop and expand our presence in the Southwest.

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•

Strategic positions in the Appalachian Basin and Michigan. We are the largest processor of natural gas in Appalachia, and we believe our significant presence and asset base there provide us with a competitive advantage in capturing new supplies of natural gas. The Appalachian Basin is a large natural gas-producing region characterized by long-lived reserves, modest decline rates and natural gas with high NGL content, generating a stable supply of natural gas for our processing plants and our Siloam NGL fractionation facility. Our concentrated infrastructure and available land and storage assets in Appalachia provide us with a platform for additional cost-effective expansion. Our December 2003 acquisition of the Michigan Crude Pipeline allowed us to enter the Michigan crude oil transportation business, where we are now the primary intrastate pipeline transporter of crude oil. We enjoy a competitive advantage over higher cost crude oil transportation alternatives such as trucking. In addition, we own a 90-mile natural gas gathering pipeline and a natural gas processing plant in Michigan. The Niagaran Reef Trend, the area from which most of our natural gas and crude oil in the state is produced, is generally characterized by long-lived natural gas and crude oil reserves.



•

Proven acquisition and integration expertise. Since our initial public offering in May 2002, we have completed six acquisitions for an aggregate purchase price of approximately $352 million. We intend to continue to use our experience in acquiring assets to grow through accretive acquisitions with a focus on opportunities through which we can increase throughput volumes and cash flow.



•

Stable cash flows. On a pro forma basis for the six months ended June 30, 2004, as adjusted for the East Texas System acquisition, we generated 60% of our gross margin from fee-based contracts relating to natural gas gathering, processing and transmission services, NGL transportation, fractionation and storage services and crude oil gathering and transportation services. These fee-based services depend on throughput volume but are typically not affected by short-term changes in commodity prices. In addition, our five lateral pipelines in the Southwest typically generate firm transportation fees independent of the volumes transported. We believe that the fee-based nature of a significant portion of our business and the long-term nature of many of our contracts provide us with a relatively stable base of cash flows.



•

Long-term contracts. In the Southwest, approximately 74% of our current East Texas System gathering volumes are under contract until 2010. Our Pinnacle assets have two significant, fixed-fee contracts for the transmission of natural gas that expire in approximately 19 and 29 years. Approximately 90% of our daily throughput in the Foss Lake gathering system in western Oklahoma is pursuant to contracts with remaining terms of five years or more. In Appalachia, we have natural gas processing and NGL fractionation contracts, which have remaining terms of up to 11 years. In Michigan, our natural gas transportation, treating and processing agreements have terms for the life of the connected wells.



•

Experienced management with operational and technical expertise. Each member of our executive management team has at least 15 years of experience in the energy industry and our facility managers have extensive experience operating our facilities. Our operational and technical expertise has enabled us to upgrade existing facilities and to design and build new facilities. In addition, the ownership of interests in us and our general partner by members of our management, as well as our compensation and incentive plans, helps align the interests of our management team with the interests of our common unitholders.

S-4

•

Financial flexibility. Following the repayment of substantially all of the outstanding indebtedness under our existing credit facility through proceeds from this offering and our anticipated senior notes or other long-term debt financing, we expect to replace our existing credit facility with a new $200 million, multi-year credit facility. Under the terms of this new credit facility, which we expect will be largely undrawn, we expect to be able to finance future acquisitions, expansions and working capital projects. Our ability to complete, and the timing of, these long-term financing transactions will depend on market conditions and other factors.

Business Strategies

        Our primary strategy is to increase distributable cash flow per unit by:

•

Expanding operations through acquisitions. We intend to continue to pursue strategic acquisitions of assets and businesses in our existing areas of operation in order to expand our current asset base, personnel and customer relationships. For example, our East Texas System, Pinnacle, Lubbock and western Oklahoma acquisitions have enabled us to establish and develop a new primary area of operation in the Southwest. In addition, we seek to acquire assets outside of our current areas of operation with a view towards creating new operating areas.



•

Increasing utilization of our facilities. We seek to capture additional natural gas and crude oil supplies from existing customers and to provide services to other natural gas and crude oil producers in our areas of operation. With our current excess capacity, we can increase throughput at our facilities with minimal incremental costs.



•

Expanding operations through new construction. By expanding our existing infrastructure and customer relationships, we intend to continue growing our asset base in our primary areas of operation to meet the anticipated need for additional midstream services. In connection with the East Texas System acquisition, we have 78 miles of natural gas gathering pipeline under construction and expect to complete a new processing plant by December 2005. In addition, drilling in the fields associated with our Appleby gathering system in East Texas and our Foss Lake gathering system in western Oklahoma has significantly increased throughput volumes over the past several years. We expect to complete a new, more efficient processing plant to replace our Cobb processing plant in Appalachia by the end of 2004.



•

Securing additional long-term, fee-based contracts. We intend to continue to secure long-term, fee-based contracts both in our existing operations and through strategic acquisitions in order to minimize our exposure to short-term changes in commodity prices.

Partnership Structure and Management

        Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own all of our subsidiaries through MarkWest Energy Operating Company, L.L.C. Upon completion of this offering:

•

The public unitholders will own a 69.4% limited partner interest in us, represented by 7,314,338 units.



•

MarkWest Hydrocarbon will own 2,469,496 subordinated units and current and former officers and directors of MarkWest Energy GP, L.L.C., our general partner, and current and former officers, directors and key employees of MarkWest Hydrocarbon will own an

S-5

aggregate of 30,504 subordinated units, totaling an aggregate 23.8% limited partner interest in us.

•

Our general partner will continue to own a 2% general partner interest in us, as well as the "incentive distribution rights," which entitle it to receive increasing percentages, up to 50%, of any cash we distribute in excess of $0.55 per unit in any quarter.



•

MarkWest Hydrocarbon will continue to own a 90.2% interest in our general partner. Current and former officers of our general partner and current and former officers and key employees of MarkWest Hydrocarbon will continue to own the remaining 9.8% interest in our general partner.



•

We will continue to own all of the membership interests in the operating company.



•

The operating company will continue to own 100% of its various subsidiary companies.

        Our general partner is entitled to distributions on its general partner interest and, if any, on its incentive distribution rights. Our general partner has sole responsibility for conducting our business and for managing our operations. Our general partner does not receive any management fee or other compensation in connection with its management of our business but is entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.

        The chart on the following page depicts the organization and ownership of MarkWest Energy Partners, L.P. and the operating company after giving effect to this offering.

S-6

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Our Relationship with MarkWest Hydrocarbon, Inc.

        We were formed by MarkWest Hydrocarbon to acquire most of its natural gas gathering and processing and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon is our largest customer, accounting for 42% of our revenues and 59% of our gross margin for the year ended December 31, 2003 and 22% of our revenues and 43% of our gross margin for the six months ended June 30, 2004. On a pro forma basis, as adjusted for our recent East Texas System acquisition, MarkWest Hydrocarbon accounted for 19% of our revenues and 30% of our gross margin for the six months ended June 30, 2004. We will continue for the foreseeable future to derive a significant portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon. Upon completion of this offering, MarkWest Hydrocarbon and its affiliates will own a 23.8% limited partner interest in us and MarkWest Hydrocarbon will continue to direct our business operations through its ownership and control of our general partner. MarkWest Hydrocarbon employees are responsible for conducting our business and operating our assets on our behalf.

        During 2003, MarkWest Hydrocarbon sold substantially all of its oil and natural gas properties. MarkWest Hydrocarbon's remaining business consists of its limited partnership interest in us, its ownership of a controlling interest in our general partner and the marketing of NGLs and natural gas. In 2003, MarkWest Hydrocarbon sold 177 million gallons of NGL products produced at our Siloam facility. In addition to its NGL product sales, MarkWest Hydrocarbon's marketing operations are also responsible for the purchase of natural gas delivered for the account of producers pursuant to its keep-whole processing contracts.

        Our principal executive offices are located at 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112, and our phone number is (303) 290-8700.

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The Offering

Common units offered by us	2,000,000 common units.
	2,323,870 common units if the underwriters exercise their over-allotment option in full.
Common units offered by the selling unitholders	159,138 common units. For information about the selling unitholders, please see "Selling Unitholders."
Units outstanding before this offering	5,314,338 common units and 3,000,000 subordinated units.
Units outstanding after this offering	7,314,338 common units and 3,000,000 subordinated units.
Use of proceeds	We intend to use the net proceeds from this offering of approximately $85.2 million, including our general partner's proportionate capital contribution, after deducting the underwriting discounts and commissions and estimated offering expenses, to repay indebtedness outstanding under our credit facility.
Cash distributions	Common units are entitled to receive quarterly distributions of $0.50 per common unit prior to any distributions on the subordinated units to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. In general, we pay any quarterly cash distributions we make in the following manner:
	•	first, 98% to the common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters;
	•	second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.50; and
	•	third, 98% to all units, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.55 per quarter.
	If cash distributions exceed $0.55 per unit in a quarter, our general partner receives increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as "incentive distributions." Because our distribution for the second quarter 2004 was $0.74 per unit, our general partner received incentive distributions.

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	We must distribute all of our cash on hand, less reserves established by our general partner, at the end of each quarter. We refer to this cash available for distribution as "available cash," and we define its meaning in our partnership agreement. The amount of available cash may be greater than or less than the minimum quarterly distribution.
Timing of distributions	We pay distributions approximately 45 days after March 31, June 30, September 30 and December 31 to unitholders of record on the applicable record date and to our general partner.
Subordination period and early conversion of subordinated units	The subordination period will end once we meet the financial tests in the partnership agreement, but it generally cannot end before June 30, 2009. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. Our partnership agreement provides that subordinated units may convert into common units prior to June 30, 2009 in certain circumstances. Generally, the earliest possible date by which all subordinated units may be converted into common units is June 30, 2007.
Issuance of additional units	In general, during the subordination period we can issue up to 1,207,500 additional common units without obtaining unitholder approval. We can, however, issue an unlimited number of common units for acquisitions, capital improvements or debt repayments that increase cash flow from operations per unit on a pro forma basis. We refer to acquisitions that increase cash flow from operations on a per unit basis as "accretive."
Voting rights	Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates. Following the closing of this offering, our general partner and its affiliates will collectively own 24.2% of the outstanding units.

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Limited call right	If at any time more than 80% of the outstanding common units are owned by our general partner and its affiliates, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then current market price of the common units.
Estimated ratio of taxable income to distributions	We estimate that if you hold the common units you purchase in this offering through the record date for the distribution with respect to the fourth calendar quarter of 2007, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be no more than 10% of the cash distributed to you with respect to that period. Please read "Material Tax Consequences" for the basis of this estimate.
Exchange listing	Our common units are listed on the American Stock Exchange under the symbol "MWE."

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

        The following table shows summary historical financial and operating data of the MarkWest Hydrocarbon Midstream Business and us as of and for the periods indicated and our summary pro forma financial and operating data as of June 30, 2004 and for the year ended December 31, 2003 and for the six months ended June 30, 2004. The MarkWest Hydrocarbon Midstream Business represents substantially all of MarkWest Hydrocarbon's historical natural gas gathering and processing and NGL transportation, fractionation and storage businesses prior to our formation. The summary historical financial data for the MarkWest Hydrocarbon Midstream Business for the year ended December 31, 2001 is derived from the audited financial statements of the MarkWest Hydrocarbon Midstream Business. Our summary historical financial data for the years ended December 31, 2002 and 2003 is derived from the audited financial statements of the Partnership. Our summary historical financial data as of and for the six months ended June 30, 2004 is derived from our unaudited financial statements and, in our opinion, has been prepared on the same basis as the audited financial statements and includes all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information.

        Our unaudited pro forma balance sheet reflects the following transactions as if such transactions occurred as of June 30, 2004:

•

the East Texas System acquisition, which closed July 30, 2004, for consideration of $239.6 million, plus $0.3 million in estimated transaction costs;



•

borrowings of $200.8 million under our credit facility to partially finance the East Texas System acquisition; and



•

our private placement of 1,304,438 common units and a capital contribution from our general partner to maintain its 2% general partner interest, the net proceeds from which were used to partially finance the East Texas System acquisition.

        In addition, our unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2003 and the six months ended June 30, 2004 reflect the following transactions as if such transactions occurred as of January 1, 2003:

•

the East Texas System acquisition, which closed July 30, 2004, for consideration of $239.6 million, plus $0.3 million in estimated transaction costs;



•

borrowings of $200.8 million under our credit facility to partially finance the East Texas System acquisition;



•

our private placement of 1,304,438 common units and a capital contribution from our general partner to maintain its 2% general partner interest, the net proceeds from which were used to partially finance the East Texas System acquisition;



•

the American Central Western Oklahoma acquisition, which closed December 1, 2003, for consideration of $37.9 million, plus $0.1 million in transaction costs;



•

the Michigan Crude Pipeline System acquisition, which closed December 18, 2003, for consideration of $21.2 million, plus $0.1 million in transaction costs;



•

borrowings of $59.3 million under our credit facility to finance the American Central Western Oklahoma and Michigan Crude Pipeline acquisitions;



•

our public offering of 1,172,944 common units on January 13, 2004 at a public offering price of $39.90 per common unit and a capital contribution from our general partner to maintain its 2% general partner interest, the net proceeds from which were used to repay

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indebtedness incurred in connection with the American Central Western Oklahoma and Michigan Crude Pipeline acquisitions;

•

the payment of underwriting fees and commission, and other fees and expenses associated with the January 2004 offering of approximately $3.8 million;



•

the Pinnacle acquisition, which closed March 28, 2003, for consideration of $39.5 million, plus $0.4 million in transaction costs; and



•

our private placement in June 2003 of 375,000 common units and a capital contribution from our general partner to maintain its 2% general partner interest, the net proceeds from which were used to repay indebtedness incurred in connection with the Pinnacle acquisition.

        The historical financial statements for all periods prior to our formation differ substantially from our financial statements and unaudited pro forma financial statements, principally because of the contracts we entered into with MarkWest Hydrocarbon at the closing of our initial public offering. The largest of these differences is in revenues and purchased product costs. Historically, revenues and purchased product costs in the MarkWest Hydrocarbon Midstream Business were higher because:

•

its revenues included the aggregate sales price for all the NGL products produced in its operations; and



•

its purchased product costs included the cost of natural gas purchases needed to replace the Btu content of the NGLs extracted in its processing operations under keep-whole contracts and the percentage of the proceeds from the sale of NGL products remitted to producers under percent-of-proceeds contracts.

        In contrast, after entering into contractual arrangements in connection with our initial public offering:

•

our revenues related to these assets include only the fees we receive for processing natural gas, transporting, fractionating and storing NGLs and the aggregate proceeds from NGL sales we receive under our percent-of-proceeds contracts; and



•

our purchased product costs related to these assets primarily consist of the percentage of proceeds from the sale of NGL products remitted to producers under our percent-of-proceeds contracts, with a small portion of our purchased product costs attributable to natural gas purchases to satisfy our obligations under our keep-whole contracts.

        Sustaining capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as facility expenses as we incur them.

        We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included in our Annual Report on Form 10-K/A for the year ended December 31, 2003, our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 and our Current Report on Form 8-K/A filed September 13, 2004, which are incorporated by reference into this prospectus supplement and the accompanying prospectus. The table should be read together with "Management's Discussion and Analysis of Financial Condition

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and Results of Operations" included in our Annual Report on Form 10-K/A for the year ended December 31, 2003 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004.

			MarkWest Hydrocarbon Midstream Business			Partnership
															Pro Forma
			Year Ended December 31,									Six Months Ended June 30, 2004						Six Months Ended June 30, 2004
															Year Ended December 31, 2003
			2001			2002(1)			2003
			($ in thousands, except per unit amounts)
Statement of Operations Data:
Total revenues			$	93,675		$	70,246		$	117,537		$	128,244		$	209,806		$	145,349
Operating expenses:
	Purchased product costs			65,483			38,906			70,832			95,060			128,018			97,492
	Facility expenses			13,138			15,101			20,463			12,421			30,862			15,564
	Selling, general and administrative expenses			5,047			5,283			7,686			4,724			9,204			4,977
	Depreciation			4,490			4,980			7,548			6,671			22,849			12,368
	Management fee			—			—			—			—			3,529			1,468
	Impairment expense			—			—			1,148			—			1,148			—
		Total operating expenses		88,158			64,270			107,677			118,876			195,610			131,869
		Income from operations		5,517			5,976			9,860			9,368			14,196			13,480
Interest expense, net				(1,307	)		(1,414	)		(4,057	)		(2,802	)		(21,037	)		(6,842	)
Miscellaneous income (expense)				—			52			(25	)		(1	)		(279	)		(138	)
	Income (loss) before income taxes			4,210			4,614			5,778			6,565			(7,120	)		6,500
Provision (benefit) for income taxes				1,624			(17,175	)		—			—			—			—
		Net income (loss)	$	2,586		$	21,789		$	5,778		$	6,565		$	(7,120	)	$	6,500
Basic net income (loss) per limited partner unit						$	4.86		$	0.96		$	0.88		$	(0.85	)	$	0.72
Diluted net income (loss) per limited partner unit						$	4.83		$	0.96		$	0.87		$	(0.85	)	$	0.72
Balance Sheet Data (at period end):
Property, plant and equipment, net			$	82,008		$	79,824		$	184,214		$	186,708					$	263,341
Total assets				104,891			87,709			212,978			219,598						464,457
Total debt, including debt due to parent				19,179			21,400			126,200			86,200						287,000
Total partners' capital							61,574			65,549			106,351						150,410
Cash Flow Data:
Net cash flow provided by (used in):
	Operating activities		$	(524	)	$	33,502		$	21,229		$	14,450
	Investing activities			(8,997	)		(2,056	)		(112,893	)		(9,139	)
	Financing activities			9,521			(28,670	)		97,641			(5,193	)
Other Financial Data:
EBITDA(2)			$	10,007		$	11,008		$	17,383		$	16,038		$	36,766		$	25,710
Sustaining capital expenditures			$	576		$	511		$	1,041		$	756
Expansion capital expenditures				9,075			1,634			1,903			6,250
		Total capital expenditures	$	9,651		$	2,145		$	2,944		$	7,006

S-14

		MarkWest Hydrocarbon Midstream Business	Partnership
						Pro Forma
		Year Ended December 31,			Six Months Ended June 30, 2004		Six Months Ended June 30, 2004
						Year Ended December 31, 2003
		2001	2002(1)	2003
Operating Data:
Appalachia:
	Natural gas processed (Mcf/d)	192,000	202,000	202,000	202,000	202,000	202,000
	NGLs fractionated for a fee (Gal/d)	423,000	476,000	458,000	469,000	458,000	469,000
	NGL product sales (gallons)	—	99,235,000	40,305,000	21,927,000	40,305,000	21,927,000
Michigan:
	Natural gas processed for a fee (Mcf/d)	8,800	13,800	15,000	13,000	15,000	13,000
	NGL product sales (gallons)	8,000,000	11,100,000	11,800,000	5,103,000	11,800,000	5,103,000
	Crude oil transported for a fee (Bbl/d)	—	—	—	14,700	15,700	14,700
Southwest:
	Gathering systems throughput (Mcf/d)	—	—	55,000	100,900	311,000	317,800
	Lateral throughput volumes (Mcf/d)	—	—	—	74,100	—	74,100
	NGL product sales (gallons)	—	—	—	16,512,000	105,178,000	36,740,000

(1)

We restated our financial and operating results for the year ended December 31, 2002 to present our 2002 results under one combined column that includes our operations both before and after our initial public offering. Prior to the restatement, our 2002 financial results were shown separately for periods prior to and following our initial public offering. Generally, this combination required simple addition of the previously bifurcated line items. In addition, in connection with the restatement we recorded the elimination of deferred tax liabilities resulting from our conversion to partnership form in our statement of operations. Such elimination was previously presented as an adjustment to our capital. In our revised presentation, the elimination of the deferred tax liability is reflected in the statement of operations as a part of the provision (benefit) for income taxes, increasing net income by $17.2 million and income per unit by $3.86.

(2)

EBITDA is defined as income before income taxes, plus depreciation and amortization expense and interest expense. We present EBITDA on a partnership basis which includes both the general and limited partner interests. EBITDA (i) is not a measure of performance calculated in accordance with generally accepted accounting principles, or GAAP, and (ii) 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.

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 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, including the ability to fund capital expenditures, service debt and pay distributions. Additionally, management believes that 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 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.

EBITDA is used by management to determine our operating performance and along with other data as an internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, evaluating targeted businesses for acquisition and determining incentive compensation. We have a number of business locations located in different regions of the United States. EBITDA can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them.

S-15

There are material limitations to using a measure such as EBITDA, including the difficulty associated with using it as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company's net income or loss. Management compensates for these limitations by considering EBITDA in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income and cash flow from operating activities. In addition, our calculation of EBITDA may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. EBITDA for the periods described herein is calculated in the same manner as presented by us in the past. A reconciliation of EBITDA to net income is presented below.

The following table reconciles EBITDA with our net income and pro forma net income (loss):

		MarkWest Hydrocarbon Midstream Business		Partnership
											Pro Forma
		Year Ended December 31,							Six Months Ended June 30, 2004					Six Months Ended June 30, 2004
											Year Ended December 31, 2003
		2001		2002(1)			2003
		($ in thousands)
Net income (loss)		$	2,586	$	21,789		$	5,778	$	6,565	$	(7,120	)	$	6,500
Plus:
	Interest expense, net		1,307		1,414			4,057		2,802		21,037			6,842
	Depreciation		4,490		4,980			7,548		6,671		22,849			12,368
	Provision (benefit) for income taxes		1,624		(17,175	)		—		—		—			—
EBITDA		$	10,007	$	11,008		$	17,383	$	16,038	$	36,766		$	25,710

S-16

RISK FACTORS

        You should read carefully the discussion of the material risks relating to our business under the caption "Risk Factors" beginning on page 1 of the accompanying prospectus, as well as those risks discussed in our Annual Report on Form 10-K/A for the year ended December 31, 2003, which are incorporated by reference into this prospectus supplement and the accompanying prospectus. If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected. In that case, the trading price of our common units could decline and you could lose all or part of your investment.

We may be unable to successfully integrate the East Texas System acquisition with our operations or realize all of the anticipated benefits of the East Texas System acquisition.

        Integration of the East Texas System business and operations with our existing business and operations will be a complex, time-consuming and costly process. Failure to successfully integrate the East Texas System business and operations with our existing business and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the operations include, among other things:

•

operating a significantly larger combined organization and integrating additional midstream operations to our existing operations;



•

coordinating geographically disparate organizations, systems and facilities;



•

integrating personnel from diverse business backgrounds and organizational cultures; and



•

consolidating corporate and administrative functions.

        In addition, we may not realize all of the anticipated benefits from our acquisition of the East Texas System. In particular, we may not achieve the potential cost savings and revenue enhancements described in "Overview of the East Texas System Acquisition" due to a number of potential factors including difficulties integrating operations, higher costs and fluctuations in markets.

        We will also be exposed to risks that are commonly associated with transactions similar to this acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management's attention. Moreover, these new assets are subject to the same stringent environmental laws and regulations relating to releases of pollutants into the environment and environmental protection as are our existing plants, pipelines and facilities, and thus our operation of these new assets could cause us to incur increased costs to maintain compliance with such laws and regulations. As a result, the anticipated benefits of the acquisition may not be fully realized, if at all.

We may not be able to repay or refinance the short-term debt we incurred in connection with the East Texas System acquisition.

        In connection with our acquisition of the East Texas System, we borrowed approximately $200.8 million of indebtedness under our amended and restated credit facility. Of that amount, $50.0 million is due in December 2004 and the remainder of that debt is due in May 2005. We intend to apply the net proceeds of this offering to retire the debt due in December 2004 and a portion of the debt due in May 2005. Following the completion of this offering, we anticipate repaying substantially all of the remaining outstanding indebtedness due in May 2005 through the

S-17

issuance of senior notes or other long-term debt financing. Our ability to complete, and the timing of, these or other long-term financing transactions will depend on market conditions, operating performance and other factors. If we are unable to successfully complete any or all of the transactions in connection with our long-term financing plan in a timely manner, or on attractive terms, our business, financial condition, results of operations and cash flows may be materially adversely affected.

We depend on third parties for the raw natural gas we transport through our East Texas System facilities, and any reduction in these quantities could reduce our ability to make distributions to our unitholders.

        We depend on numerous suppliers, including Devon Energy, to provide a significant portion of the raw natural gas for our transportation through the East Texas System. For the six months ended June 30, 2004, Devon Energy accounted for 42% of the throughput volume on the East Texas System. If Devon Energy, or a significant number of other producers, were to decrease materially the supply of raw natural gas to our East Texas System facilities for any reason, we could experience difficulty in replacing those lost volumes. Because our operating costs are primarily fixed, a reduction in the volumes of raw natural gas delivered to us would result not only in a reduction of revenues but also a decline in net income and cash flow of similar or greater magnitude, which would reduce our ability to make distributions to our unitholders.

Transportation on our Michigan Crude Pipeline could become subject to the jurisdiction of the Federal Energy Regulatory Commission.

        The Michigan Crude Pipeline is not currently subject to the jurisdiction of the Federal Energy Regulatory Commission, or FERC. If a shipper sought to challenge the jurisdictional status of this pipeline, however, FERC could determine that transportation on this pipeline is within its jurisdiction under the Interstate Commerce Act, thereby requiring us to file a tariff and cost-based rates for such transportation with FERC. While no shipper has filed a formal complaint, one shipper on the Michigan Crude Pipeline has contacted FERC to complain about the transportation rates and question the jurisdictional status of the pipeline. FERC requested that we and the shipper resolve the dispute. If we are unable to successfully resolve this dispute or any future dispute over the jurisdictional status of the Michigan Crude Pipeline, it could become subject to FERC regulation, and the cost of compliance with that regulation could adversely affect our profitability.

S-18

USE OF PROCEEDS

        The net proceeds of this offering will be approximately $85.2 million, including our general partner's proportionate capital contribution, after deducting the underwriting discounts and commissions and estimated offering expenses. We anticipate using the aggregate net proceeds of this offering to repay a portion of the outstanding indebtedness under our credit facility.

        We incurred approximately $200.8 million of indebtedness under our credit facility to fund the East Texas System acquisition. As of August 31, 2004, there was $291.0 million outstanding under our credit facility with a weighted average interest rate of 5.6% per annum. Following completion of this offering, we anticipate repaying substantially all of the then-remaining outstanding indebtedness under our amended and restated credit facility through the issuance of senior notes or other long-term financing. Our ability to complete, and the timing of, these long-term financing transactions will depend on market conditions and other factors.

        We will use the proceeds from any exercise of the underwriters' over-allotment option to repay additional amounts of borrowings under our credit facility.

        We will not receive any proceeds from the sale of 159,138 common units by the selling unitholders.

S-19

CAPITALIZATION

        The following table sets forth our capitalization as of June 30, 2004:

•

on an actual basis;



•

on a pro forma basis to give effect to the financing related to the East Texas System acquisition, including our private placement of 1,304,438 common units and borrowings of $200.8 million under our amended and restated credit facility; and



•

on a pro forma as adjusted basis to give further effect to (i) the common units offered by this prospectus supplement, (ii) our general partner's capital contribution and (iii) the application of the net proceeds from this offering in the manner described under "Use of Proceeds."

        This table should be read together with our historical financial statements and the accompanying notes incorporated by reference into this prospectus supplement and the accompanying prospectus.

				As of June 30, 2004
				Actual			Pro Forma for the East Texas System Acquisition			Pro Forma As Adjusted
				($ in thousands)
Total debt				$	86,200		$	287,000		$	201,787
Capital:
	Common units				92,422			136,052			219,477
	Subordinated units				11,984			11,532			11,532
	General partner interest				1,250			2,131			3,919
	Other				695			695			695
	Accumulated other comprehensive income (loss)				(1,145	)		(1,145	)		(1,145	)
		Total capital			105,206			149,265			234,478
			Total capitalization	$	191,406		$	436,265		$	436,265

        This table does not reflect the issuance of up to 323,870 common units that may be sold to the underwriters upon exercise of their over-allotment option, the proceeds of which will be used to further repay indebtedness outstanding under our credit facility.

S-20

PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

        Our initial public offering was completed on May 24, 2002. As of the close of business on September 1, 2004, there were 5,314,338 common units outstanding held by approximately 136 holders of record, including common units held in street name and common units held by our general partner. Our common units are traded on the American Stock Exchange under the symbol "MWE."

        As of September 7, 2004, 3,000,000 subordinated units were outstanding. The subordinated units are held by current and former affiliates of our general partner and one other investor and are not publicly traded.

        The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the American Stock Exchange, and quarterly cash distribution paid to our unitholders. The last reported sales price of our common units on the American Stock Exchange on September 9, 2004 was $44.05 per common unit.

		Sales Price Ranges
						Cash Distribution per Unit
		High		Low
2004
	Third Quarter (through September 9, 2004)	$	45.80	$	37.73	$	—
	Second Quarter		40.07		33.50		0.74
	First Quarter		41.66		33.70		0.69
2003
	Fourth Quarter	$	40.90	$	34.05	$	0.67
	Third Quarter		35.98		29.55		0.64
	Second Quarter		32.50		25.30		0.58
	First Quarter		26.00		22.95		0.58
2002
	Fourth Quarter	$	23.50	$	20.80	$	0.52
	Third Quarter		22.64		17.90		0.50
	Second Quarter		21.90		20.50		0.21	(1)

(1)

The distribution for the second quarter of 2002 was prorated for the period from May 24, 2002, the closing date of our initial public offering, through June 30, 2002.

S-21

OVERVIEW OF THE EAST TEXAS SYSTEM ACQUISITION

        On July 30, 2004, we acquired certain natural gas gathering assets located in East Texas from American Central Eastern Texas Gas Company, Limited Partnership for $240 million. The acquired assets, which we refer to as our East Texas System, are located in Panola County, Texas and consist of:

•

approximately 185 miles of natural gas gathering system pipelines;



•

approximately 78 miles of additional natural gas gathering system pipelines currently under construction; and



•

14 centralized compressor stations representing approximately 61,500 horsepower of compression (with an additional 23,900 horsepower currently being installed as gathering system compression and processing plant recompression).

        The gathering system currently serves approximately 20 producers in the Carthage Field through central receipt points sourced by natural gas production from approximately 1,730 upstream well connections. The gathering system has a throughput capacity of approximately 350 MMcf/d and had average throughput volumes of 245 MMcf/d in August 2004. In addition, we anticipate increasing our throughput volumes to over 300 MMcf/d by the end of 2004 by connecting additional volumes currently under contract. We recently secured gathering and processing contractual commitments from ChevronTexaco and TotalFinaElf for the connection of additional natural gas production of approximately 95 MMcf/d for January 2005. We intend to seek additional gathering and processing contracts with producers not currently served by the gathering system and to add incremental volumes through system expansion into the Bethany and Beckville areas of the Carthage field that will be accessible upon completion of the system expansion.

        To increase our midstream services available to producers connected to our gathering system, provide natural gas processing required to meet downstream pipeline quality specifications and expand the existing system footprint to receive new natural gas dedicated to the system, we are currently constructing gathering pipeline additions, compression additions and a new processing facility and planning the construction of an NGL pipeline at an aggregate total projected cost of approximately $55 million, which we expect to complete by December 2005. Once the pipeline and compression additions are operational, we will be positioned to pursue future expansion into surrounding natural gas supply areas, particularly the Beckville and Bethany areas. We expect that the new processing plant will have a capacity of 175 MMcf/d. We are pursuing dedication of additional processing volumes that are gathered on the system and are considering expanding the plant as contractually committed processing volumes increase.

        During plant construction, we are processing natural gas at the Duke Energy Field Services East Texas plant under an existing processing agreement that expires on December 31, 2005. Under the terms of this contract, we expect to receive processing income of less than $1.5 million in 2005.

S-22

Rationale for the Acquisition

        We believe that the East Texas System complements our existing businesses in several ways and provides us with a number of growth opportunities through its attractive characteristics, including the following:

•

The majority of the East Texas System's cash flow is generated from its natural gas gathering operations, which are tied to contracts generally ranging in length from five to 10 years.



•

The East Texas System features natural gas pipelines with centralized receipt points connected to common suction or common discharge gathering pipelines. This configuration provides a high degree of reliability and enables us to offer both low and high-pressure service to our customers. The system benefits from low fuel and operating costs because of its design, age and large, efficient, standardized compressor stations.



•

We believe that the Carthage Field served by the East Texas System is an attractive operating area for us because it has long-lived reserves and significant development potential. To date, more than 12 trillion cubic feet, or Tcf, of natural gas has been produced from the the Carthage Field. The level of drilling permit activity in Panola County has increased from 2003 to 2004 due to a combination of higher natural gas prices and improved technology.



•

The East Texas System provides us with a platform on which to vertically integrate our operations through the planned construction of a 175 MMcf/d natural gas processing facility. We have already obtained contractual commitments that will fill the plant's capacity.

Overview of the East Texas System

        Geographic Market.    The East Texas System is strategically located in Panola County, which encompasses the Carthage Field, one of Texas' largest onshore natural gas fields. Panola County consists of the Cotton Valley, Pettit and Travis Peak formations and is one of the largest natural gas producing regions in the United States. The Carthage Field has approximately 18 Tcf of estimated ultimate reserves and cumulative historical production in excess of 12 Tcf. According to industry sources, there were 4,158 active wells in the field during May 2004, 1,730 of which were connected to the East Texas System.

        Gathering Operations.    The East Texas System is a regional gathering system designed to provide relatively low-cost gathering service at consistent operating pressures over a broad geographic area. Substantially all of the system was constructed within the last 10 years, which makes our natural gas pipelines generally newer than competing gathering systems in the area. The low-pressure system design allows for natural gas production to be distributed or balanced across 14 centralized compressor stations with an aggregate of approximately 61,500 horsepower, with an additional 23,900 of new compression currently being planned. These stations are designed to operate in unison, to respond to gathering system dynamics and to automatically load and unload the compressors based on operating pressures and volumes.

        Automation technology allows the gathering system to be balanced daily on an MMcf/d and on an MMbtu/d basis. All system inlets are compared to system outlets (natural gas redeliveries, fuel, NGLs, and condensates) to accurately manage the system and minimize system losses. Monitoring technology also is used to compare producers' nominations to actual flows to minimize end-of-the-month pipeline imbalances.

S-23

        The gathering system was designed and constructed to operate as a closed system, which means hydrocarbons are not released or vented into the atmosphere during normal operations. Specifically, all hydrocarbon liquids that condense in the pipeline system are collected and transported to the liquid handling and vapor recovery facility. The high-pressure hydrocarbon liquids are then stabilized into condensate, which is trucked and sold. The hydrocarbon vapors from the high-pressure liquids are compressed to 1,050 per square inch for delivery to the processing plant, where they are converted into NGL products. During 2003, the East Texas System gathered 204 MMcf/d of natural gas, and hydrocarbon liquid production was 1,016 Bbls/d.

        Gathering Fee Arrangements.    The East Texas System gathering revenues are derived from the following three fee-arrangements:

•

Fixed gathering and compression fees. Fixed gathering and compression fees accounted for 39% of the East Texas System's total gathering margin for the six months ended June 30, 2004. Typically, gathering and compression fees are comprised of a fixed fee portion in which producers pay a fixed rate per unit to transport their natural gas through the gathering system. Under the majority of these contracts, fees are escalated annually based on the Consumer Price Index.



•

Settlement margin. Settlement margin accounted for 37% of the East Texas System's total gathering margin for the six months ended June 30, 2004. Typically, the terms of these contracts specify that we are allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed line losses. To the extent the East Texas System is operated more efficiently than provided for by contracted allowances, we are entitled to retain the difference for our own account.



•

Condensate sales. Condensate sales (otherwise known as pipeline drip) accounted for 24% of the East Texas System's total gathering margin for the six months ended June 30, 2004. During the gathering process, thermodynamic forces contribute to changes in operating conditions of the natural gas flowing through the pipeline infrastructure. As a result, hydrocarbon dew points are reached, causing condensation of hydrocarbons in the high- pressure pipelines. The East Texas System retains 100% of condensate collected in the system and sells the condensate at a monthly crude-oil based price.

        In July 2004, Devon Energy, ConocoPhillips, BP Amoco, Samson, XTO Energy, EOG Resources, Anadarko, ExxonMobil, ChevronTexaco and TotalFinaElf were the East Texas System's largest customers based on system throughput, collectively accounting for approximately 95% of total system throughput.

        Processing Plant and NGL Transportation.    We are currently constructing a 175 MMcf/d skid-mounted cryogenic processing plant designed to recover ethane and heavier hydrocarbons. The plant will be able to operate efficiently in an ethane recovery or rejection mode. A plant expansion is already under consideration based on the availability of additional processable natural gas currently gathered on the system. Plant residue natural gas will be delivered to both the Natural Gas Pipeline Company of America and the Carthage Hub. We also expect to construct an NGL pipeline to effect eventual delivery of the recovered plant products to Mount Belvieu for fractionation and sale. The plant and related pipeline are scheduled for completion by December 2005.

        Regulation.    The East Texas System is subject to the Texas Utilities Code, as implemented by the Texas Railroad Commission, or TRRC. Generally, the TRRC has authority to ensure that rates and/or operations and services of gas utilities, intrastate pipelines and gathering systems are just and reasonable and not discriminatory. Rates are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulations of gas utilities, intrastate pipelines and gathering systems.

S-24

MANAGEMENT

        The following table shows information for the directors and executive officers of MarkWest Energy GP, L.L.C., our general partner. Executive officers are appointed and directors are elected by the owners of our general partner for one-year terms.

Name	Age	Position with our General Partner
John M. Fox	64	Chairman of the Board of Directors
Frank M. Semple	52	President, Chief Executive Officer and Director
Charles K. Dempster	62	Director
Donald C. Heppermann	61	Director
William A. Kellstrom	63	Director
William P. Nicoletti	59	Director
James G. Ivey	53	Senior Vice President and Chief Financial Officer
John C. Mollenkopf	43	Senior Vice President, Southwest Business Unit
Randy S. Nickerson	43	Senior Vice President, Corporate Development
Andrew L. Schroeder	45	Vice President, Finance, Treasurer and Secretary
Ted S. Smith	54	Vice President and Chief Accounting Officer
David L. Young	44	Senior Vice President, Northeast Business Unit

John M. Fox has served as Chairman of the Board of Directors of our general partner since May 2002 and has served in the same capacity with MarkWest Hydrocarbon since its inception in April 1988. Mr. Fox also served as President and Chief Executive Officer of our general partner and of MarkWest Hydrocarbon from April 1988 until his retirement as President on November 1, 2003 and his retirement as Chief Executive Officer effective December 31, 2003. Mr. Fox was a founder of Western Gas Resources, Inc. and was its Executive Vice President and Chief Operating Officer from 1972 to 1986. Mr. Fox holds a bachelor's degree in engineering from the United States Air Force Academy and a master of business administration degree from the University of Denver.

Frank M. Semple was appointed as President of both our general partner and MarkWest Hydrocarbon on November 1, 2003. Mr. Semple also became Chief Executive Officer of both our general partner and MarkWest Hydrocarbon on January 1, 2004 and also became a director of our general partner and MarkWest Hydrocarbon in January 2004. Prior to his appointment, Mr. Semple served in various capacities, lastly as Chief Operating Officer, with WilTel Communications, formerly Williams Communications from 1997 to 2003. Prior to his tenure at WilTel Communications, he was the Senior Vice President/General Manager of Williams Natural Gas from 1995 to 1997 as well as Vice President of Marketing and Vice President of Operations and Engineering for Northwest Pipeline and Director of Product Movements and Division

S-25

Manager for Williams Pipeline during his 22-year career with the Williams Companies. During his tenure at Williams Communications, he served on the board of directors for PowerTel Communications and the Competitive Telecommunications Association (Comptel). He currently serves on the board of directors for the Tulsa Zoo and the Children's Medical Center. Mr. Semple holds a bachelor's degree in mechanical engineering from the United States Naval Academy.

Charles K. Dempster has served as a member of the board of directors of our general partner since December 2002. Mr. Dempster has more than 30 years of experience in the natural gas and power industry. He held various management and executive positions with Enron Corporation and its predecessors between 1969 and 1986, focusing on natural gas supply, transmission and distribution. From 1986 through 1992 Mr. Dempster served as President of Reliance Pipeline Company and Executive Vice President of Nicor Oil and Gas Corporation, which were oil and natural gas midstream and exploration subsidiaries of Nicor Inc. in Chicago. He was appointed President of Aquila Energy Corporation in 1993, a wholly owned midstream, pipeline and energy-trading subsidiary of Utilicorp, Inc. Mr. Dempster retired in 2000 as Chairman and CEO of Aquila Energy Company. Mr. Dempster holds a bachelor's degree in civil engineering from the University of Houston and attended graduate business school at the University of Nebraska.

Donald C. Heppermann has served on our general partner's board of directors since its inception in May 2002 and will continue to serve as Chairman of the Finance Committee. Mr. Heppermann previously served as Executive Vice President, Chief Financial Officer and Secretary of our general partner from October 2003 until his retirement in March 2004. He joined our general partner and MarkWest Hydrocarbon in November 2002 as Senior Vice President and Chief Financial Officer and served as Senior Executive Vice President beginning in January 2003. Prior to joining our general partner and MarkWest Hydrocarbon, Mr. Heppermann was a private investor and a career executive in the energy industry with major responsibilities in operations, finance, business development and strategic planning. From 1990 to 1997 he served as President and Chief Operating Officer for InterCoast Energy Company, an unregulated subsidiary of Mid American Energy Company. From 1987 to 1990 Mr. Heppermann was employed by Pinnacle West Capital Corporation, the holding company for Arizona Public Service Company, where he was Vice President of Finance. From 1965 to 1987, Enron Corporation and its predecessors employed Mr. Heppermann in a variety of positions, including Executive Vice President, Gas Pipeline Group. Mr. Heppermann holds a bachelor's degree in accounting from the University of Missouri and a master of business degree from Creighton University.

William A. Kellstrom has served as a member of the Board of Directors of our general partner since its inception in May 2002 and has served as a director of MarkWest Hydrocarbon since May 2000. Mr. Kellstrom has held a variety of managerial positions in the natural gas industry since 1968. They include distribution, pipelines and marketing. He held various management and executive positions with Enron Corp., including Executive Vice President, Pipeline Marketing and Senior Vice President, Interstate Pipelines. In 1989, he created and was President of Tenaska Marketing Ventures, a natural gas marketing company for the Tenaska Power Group. From 1992 until 1997 he was with NorAm Energy Corporation (which later merged with Reliant Energy, Incorporated) where he was President of the Energy Marketing Company and Senior Vice President, Corporate Development. Mr. Kellstrom holds an engineering degree from Iowa State University and a master of business administration degree from the University of Illinois. He retired in 1997 and is periodically engaged as a consultant to energy companies.

William P. Nicoletti has served as a member of the Board of Directors of our general partner since its inception in May 2002. Mr. Nicoletti is Managing Director of Nicoletti & Company Inc., a private banking firm serving clients in the energy and transportation industries. In addition,

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Mr. Nicoletti has served as a Senior Advisor to the Energy Investment Banking Group of McDonald Investments Inc. From March 1998 until July 1999, Mr. Nicoletti was a Managing Director and co-head of Energy Investment Banking for McDonald Investments Inc. Prior to forming Nicoletti & Company Inc. in 1991, Mr. Nicoletti was a Managing Director and head of Energy Investment Banking for PaineWebber Incorporated. Previously, he held a similar position at E.F. Hutton & Company Inc. Mr. Nicoletti is a director and Chairman of the Audit Committee of Star Gas LLC, the general partner of Star Gas Partners, L.P, a retail propane and heating oil master limited partnership. He is also a director of Southwest Royalties, Inc., an oil and natural gas exploration and production company and Russell-Stanley Holdings, Inc., a manufacturer and marketer of steel and plastic industrial containers. Mr. Nicoletti is a graduate of Seton Hall University and received an MBA degree from Columbia University Graduate School of Business.

James G. Ivey has served as Chief Financial Officer of MarkWest Hydrocarbon and our general partner since June 2004. Prior to joining MarkWest, Mr. Ivey served as Treasurer of The Williams Companies from 1999 to April 30, 2004 and as acting Chief Financial Officer from mid-2002 to mid-2003. Prior to joining Williams, Mr. Ivey held similar positions with Tenneco Gas and NORAM Energy. Prior to that, he held various engineering positions with Conoco and Fluor Corp. He currently serves on the board of directors for MACH Gen LLC and the Tulsa Boys Home. Mr. Ivey is a graduate of Texas A&M University with a B.S. in Building Construction, the University of Houston with a MBA, the Army Command and General Staff College and the Duke University Advanced Management Program. Mr. Ivey retired in early 2004 from the Army Reserve with the rank of Colonel.

John C. Mollenkopf was appointed Senior Vice President, Southwest Business Unit of our general partner in January 2004 and previously served as Vice President, Business Development since January 2003. Prior to that, he served as Vice President-Michigan Business Unit of our general partner since its inception in May 2002 and in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Mollenkopf was General Manager of the Michigan Business Unit of MarkWest Hydrocarbon since 1997. He joined MarkWest Hydrocarbon in 1996 as Manager, New Projects. From 1983 to 1996, Mr. Mollenkopf worked for ARCO Oil and Gas Company, holding various positions in process and project engineering, as well as operations supervision. Mr. Mollenkopf holds a bachelor's degree in mechanical engineering from the University of Colorado at Boulder.

Randy S. Nickerson has served as Senior Vice President, Corporate Development of our general partner since October 2003. Prior to that, Mr. Nickerson served as Executive Vice President, Corporate Development of our general partner from January 2003 and as Senior Vice President of our general partner since its inception in May 2002 and has served in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Nickerson served as MarkWest Hydrocarbon's Vice President and the General Manager of the Appalachia Business Unit from June 1997. Mr. Nickerson joined MarkWest Hydrocarbon in July 1995 as Manager, New Projects and served as General Manager of the Michigan Business Unit from June 1996 until June 1997. From 1990 to 1995, Mr. Nickerson was a Senior Project Manager and Regional Engineering Manager for Western Gas Resources, Inc. From 1984 to 1990, Mr. Nickerson worked for Chevron USA and Meridian Oil Inc. in various process and project engineering positions. Mr. Nickerson holds a bachelor's degree in chemical engineering from Colorado State University.

Andrew L. Schroeder currently serves as Vice President, Finance, Treasurer and Secretary for our general partner and has been employed by our general partner since February 2003. Prior to his appointment, he was Director of Finance/Business Development at Crestone Energy Ventures from 2001 through 2002. Prior to that Mr. Schroeder worked at Xcel Energy for two years as

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Director of Corporate Financial Analysis. Prior to that, he spent seven years working with various energy companies. He began his career with Touche, Ross & Co. and spent eight years in public accounting. Mr. Schroeder holds a master's of taxation from the University of Denver and a bachelor's degree in business from the University of Colorado. He is a Certified Public Accountant licensed in the state of Colorado.

Ted S. Smith was appointed as Vice President and Chief Accounting Officer of our general partner in March 2004. Prior to that, he served as a Vice President of our general partner beginning on his arrival in March 2003, via the Pinnacle Natural Gas Company merger. Prior to that time, Mr. Smith had been Senior Vice President and Chief Financial Officer for Pinnacle Natural Gas Corporation from 1999. From 1994 through 1999 he was Chief Financial Officer for Total Safety Inc., and from 1987 to 1994 Mr. Smith served as Assistant Treasurer and Director of Management Information Systems at American Oil and Gas Corporation in Houston, Texas. Prior to that, Mr. Smith held various senior executive finance and accounting positions with several energy services organizations. Mr. Smith holds a bachelor's degree in finance from Texas A&M University and is a Certified Public Accountant licensed in the state of Texas.

David L. Young was appointed Senior Vice President, Northeast Business Unit of our general partner effective February 1, 2004. Prior to joining MarkWest, Mr. Young spent eighteen years at the Williams Companies in Tulsa, Oklahoma, having served most recently as Vice President and General Manager for WilTel Communications' video services business from 2001 to 2004. Prior to that, Mr. Young's management positions at the Williams Companies included serving as Senior Vice President and General Manager for Texas Gas Pipeline and Williams Central Pipeline Company. Mr. Young holds a bachelor's degree in petroleum engineering from the Colorado School of Mines.

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SELLING UNITHOLDERS

        The following table shows the beneficial ownership of common units held by the selling unitholders as of September 9, 2004 and to be held following the offering. Each of the selling unitholders acquired its common units in connection with the June 2003 private placement.

        We and the selling unitholders are parties to a registration rights agreement. This registration rights agreement gives the holders of the securities covered under the agreement rights to request registration of their common units and to participate in any registration by us of any of our common units for sale to the public pursuant to the Securities Act (other than in connection with mergers, acquisitions, exchange offers, options or other employee benefit plans). We are required to pay all registration expenses if these registration rights are exercised, other than underwriting discounts and selling commissions.

	Common Units Beneficially Owned Prior to this Offering			Common Units Beneficially Owned Following this Offering
Name of Selling Unitholder	Number	Percentage Owned	Units Offered in this Offering	Number	Percentage Owned
JAS Trust, Country Club Bank N.A. Trustee 414 Nichols Road P.O. Box 410889 Kansas City, MO 64141	19,062	*	19,062	0	—
Jeane Marie Swalm 405 Merry-Go-Round Rock Road Sedona, AZ 86341	19,062	*	14,515	4,547	*
Robert A. Tucci and Cynthia L. Tucci, JTWROS 8631 Cedar Dr. Prairie Village, KS 66207	19,062	*	5,800	13,262	*
Elkan, L.L.C. 4200 Somerset Drive, Suite 200 Prairie Village, KS 66208	9,531	*	9,531	0	—
Curtis A. Krizek Revocable Trust UTA dated 12/17/98, Curtis A. Krizek, Trustee 4200 Somerset Drive, Suite 200 Prairie Village, KS 66208	11,437	*	11,437	0	—
Jonathan E. Baum Revocable Trust U/A dated 1/29/92, Jonathan E. Baum, Trustee 3600 W. 64th Street Mission Hills, KS 66208	4,765	*	4,765	0	—
Timothy S. Webster Revocable Trust dated 4/10/00, Timothy S. Webster, Trustee 3700 W. 65th Street Mission Hills, KS 66208	9,531	*	9,531	0	—

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Richard B. Klein Revocable Trust Richard B. Klein and Lynn M. Klein, Trustees 8104 W. 99th St. Overland Park, KS 66212	9,531	*	3,500	6,031	*
Michael G. Smith 221 N. Adams Hinsdale, IL 60521	9,531	*	9,531	0	—
Sally S. Hikene Revocable Trust dated 8/30/2002, Sally S. Hikene Trustee 2700 Verona Road Shawnee Mission, KS 66208	3,812	*	3,812	0	—
Frederick M. Solberg, Jr. and Elizabeth T. Solberg, Tenants by the Entirety 850 W. 52nd Street Kansas City, MO 64112	3,812	*	3,812	0	—
Edward D. Durwood 3001 W. 68th Street Shawnee Mission, KS 66208	5,718	*	5,718	0	—
Bradford M. Epsten 1030 W. 66th Terrace Kansas City, MO 64112	5,718	*	5,718	0	—
Laura Marcia Wolff Greenbaum Trust dated 9/20/78, Laura Wolff Greenbaum Trustee 6035 High Drive Shawnee Mission, KS 66208	5,718	*	3,450	2,268	*
Brian N. Kaufman and Susan C. Kaufman JTWROS 4972 W. 88th Street Prairie Village, KS 66207	4,765	*	4,765	0	—
A. Scott Ritchie III 8831 Clubside Ct. Wichita, KS 67206	4,000	*	4,000	0	—
Frank J. Cucchiara and Jo Marie Cucchiara JTWROS 26724 W. Greentree Ct. Olathe, KS 66061	3,812	*	3,812	0	—
The Lewis White Trust U/D/T dated 12/29/86, as amended 8900 State Line Road, Suite 333 Leawood, KS 66206	3,812	*	3,812	0	—

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Dolores Arn Underhill Trust, Dolores Arn Underhill Trustee 4 N. Encino Laguna Beach, CA 92651	3,812	*	3,812	0	*
John D. Starr Trust dated 11/10/93, John D. Starr Trustee 833 West 51st Street Kansas City, MO 64112	3,049	*	3,049	0	*
Jeffrey C. Reene Revocable Trust dated 10/20/99, Jeffrey C. Reene Trustee 9808 High Drive Leawood, KS 66206	2,859	*	2,859	0	*
Jason Talley and Amarilis Talley, Tenants by the Entirety 300 Loch Lloyd Parkway Belton, MO 64012	2,287	*	2,287	0	*
George D. and Lisa M. Shadid, Trustees u/t/a dated 07/03/00, George D. Shadid, donor 801 W. 58th Terrace Kansas City, MO 64113	2,859	*	715	2,144	*
Theresa K. Freilich Revocable Trust dated 3/28/2003, Theresa K. Freilich Trustee 5252 Sunset Drive Kansas City, MO 64113	1,906	*	1,906	0	*
Peter P. Dreher and Nancy D. Dreher, JTWROS 5129 Woodland Avenue Western Springs, IL 60302	1,906	*	906	1,000	*
Robyn R. Schneider Revocable Trust, Robyn R. Schneider Trustee 20 E. 3rd Street Hinsdale, IL 60521	1,906	*	906	1,000	*
James S. Gerson Revocable Trust Dtd 04/94, James S. Gerson Trustee 6516 Overbrook Road Mission Hills, KS 66208	1,524	*	1,524	0	*
Midwest Venture Capital, LLC 1100 Main Street, Suite 350 Kansas City, MO 64105	12,000	*	6,000	6,000	*

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Roger Brent Stover 6841 Linden Prairie Village, KS 66208	2,860	*	2,860	0	*
Kansas City Equity Partners, LC 233 West 47th Street Kansas City, MO 64112	2,028	*	2,028	0	*
Gerald W. Buetow, Jr. 1705 Owensfield Drive Charlottesville, VA 22901	1,000	*	1,000	0	*
Brian K. Smith Trust 5744 Sheridan Drive Fairway, KS 66205	1,000	*	1,000	0	*
Larry H. Powell 5620 Mission Drive Mission Hills, KS 66208	953	*	953	0	*
IMREX, L.P. 400 W. 2nd Washington, KS 66968	762	*	762	0	*

*Less than 1%

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MATERIAL TAX CONSEQUENCES

        The tax consequences to you of an investment in our common units will depend in part on your own tax circumstances. For a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of common units, please read "Material Tax Consequences" in the accompanying prospectus. You are urged to consult your own tax advisor about the federal, state, foreign and local tax consequences peculiar to your circumstances.

        We estimate that if you purchase common units in this offering and own them through the record date for the distribution with respect to the fourth calendar quarter of 2007, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 10% of the amount of cash distributed to you with respect to that period.

        This estimate is based upon the assumption that our available cash for distribution will approximate the amount required to distribute cash to the holders of common units in an amount equal to the current quarterly distribution of $0.74 per unit and other assumptions with respect to capital expenditures, cash flows and anticipated cash distributions. This estimate and our assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, this estimate is based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service might disagree. Accordingly, we cannot assure you that this estimate will be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could materially affect the value of the common units. See "Material Tax Consequences" in the accompanying prospectus.

        Ownership of common units by tax-exempt entities, regulated investment companies and foreign investors raises issues unique to such persons. Please read "Material Tax Consequences — Tax-Exempt Organizations and Other Investors" in the accompanying prospectus.

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UNDERWRITING

        Subject to the terms and conditions stated in the underwriting agreement among us, the selling unitholders and the underwriters, dated the date of this prospectus supplement, each underwriter named below has agreed to purchase from us and the selling unitholders the number of common units set forth opposite the underwriter's name.

Name	Number of Common Units
RBC Capital Markets Corporation
A.G. Edwards & Sons, Inc.
Wachovia Capital Markets, LLC
KeyBanc Capital Markets, a division of McDonald Investments Inc.
Stifel, Nicolaus & Company, Incorporated
Total

        The underwriting agreement provides that the underwriters' obligations to purchase the common units depend on the satisfaction of the conditions contained in the underwriting agreement and that if any of our or the selling unitholders' common units are purchased by the underwriters, all of our and the selling unitholders' common units must be purchased. The conditions contained in the underwriting agreement include the condition that all of the representations and warranties made by us and the selling unitholders to the underwriters are true, that there has been no material adverse change in the condition of us or in the financial markets and that we and the selling unitholders deliver to the underwriters customary closing documents.

        The following table shows the underwriting fees to be paid to the underwriters by us and the selling unitholders in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units. This underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us and the selling unitholders to purchase the common units. On a per unit basis, the underwriting fee is    % of the initial price to the public.

		Paid by Us
		No Exercise	Full Exercise
Per common unit		$	$
	Total	$	$

        We estimate that total expenses of the offering, other than underwriting discounts and commissions, will be approximately $0.5 million.

        We and the selling unitholders have been advised by the underwriters that the underwriters propose to offer our and the selling unitholders' common units directly to the public at the initial price to the public set forth on the cover page of this prospectus supplement and to dealers (who may include the underwriters) at this price to the public less a concession not in excess of $    per unit. The underwriters may allow, and the dealers may reallow, a concession not in excess of $    per unit to certain brokers and dealers. After the offering, the underwriters may change the offering price and other selling terms.

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        We and the selling unitholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act or to contribute to payments that may be required to be made with respect to these liabilities.

        We have granted to the underwriters an option to purchase up to an aggregate of 323,870 additional common units at the initial price to the public less the underwriting discount set forth on the cover page of this prospectus supplement exercisable solely to cover over-allotments, if any. Such option may be exercised in whole or in part at any time until 30 days after the date of this prospectus supplement. If this option is exercised, each underwriter will be committed, subject to satisfaction of the conditions specified in the underwriting agreement, to purchase a number of additional common units proportionate to the underwriter's initial commitment as indicated in the preceding table, and we will be obligated, pursuant to the option, to sell these common units to the underwriters.

        We, our general partner, the directors and the executive officers of the general partner, certain other affiliates and the selling unitholders have agreed that during the 90 days after the date of this prospectus supplement, they will not, without the prior written consent of RBC Capital Markets Corporation, directly or indirectly, offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units, other than (1) pursuant to employee benefit plans in existence as of the date of this prospectus or (2) in connection with accretive acquisitions of assets or businesses in which common units are issued as consideration; provided, however, that with respect to clause (2), any recipient of common units will furnish to RBC Capital Markets Corporation a letter agreeing to be bound by these provisions for the remainder of the 90 day period.

        RBC Capital Markets Corporation, in its sole discretion, may release the units subject to lock-up agreements in whole or in part at any time with or without notice. When determining whether or not to release units from lock-up agreements, RBC Capital Markets Corporation will consider, among other factors, the unitholders' reasons for requesting the release, the number of units for which the release is being requested and market conditions at the time.

        In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.



•

Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common units in the open market.



•

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In

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determining the source of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the underwriters sell more common units than could be covered by the over-allotment option, which we refer to in this prospectus as a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

•

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

        Similar to other purchase transactions, the underwriters' purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market.

        These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the American Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

        Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, if commenced, will not be discontinued without notice.

        Certain underwriters and their affiliates have performed, and may in the future perform, various financial advisory, investment banking and other commercial banking services in the ordinary course of business with us and our affiliates for which they have received or will receive customary compensation. In addition, an affiliate of RBC Capital Markets Corporation is a lender under our credit facility and will be partially repaid with a portion of the net proceeds from this offering.

        Because the National Association of Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD's Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

        No sales to accounts over which any underwriter exercises discretionary authority may be made without the prior written approval of the customer.

        A prospectus supplement in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree

S-36

with us to allocate a specific number of units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

        Other than the prospectus supplement in electronic format, information contained in any other web site maintained by an underwriter or selling group member is not part of this prospectus supplement or the registration statement of which this prospectus supplement forms a part, has not been endorsed by us and should not be relied on by investors in deciding whether to purchase any units. The underwriters and selling group members are not responsible for information contained in web sites that they do not maintain.

LEGAL MATTERS

        The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

        The financial statements of MarkWest Energy Partners, L.P. and the Midstream Business appearing in the Partnership's Annual Report on Form 10-K/A, for the year ended December 31, 2003 have been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as set forth in their reports thereon included therein and incorporated herein by reference. Such financial statements are incorporated herein by reference in reliance upon such reports given on the authority of such firm as experts in auditing and accounting.

        The financial statements of American Central East Texas Gas Company, L.P. incorporated in this prospectus supplement by reference from MarkWest Energy Partners, L.P.'s Current Report on Form 8-K/A filed with the Securities and Exchange Commission on September 13, 2004, have been audited by BKD, LLP, an independent registered public accounting firm, as set forth in their reports thereon included therein and incorporated herein by reference. Such financial statements are incorporated herein by reference in reliance upon such reports given on the authority of such firm as experts in auditing and accounting.

FORWARD-LOOKING STATEMENTS

        Statements included in this prospectus supplement and the accompanying prospectus and any documents we incorporate by reference that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as "may," "believe," "estimate," "expect," "plan," "intend," "project," "anticipate," and similar expressions to identify forward-looking statements.

        These forward-looking statements are based on management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

        Important factors that could cause our actual results of operations or our actual financial condition to differ include, but are not necessarily limited to:

•

The availability of raw natural gas supply for our gathering and processing services;

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•

The availability of NGLs for our transportation, fractionation and storage services;



•

Our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas, including MarkWest Hydrocarbon;



•

The risks that third-party oil and natural gas exploration and production activities will not occur or be successful;



•

Prices of NGL products and crude oil, including the effectiveness of any hedging activities, and indirectly by natural gas prices;



•

Competition from other NGL processors, including major energy companies;



•

Changes in general economic conditions in regions in which our products are located; and



•

Our ability to identify and consummate grass roots projects or acquisitions complementary to our business.

        These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We do not update publicly any forward-looking statement. We caution you not to put undue reliance on forward-looking statements. You should read "Risk Factors" included on page S-17 of this prospectus supplement and page 1 of the accompanying prospectus, as well as those risks discussed in our Annual Report on Form 10-K/A for the year ended December 31, 2003, for further information.

WHERE YOU CAN FIND MORE INFORMATION

        We have filed a registration statement with the Securities and Exchange Commission, or SEC, under the Securities Act that registers the common units offered by this prospectus supplement. The registration statement, including the attached exhibits, contains additional relevant information about us. In addition, we file annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on their public reference room. Our SEC filings are also available at the SEC's web site at www.sec.gov. You can also obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

        The SEC allows us to "incorporate by reference" the information we have filed with the SEC. This means that we can disclose important information to you without actually including the specific information in this prospectus supplement or the accompanying prospectus by referring you to those documents. The information incorporated by reference is an important part of this prospectus supplement and the accompanying prospectus. Information that we file later with the SEC and that is deemed to be "filed" with the SEC will automatically update and may replace information in this prospectus supplement and the accompanying prospectus and information previously filed with the SEC.

        In addition to the documents listed in "Where You Can Find More Information" on page ii of the accompanying prospectus, we incorporate the documents listed below and any future filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act, other than

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information under Item 9 or Item 12 of any Current Report on Form 8-K. These reports contain important information about us, our financial condition and results of operations.

•

Our Amendment No. 1 to Annual Report on Form 10-K/A for the year ended December 31, 2003;



•

Our Quarterly Reports on Form 10-Q for the periods ended March 31, 2004 and June 30, 2004;



•

Our Current Reports on Forms 8-K and 8-K/A filed March 1, 2004; March 22, 2004; April 16, 2004; August 13, 2004; September 9, 2004; and September 13, 2004; and



•

The description of our common units contained in our registration statement on Form 8-A filed February 14, 2002 and any amendment thereto filed for the purpose of updating such description.

        We make available free of charge on or through our Internet website, www.markwest.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our Internet website is not part of this prospectus supplement or the accompanying prospectus and you should not consider information contained on our Internet website as part of this prospectus supplement or the accompanying prospectus.

        You may request a copy of any document incorporated by reference in this prospectus, at no cost, by writing or calling us at the following address:

MarkWest Energy Partners, L.P.
155 Inverness Drive West, Suite 200
Englewood, CO 80112-5000
Attention: Andrew L. Schroeder
(303) 290-8700

S-39

PROSPECTUS

$300,000,000

MarkWest Energy Partners, L.P.

Common Units
Debt Securities

        We may from time to time offer the following securities under this prospectus:

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common units representing limited partner interests in MarkWest Energy Partners, L.P; and



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debt securities of MarkWest Energy Partners L.P.

        Our common units are traded on the American Stock Exchange under the symbol "MWE."

        Each time we sell securities we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. You should read this prospectus and any prospectus supplement carefully before you invest. You should also read the documents we have referred you to in the "Where You Can Find More Information" section of this prospectus for information on us and for our financial statements.

        The selling unitholders may offer and sell from time to time up to 827,444 of our common units, including common units available upon conversion of subordinated units, in connection with this prospectus. Unless otherwise provided in a prospectus supplement, we will not receive any proceeds from the sale of common units by the selling unitholders.

Limited partnerships are inherently different from corporations. You should carefully consider each of the factors described under "Risk Factors," which begin on page 1 of this prospectus before you make an investment in our securities.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is July 27, 2004

TABLE OF CONTENTS

        You should rely only on the information contained or incorporated by reference in this prospectus or any prospectus supplement. We have not authorized any other person to provide you with different information. You should not assume that the information incorporated by reference or provided in this prospectus or any prospectus supplement is accurate as of any date other than the date on the front of each document.

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ABOUT THIS PROSPECTUS

        This prospectus is part of a registration statement that we have filed with the Securities and Exchange Commission using a "shelf" registration process. Under this shelf registration process, we may offer from time to time up to $300,000,000 of our common units or debt securities, and the selling unitholders may sell up to an aggregate of 827,444 common units from time to time. Each time we offer securities, we will provide you with a prospectus supplement that will describe, among other things, the specific amounts and prices of the securities being offered and the terms of the offering. The prospectus supplement may also add, update or change information contained in this prospectus. Therefore, before you invest in our securities, you should read this prospectus and any attached prospectus supplements.

        As used in this prospectus, "we," "us," "our," "the Partnership" and "MarkWest Energy Partners" mean MarkWest Energy Partners, L.P. and, where the context requires, include our operating subsidiaries.

WHERE YOU CAN FIND MORE INFORMATION

        We file annual, quarterly and special reports and other information with the Securities and Exchange Commission under the Securities Exchange Act of 1934. You can inspect and/or copy these reports and other information at offices maintained by the SEC, including:

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the principal offices of the SEC located at Judiciary Plaza, 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549; and



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The SEC's website at http://www.sec.gov.

        In addition, please call the SEC at 1-800-732-0330 for further information on their public reference room.

        Further, our common units are listed on the American Stock Exchange, and you can inspect similar information at the offices of the American Stock Exchange, located at 86 Trinity Place, New York, New York 10006.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

        The SEC allows us to incorporate by reference information we file with it into this prospectus. This procedure means that we can disclose important information to you by referring you to documents on file or to be filed with the SEC. The information we incorporate by reference is part of this prospectus and later information that we file with the SEC will automatically update and supersede this information. Therefore, before you decide to invest in a particular offering under this shelf registration, you should always check for SEC reports we may have filed after the date of this prospectus. We incorporate by reference the documents listed below and any future filings we make with the SEC under Section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 (excluding any information furnished pursuant to Item 9 or Item 12 on any Current Report on Form 8-K) until all offerings under this shelf registration are completed:

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Quarterly Report on Form 10-Q for the period ended March 31, 2004;



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Annual Report on Form 10-K for the year ended December 31, 2003;



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Current Reports on Form 8-K filed with the SEC on March 1, 2004, March 11, 2004, March 22, 2004, April 16, 2004 and May 6, 2004; and



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The descripton of our common units contained in our Form 8-A, initially filed with the SEC on February 14, 2002, and any subequent amendment thereto filed for the purpose of updating such description.

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        You may request a copy of these filings at no cost by making written or telephone requests for copies to:

MarkWest Energy Partners, L.P.
155 Inverness Drive West, Suite 200
Englewood, CO 80112-5000
Attention: Andrew L. Schroeder
Telephone: (303) 290-8700

FORWARD-LOOKING STATEMENTS

        Statements included in this prospectus which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto) are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements.

        These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

        Important factors that could cause our actual results of operations or our actual financial condition to differ include, but are not necessarily limited to:

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the availability of raw natural gas supply for our gathering and processing services;



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the availability of NGLs for our transportation, fractionation and storage services;



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our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas, including MarkWest Hydrocarbon, Inc.;



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the risks that third-party natural gas exploration and production activities will not occur or be successful;



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prices of NGL products and crude oil, including the effectiveness of any hedging activities, and indirectly by natural gas prices;



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competition from other NGL processors, including major energy companies;



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changes in general economic conditions in regions in which our products are located;



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our ability to identify and consummate grass roots projects or acquisitions complementary to our business; and



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our ability to integrate our acquisitions.

        These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. The Partnership undertakes no obligation to update publicly any forward-looking statement whether as a result of new information or future events.

        For a more detailed description of these particular forward-looking statements and for other factors that may affect any forward-looking statements, see the section entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 of our most recently filed Annual Report on Form 10-K, as incorporated herein by reference.

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        When considering any forward-looking statement, you should also keep in mind the risk factors described under the section entitled "Risk Factors" beginning on page 1 of this prospectus and any other risk factors described in an applicable prospectus supplement. Investors are cautioned not to put undue reliance on forward-looking statements.

ABOUT MARKWEST ENERGY PARTNERS

        We are engaged in the gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquids (NGLs). We are the largest processor of natural gas in the northeastern United States, processing gas from the Appalachian basin, one of the country's oldest natural gas producing regions, and from Michigan. As a result of three acquisitions completed during 2003, we have expanded our natural gas gathering, processing and transmission geographic coverage to include the southwest United States. A fourth 2003 acquisition has resulted in our entry into the Michigan crude oil transportation business.

        We focus on providing fee-based services to customers and attempt to limit our commodity price risks. Our assets are grouped into one business segment—midstream services. Our primary strategy is to increase distributable cash flow per unit by:

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Increasing utilization of our existing facilities.  We seek to capture additional natural gas production from existing customers and to provide services to other natural gas producers in our areas of operation.



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Expanding operations through new construction.  By leveraging our existing infrastructure and customer relationships, we intend to continue expanding our asset base in our primary areas to meet the anticipated need for additional midstream services.



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Expanding operations through acquisitions.  We intend to pursue strategic acquisitions of assets and businesses in our existing areas of operation in order to leverage our current asset base, personnel and customer relationships. Our acquisition of approximately 250 miles of an intrastate crude gathering pipeline in Michigan, which we refer to as the Michigan Crude Pipeline, allows us to take advantage of our existing Michigan infrastructure and personnel. In addition, we seek to acquire assets outside of our existing areas of operation with a view towards creating new core operating areas. Our Pinnacle, Lubbock pipeline and western Oklahoma acquisitions enabled us to establish and develop a new primary area of operation in the Southwest.



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Securing additional long-term, fee-based contracts.  We intend to continue to secure long-term, fee-based contracts in both our existing operations and when we complete strategic acquisitions. While fee-based arrangements are dependent on throughput volume, they are typically less affected by short-term changes in commodity prices than other contractual arrangements in our industry.

        MarkWest Energy Partners, L.P., a publicly traded Delaware limited partnership, began conducting operations on May 24, 2002, the date of the closing of our initial public offering (the IPO). We were formed by MarkWest Hydrocarbon, Inc. (MarkWest Hydrocarbon) to acquire most of its natural gas gathering and processing and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon formed us as a publicly traded limited partnership primarily to reduce our cost of capital thereby enhancing our ability to more efficiently grow our operations. The limited partnership structure provides us with access to capital markets as a source of financing in addition to that provided by our credit facility, as well as the ability to use common units in connection with acquisitions.

        Our principal executive office is located at 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112-5000. Our telephone number is 303-290-8700. Our common units trade on the American Stock Exchange under the symbol "MWE."

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RISK FACTORS

        Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in the common units.

        If any of the following risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Inherent in Our Business

If we are unable to successfully integrate our recent or future acquisitions, our future financial performance may be negatively impacted.

        Our future growth will depend in part on our ability to integrate our recent acquisitions, and our ability to make future acquisitions of assets and businesses at attractive prices. We recently completed the western Oklahoma and Michigan Crude Pipeline acquisitions, which geographically expanded our operations in the Southwest, particularly Oklahoma, and expanded our operations in Michigan. We cannot assure you that we will successfully integrate these or any other acquisitions into our operations, or that we will achieve the desired profitability from such acquisitions. Failure to successfully integrate these substantial or future acquisitions could adversely affect our operations and cash flows available for distribution to our unitholders.

        The integration of acquisitions with our existing business involves numerous risks, including:

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difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographic area;



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the loss of customers or key employees from the acquired businesses;



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the diversion of management's attention from other business concerns; and



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the failure to realize expected synergies and cost savings.

        Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse from the seller under applicable indemnification provisions or otherwise. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

        Our acquisition strategy is based in part on our expectation of ongoing divestitures of assets within the midstream industry. A material decrease in such divestitures will limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.

Our indebtedness may limit our ability to borrow additional funds, make distributions to you or capitalize on acquisitions or other business opportunities.

        Borrowings under our credit facility vary and can be material as we finance our working capital needs and expansion and acquisition opportunities. Payments of principal and interest on the

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indebtedness will reduce the cash available for distribution on our units. Our credit facility contains various covenants limiting our ability to incur indebtedness, grant liens, engage in transactions with affiliates, make distributions to our unitholders and capitalize on acquisition or other business opportunities. It also contains covenants requiring us to maintain certain financial ratios and minimum tangible net worth. We are prohibited from making any distribution to unitholders if such distribution would cause a default or an event of default under our credit facility. Borrowings under our bank credit facility that are used to pay distributions to unitholders are also limited. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's fees and expenses to enable us to pay the minimum quarterly distribution.

        We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. Under the terms of our partnership agreement, we must pay our general partner's fees and expenses and set aside any cash reserve amounts before making a distribution to our unitholders. Our ability to pay the minimum quarterly distribution will depend upon a number of factors, some of which are beyond our control, including:

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cash flow generated by our operations;



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the costs of acquisitions, if any;



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fluctuations in our working capital;



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restrictions contained in our debt instruments and required payments of principal and interest on our debt;



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our ability to make borrowings under our credit facility;



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the level of capital expenditures we make;



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prevailing economic conditions; and



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the amount, if any, of cash reserves made by our general partner in its discretion.

        Furthermore, you should be aware that our ability to pay the minimum quarterly distribution each quarter depends primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record profits.

A significant decrease in natural gas production in our areas of operation, due to the decline in production from existing wells, depressed commodity prices or otherwise, would reduce our ability to make distributions to our unitholders.

        Our profitability is materially impacted by the volume of natural gas we gather, transmit and process and NGLs we transport and fractionate at our facilities. A material decrease in natural gas production in our areas of operation would result in a decline in the volume of natural gas delivered to our pipelines and facilities for gathering, transmitting and processing and NGLs delivered to our pipelines and facility for fractionation and transportation. The effect of such a material decrease would be to reduce our revenue and operating income and, therefore, our ability to make distributions to our unitholders. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the "decline rate." In addition, we have no control over

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producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. Failure to connect new wells to our gathering systems would, therefore, result in the amount of natural gas we gather, transmit and process and the amount of NGLs we transport and fractionate being reduced substantially over time and could, upon exhaustion of the current wells, cause us to abandon our gathering systems and, possibly, cease gathering operations. Our ability to connect to new wells will be dependent on the level of drilling activity in our areas of operations and competitive market factors. As a consequence of such declines, our revenues and our ability to make distributions to unitholders would be materially adversely affected.

A material decrease in the supply of crude oil available for transport through our Michigan Crude Pipeline, or a significant decrease in demand for refined products in the markets served by this pipeline could adversely affect our revenues and cash flow.

        The volume of crude oil we transport through our Michigan Crude Pipeline depends on the availability of attractively priced crude oil produced in the areas accessible to our crude oil pipeline. If there were a material decrease in the volume of crude oil shipped on the pipeline due to reduced production from our shippers, less expensive supplies of crude oil available to the markets served by our pipeline, competition from trucks or reduced demand for refined product, our revenues would be reduced unless we are able to raise our tariffs on the pipeline sufficiently to offset the revenues lost due to the reduced volumes. Our ability to raise tariffs might be constrained by competitive market forces.

        Likewise, a sustained decrease in demand for refined products in the markets served by our crude oil pipeline would adversely affect our revenues and cash flow. Factors that could lead to a decrease in market demand include:

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a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel fuel, and travel;



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an increase in the market price of crude oil that leads to higher refined product prices;



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higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products; and



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a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise.

We depend upon third parties for the raw natural gas we process and the NGLs we fractionate at our Appalachian facilities, and any reduction in these quantities could reduce our ability to make distributions to our unitholders.

        We depend upon Columbia Natural Resources, Inc., or Columbia Resources, and Equitable Production Company, or Equitable, to provide a significant portion of the raw natural gas and NGLs for our processing, transportation, fractionation, and storage facilities in the Appalachian basin.

        Raw natural gas from Columbia Resources, Equitable and the other third party producers are committed to us pursuant to our processing agreements with MarkWest Hydrocarbon and our contract with Equitable. The raw gas and NGLs committed to us by MarkWest Hydrocarbon are in turn committed to it pursuant to its agreements with third party producers. We depend on these contracts for our supply of natural gas and NGLs. Pursuant to these contracts, Columbia Resources, Equitable and the other producers are under no obligation to deliver a specific quantity of raw natural gas or NGLs to our facilities. If Columbia Resources, Equitable or a significant number of other producers

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were to decrease materially the supply of raw natural gas or NGLs to our facilities for any reason, we could experience difficulty in replacing those lost volumes. Because our operating costs are primarily fixed, a reduction in the volumes of raw natural gas or NGLs delivered to us would result not only in a reduction of revenues but also a decline in net income and cash flow of similar or greater magnitude, which would reduce our ability to make distributions to our unitholders.

We derive a significant portion of our revenues from our gas processing, transportation, fractionation and storage agreements with MarkWest Hydrocarbon and its failure to satisfy its payment or other obligations under these agreements could reduce our revenues and cash flow and in turn reduce our ability to make distributions to our unitholders.

        Historically, MarkWest Hydrocarbon has accounted for a material percentage of our revenues and a substantial percentage of our gross margin. These revenues and margins are generated by the volumes of raw natural gas contractually committed to MarkWest Hydrocarbon by the Appalachian producers described above, and the fees generated from processing, transportation, fractionation and storage services provided to MarkWest Hydrocarbon. We expect to derive a significant portion of our revenues and gross margin from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future. Any default or nonperformance by MarkWest Hydrocarbon of its contractual obligations to us could significantly reduce our revenues and cash flows and reduce our ability to make distributions to our unitholders. Thus, any factor or event adversely affecting MarkWest Hydrocarbon's business, creditworthiness or its ability to perform under its contracts with us or its other contracts related to our business could also adversely affect us.

The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation and storage agreements may not escalate sufficiently to cover increases in costs and the agreements may not be renewed or may be suspended in some circumstances, which would reduce our ability to make distributions to our unitholders.

        Our costs may increase at a rate greater than the rate that the fees that we charge to third parties increase pursuant to our contracts with them. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties' obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of either natural gas, NGLs or crude oil are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of equipment or facilities of the Partnership or third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with us, or if any third party suspends or terminates its contracts with us, our ability to make distributions to our unitholders will be reduced.

We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

        We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.

        The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including

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competition from other pipelines, and the price of, and demand for, natural gas, NGLs and crude oil in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of whom have greater financial resources and access to raw natural gas and NGL supplies than we do. Additionally, our customers who gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services. In addition, certain of our competitors may have advantages in competing for acquisitions or other new business opportunities because of their financial resources and access to raw natural gas and NGL supplies.

        As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

Growing our business by constructing new pipelines and processing and treating facilities subjects us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities.

        One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new gathering, processing and treating facilities. The construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital, which may exceed our expectations, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project. Furthermore, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

Our profitability is affected by the volatility of NGL product and natural gas prices.

        The profitability of our natural gas processing and NGL fractionation operations is affected by volatility in prevailing NGL product and natural gas prices. Changes in the prices of NGL products correlate closely with changes in the price of crude oil. NGL product and natural gas prices have been subject to significant volatility in recent years in response to relatively minor changes in the supply and demand for NGL products and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including:

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the level of domestic oil, natural gas and NGL production;



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imports of crude oil, natural gas and NGLs;



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seasonality;

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the condition of the United States economy;



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political conditions in other oil-producing and natural gas-producing countries; and



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domestic government regulation, legislation and policies.

        The gross margin we realize under percent-of-proceeds and percent-of-index contracts is directly affected by changes in NGL product prices and natural gas prices, and is therefore more subject to volatility in commodity prices than our fee-based contracts. Additionally, changes in natural gas prices may indirectly impact our profitability since prices can influence drilling activity and well operations and thus the volume of gas we gather and process.

        In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue.

We are subject to operating and litigation risks that may not be covered by insurance.

        Our operations are subject to all operating hazards and risks incidental to processing, transporting, fractionating, and storing natural gas and NGLs and to transporting and storing crude oil. These hazards include:

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damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;



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inadvertent damage from construction and farm equipment;



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leakage of crude oil, natural gas, NGLs and other hydrocarbons;



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fires and explosions; and



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other hazards, including those associated with high-sulfur content, or sour gas, that could also result in personal injury and loss of life, pollution and suspension of operations.

        As a result, we may be a defendant in various legal proceedings and litigation arising from our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

Our business is subject to federal, state and local laws and regulations with respect to environmental, safety and other regulatory matters, and the violation of or the cost of compliance with such laws and regulations could adversely affect our profitability.

        Our business is subject to the jurisdiction of numerous governmental agencies with respect to a wide range of environmental, safety and other regulatory matters. We could be adversely affected by increased costs due to more strict pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely impact our products and activities, including the gathering, processing, transportation, fractionation, and storage of raw natural gas and NGLs and the transportation and storage of crude oil. Federal and state agencies also could impose additional safety requirements, any of which could affect our profitability. In addition, we face the risk of accidental releases or spills associated with our operations, which could result in material costs and liabilities, including those relating to claims for damages to property and persons.

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        Furthermore, our gas gathering and crude oil transportation operations in Michigan are subject to regulation at the state level, which increases the costs of operating our pipeline facilities. Matters subject to regulation include rates on our natural gas pipelines, as well as service and safety on all our pipelines. In addition, our lateral pipelines in Texas and Oklahoma are subject to the jurisdiction of the Texas Railroad Commission and the Oklahoma Corporation Commission, respectively. Changes in state regulations, or our status under these regulations due to configuration changes in our operating facilities, that subject us to further regulation could have a material adverse effect on our financial condition.

We are indemnified for liabilities arising from an ongoing remediation of property on which our facilities are located and our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if the indemnifying party fails to perform its indemnification obligation.

        Columbia Gas is the previous or current owner of the property on which our Kenova, Boldman, Cobb and Kermit facilities are located and is the previous operator of our Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman and Cobb facilities pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and the U.S. Environmental Protection Agency and, in the case of the Boldman facility, an "Agreed Order" with the Kentucky Natural Resources and Environmental Protection Cabinet.

        Columbia Gas has agreed to retain sole liability and responsibility for, and to indemnify MarkWest Hydrocarbon against, any environmental liabilities associated with these regulatory orders or the real property underlying these facilities to the extent such liabilities arose prior to the effective date of the agreements pursuant to which such properties were acquired or leased from Columbia Gas. At the closing of our initial public offering, MarkWest Hydrocarbon assigned us the benefit of its indemnity from Columbia Gas with respect to the Cobb, Boldman and Kermit facilities. While we are not a party to the agreement under which Columbia Gas agreed to indemnify MarkWest Hydrocarbon with respect to the Kenova facility, MarkWest Hydrocarbon has agreed to provide to us the benefit of its indemnity, as well as any other third-party environmental indemnity of which it is a beneficiary. MarkWest Hydrocarbon has also agreed to provide us an additional environmental indemnity pursuant to the terms of the omnibus agreement. Our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if in the future either Columbia Gas or MarkWest Hydrocarbon fails to perform under the indemnification provisions of which we are the beneficiary.

The amount of gas we process, gather and transmit or the crude oil we gather and transport may be reduced if the pipelines to which we deliver the natural gas or crude oil cannot or will not accept the gas or crude oil.

        All of the natural gas we process, gather and transmit is delivered into pipelines for further delivery to end users. If these pipelines cannot or will not accept delivery of the gas due to downstream constraints on the pipeline, we will be forced to limit or stop the throughput of gas through our pipelines and processing systems. In addition, interruption of pipeline service upstream of our processing facilities would likewise limit or stop throughput through our processing facilities. Likewise, if the pipelines into which we deliver crude oil are interrupted, we will be limited in, or prevented from, conducting our crude oil transportation operations. Such interruptions or constraints on pipeline service may be caused by any number of factors beyond our control, including necessary and scheduled maintenance as well as unexpected damage to the pipeline. Since our revenues and gross margin depend upon the volumes of natural gas we process, gather and transmit, the throughput of NGLs through our transportation, fractionation and storage facilities and the volume of crude oil we gather and transport, any such limitation or reduction of volumes could result in a material reduction in our gross margin.

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Our business would be adversely affected if operations at any of our facilities were interrupted.

        Our operations are dependent upon the infrastructure that we have developed, including processing and fractionation plants, storage facilities and various means of transportation. Any significant interruption at these facilities or pipelines or our inability to transmit natural gas or NGLs, or transport crude oil to or from these facilities or pipelines for any reason would adversely affect our results of operations. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:

•

unscheduled turnarounds or catastrophic events at our physical plants;



•

labor difficulties that result in a work stoppage or slowdown; and



•

a disruption in the supply of crude oil to our crude oil pipeline, natural gas to our processing plants or gathering pipelines, or a disruption in the supply of NGLs to our transportation pipeline and fractionation facility.

Our business and operations could be adversely affected by terrorist attacks.

        On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scope, and the United States and others instituted military action in response. Since the September 11th attacks, the U.S. government has issued public warnings that indicate that energy assets, specifically our nation's pipeline infrastructure, production facilities and transmission and distribution facilities, might be specific targets of terrorist organizations. The continued threat of terrorism and the impact of military and other actions will likely lead to increased volatility in prices for natural gas and oil and could affect the markets for our products. In addition, future acts of terrorism could be directed against companies operating in the United States, particularly those engaged in sectors essential to our economic prosperity, such as natural resources. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse affect on our business.

Due to our lack of asset diversification, adverse developments in our gathering, processing, transportation, transmission, fractionation and storage business would reduce our ability to make distributions to our unitholders.

        We rely exclusively on the revenues generated from our gathering, processing, transportation, transmission, fractionation and storage businesses. Due to our lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

Risks Related to Our Partnership Structure

Cost reimbursements and fees due our general partner may be substantial and reduce our cash available for distribution to you.

        Payments to our general partner may be substantial and reduce the amount of available cash for distribution to unitholders. Prior to making any distribution on the common units, we reimburse our general partner for all expenses it incurs on our behalf. Our general partner has sole discretion in determining the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner.

8

MarkWest Hydrocarbon and its affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to your detriment.

        MarkWest Hydrocarbon and its affiliates own and control our general partner. MarkWest Hydrocarbon and its affiliates also own a significant limited partner interest in us. A number of officers and employees of MarkWest Hydrocarbon and our general partner also own interests in us. Conflicts of interest may arise between MarkWest Hydrocarbon and its affiliates, including our general partner, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

Conflicts Relating to Control:

•

employees of MarkWest Hydrocarbon who provide services to us also devote significant time to the businesses of MarkWest Hydrocarbon and are compensated by MarkWest Hydrocarbon for these services;



•

neither our partnership agreement nor any other agreement requires MarkWest Hydrocarbon to pursue a future business strategy that favors us or utilizes our assets for processing, transportation or fractionation services we provide. MarkWest Hydrocarbon's directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of MarkWest Hydrocarbon;



•

our general partner is allowed to take into account the interests of parties other than us, such as MarkWest Hydrocarbon, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;



•

our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;



•

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the processing, transportation and fractionation agreements with MarkWest Hydrocarbon;



•

our general partner decides whether to retain separate counsel, accountants or others to perform services for us;



•

in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units or to make incentive distributions or to hasten the conversion of subordinated units; and



•

our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.

9

Conflicts Relating to Costs:

•

our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to our unitholders;



•

our general partner determines which costs incurred by MarkWest Hydrocarbon and its affiliates are reimbursable by us; and



•

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

Unitholders have less ability to elect or remove management than holders of common stock in a corporation.

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or its board of directors and have no right to elect our general partner or its board of directors on an annual or other continuing basis.

        The board of directors of our general partner is chosen by MarkWest Hydrocarbon and its affiliates. The directors of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to its members, MarkWest Hydrocarbon and its affiliates.

        Furthermore, if unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. First, our general partner generally may not be removed except upon the vote of the holders of at least 66²/3% of the outstanding units voting together as a single class. Also, if our general partner is removed without cause during the subordination period and units held by MarkWest Hydrocarbon and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal under these circumstances would adversely affect the common units by prematurely eliminating their contractual right to distributions over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

        Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders' dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period.

        Furthermore, unitholders' voting rights are further restricted by the partnership agreement provision which states that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

        These provisions may discourage a person or group from attempting to remove our general partner or otherwise change our management. As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

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The control of our general partner may be transferred to a third party, and that party could replace our current management team, in each case without unitholder consent.

        Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owners of our general partner from transferring their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and to control the decisions taken by the board of directors and officers.

Our general partner's absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

        Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.

Our partnership agreement contains provisions which reduce the remedies available to unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.

        Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. The partnership agreement also restricts the remedies available to unitholders for actions that would otherwise constitute breaches of our general partner's fiduciary duties. If you choose to purchase a common unit, you will be treated as having consented to the various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law.

MarkWest Hydrocarbon and its affiliates may engage in competition with us.

        MarkWest Hydrocarbon and its affiliates may engage in competition with us. Pursuant to the omnibus agreement, MarkWest Hydrocarbon and its affiliates have agreed not to engage in, whether by acquisition, construction or otherwise, the business of processing natural gas and transporting, fractionating and storing NGLs. These restrictions, however, do not apply to:

•

the gathering of natural gas;



•

any business operated by MarkWest Hydrocarbon or any of its subsidiaries at the closing of our initial public offering;



•

any business that MarkWest Hydrocarbon or any of its subsidiaries acquires or constructs that has a fair market value of less than $7.5 million;



•

any business that MarkWest Hydrocarbon or any of its subsidiaries acquires or constructs that has a fair market value of $7.5 million or more if we have been offered the opportunity to purchase the business for fair market value, and we decline to do so with the concurrence of the conflicts committee of our general partner; and



•

any business that MarkWest Hydrocarbon or any of its subsidiaries acquires or constructs where the fair market value of the restricted business is $7.5 million or more and represents less than 20% of the aggregate value of the entire business acquired or constructed; provided, however, that following completion of such acquisition or construction, we are provided the opportunity to

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purchase such restricted business, and we decline to do so with the concurrence of the conflicts committee of our general partner.

        Upon a change of control of MarkWest Hydrocarbon or a sale of the general partner by MarkWest Hydrocarbon, the non-competition provisions of the omnibus agreement will terminate.

We do not have any employees and rely solely on employees of MarkWest Hydrocarbon and its affiliates who serve as our agents.

        We do not have any employees and rely solely on employees of MarkWest Hydrocarbon and its affiliates who serve as our agents. MarkWest Hydrocarbon and its affiliates conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the employees who provide services to our general partner. If the employees of MarkWest Hydrocarbon and its affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

We may issue additional common units without your approval, which would dilute your ownership interests.

        During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,207,500 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:

•

the issuance of common units in connection with acquisitions or capital improvements that increase cash flow from operations per unit on a pro forma basis;



•

the conversion of subordinated units into common units;



•

the conversion of units of equal rank with the common units into common units under some circumstances;



•

the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner;



•

issuances of common units under our long-term incentive plan; or



•

issuances of common units to repay indebtedness the cost of which to service is greater than the distribution obligations associated with the units issued in connection with the debt's retirement.

        The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

•

our unitholders' proportionate ownership interest in us will decrease;



•

the amount of cash available for distribution on each unit may decrease;



•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;



•

the relative voting strength of each previously outstanding unit may be diminished; and



•

the market price of the common units may decline.

        After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give

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our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

        If at any time more than 80% of the outstanding common units are owned by our general partner and its affiliates, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units.

You may not have limited liability if a court finds that unitholder action constitutes control of our business.

        Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement, or to take other action under our partnership agreement constituted participation in the "control" of our business.

        Our general partner generally has unlimited liability for the obligations of the Partnership, such as its debts and environmental liabilities, except for those contractual obligations of the Partnership that are expressly made without recourse to our general partner.

        In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Risks Related to the Debt Securities

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

        We have a holding company structure, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make required payments on the debt securities depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. Pursuant to the credit facilities, we may be required to establish cash reserves for the future payment of principal and interest on the amounts outstanding under the credit facilities. If we are unable to obtain the funds necessary to pay the principal amount at maturity of the debt securities, or to repurchase the debt securities upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of the debt securities. We cannot assure you that we would be able to refinance the debt securities.

We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service the debt securities or to repay them at maturity.

        Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our available cash to our unitholders of record and our general partner. Available cash is generally all of our cash receipts adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to

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establish and make additions to our reserves or the reserves of our operating partnerships in amounts the general partner determines in its reasonable discretion to be necessary or appropriate:

•

to provide for the proper conduct of our business and the businesses of our operating partnerships (including reserves for future capital expenditures and for our anticipated future credit needs),



•

to provide funds for distributions to our unitholders and the general partner for any one or more of the next four calendar quarters, or



•

to comply with applicable law or any of our loan or other agreements.

Although our payment obligations to our unitholders are subordinate to our payment obligations to debtholders, the value of our units will decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue equity to recapitalize.

Tax Risks to Common Unitholders

        You should read "Material Tax Consequences" for a more complete discussion of the expected federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to you.

        The after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gain, loss or deduction would flow through to you. Treatment of us as a corporation would result in a material reduction in the after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

        Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions would be reduced. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units.

        We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not concur with our counsel's conclusions

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or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne by us and directly or indrectly by our unitholders and our general partner.

You may be required to pay taxes even if you do not receive any cash distributions.

        You will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even the tax liability that results from that income.

Tax gain or loss on disposition of common units could be different than expected.

        A unitholder who sells common units will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income allocated to that unitholder, which decreased the tax basis in that unitholder's common unit, will, in effect, become taxable income to that unitholder if the common unit is sold at a price greater than that unitholder's tax basis in that common unit, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to that unitholder.

Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

        Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable them. Very little of our income will be qualifying income to a regulated investment company. Distributions to foreign persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and foreign persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We are registered as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.

        We are registered with the IRS as a "tax shelter." Our tax shelter registration number is 0218400024. The IRS requires that some types of entities, including some partnerships, register as "tax shelters" in response to the perception that they claim tax benefits that the IRS may believe to be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our unitholders' tax returns and may lead to audits of unitholders' tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.

        Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a "reportable transaction." Unitholders may be required to file this form with the IRS if we participate in a "reportable transaction." A transaction may be a reportable transaction based upon any of several factors. Unitholders are urged to consult with their own tax advisor concerning the application of any of these factors to their investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant

15

penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on "material advisors" that organize, manage or sell interests in registered "tax shelters." As stated above, we have registered as a tax shelter, and, thus, one of our material advisors will be required to maintain a list with specific information, including unitholder names and tax identification numbers, and to furnish this information to the IRS upon request. Unitholders are urged to consult with their own tax advisor concerning any possible disclosure obligation with respect to their investment and should be aware that we and our material advisors intend to comply with the list and disclosure requirements.

We will treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

        Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders' tax returns.

You will likely be subject to state and local taxes in states where you do not live as a result of an investment in our common units.

        In addition to federal income taxes, you will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not reside in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in many or all of the jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

USE OF PROCEEDS

        We expect to use the net proceeds from the sale of our securities for general business purposes, which, among other things, may include the following:

•

the repayment of outstanding indebtedness;



•

working capital;



•

capital expenditures; or



•

acquisitions.

The precise amount and timing of the application of the net proceeds will depend upon our funding requirements and the availability and cost of other funds. We may change the potential uses of the net proceeds in a prospectus supplement.

16

RATIOS OF EARNINGS TO FIXED CHARGES

        The table below sets forth the Ratios of Earnings to Fixed Charges for the Partnership for the periods indicated. On May 24, 2002, the Partnership completed its initial public offering whereby the Partnership became successor to the business of the MarkWest Hydrocarbon Midstream Business (Midstream Business). As such, the periods ended December 31, 2001, 2000 and 1999 reflect the financial results of the Midstream Business.

	Year Ended December 31,
											Three Months Ended March 31, 2004
	1999		2000		2001		2002		2003
RATIO OF EARNINGS TO FIXED CHARGES	3.22	x	8.63	x	3.79	x	3.86	x	2.31	x	2.66	x

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DESCRIPTION OF OUR DEBT SECURITIES

General

        The debt securities will be:

•

our direct general obligations;



•

either senior debt securities or subordinated debt securities; and



•

issued under separate indentures among us and Wells Fargo Bank, National Association, as Trustee.

        MarkWest Energy Partners may issue debt securities in one or more series. When used in this section "Description of Our Debt Securities," the terms "we," "us," "our" and "issuers" refers to MarkWest Energy Partners.

        If we offer senior debt securities, we will issue them under a senior indenture. If we issue subordinated debt securities, we will issue them under a subordinated indenture. A form of each indenture is filed as an exhibit to the registration statement of which this prospectus is a part. We have not restated either indenture in its entirety in this description. You should read the relevant indenture because it, and not this description, controls your rights as holders of the debt securities. Capitalized terms used in the summary have the meanings specified in the indentures.

Specific Terms of Each Series of Debt Securities in the Prospectus Supplement

        A prospectus supplement and a supplemental indenture or authorizing resolutions relating to any series of debt securities being offered will include specific terms relating to the offering. These terms will include some or all of the following:

•

the guarantors of the debt securities, if any;



•

whether the debt securities are senior or subordinated debt securities;



•

the title of the debt securities;



•

the total principal amount of the debt securities;



•

the assets, if any, that are pledged as security for the payment of the debt securities;



•

whether we will issue the debt securities in individual certificates to each holder in registered form, or in the form of temporary or permanent global securities held by a depository on behalf of holders;



•

the prices at which we will issue the debt securities;



•

the portion of the principal amount that will be payable if the maturity of the debt securities is accelerated;



•

the currency or currency unit in which the debt securities will be payable, if not U.S. dollars;



•

the dates on which the principal of the debt securities will be payable;



•

the interest rate that the debt securities will bear and the interest payment dates for the debt securities;



•

any conversion or exchange provisions;



•

any optional redemption provisions;



•

any sinking fund or other provisions that would obligate us to repurchase or otherwise redeem the debt securities;

18

•

any changes to or additional events of default or covenants; and



•

any other terms of the debt securities.

        We may offer and sell debt securities, including original issue discount debt securities, at a substantial discount below their principal amount. The prospectus supplement will describe special U.S. federal income tax and any other considerations applicable to those securities. In addition, the prospectus supplement may describe certain special U.S. federal income tax or other considerations applicable to any debt securities that are denominated in a currency other than U.S. dollars.

Guarantees

        If specified in the prospectus supplement respecting a series of debt securities, the subsidiaries of MarkWest Energy Partners specified in the prospectus supplement will unconditionally guarantee to each holder and the Trustee, on a joint and several basis, the full and prompt payment of principal of, premium, if any, and interest on the debt securities of that series when and as the same become due and payable, whether at stated maturity, upon redemption or repurchase, by declaration of acceleration or otherwise. If a series of debt securities is guaranteed, such series will be guaranteed by all subsidiaries other than "minor" subsidiaries as such term is interpreted in securities regulation governing financial reporting for guarantors. The prospectus supplement will describe any limitation on the maximum amount of any particular guarantee and the conditions under which guarantees may be released.

        The guarantees will be general obligations of the guarantors. Guarantees of subordinated debt securities will be subordinated to the Senior Indebtedness of the guarantors on the same basis as the subordinated debt securities are subordinated to the Senior Indebtedness of MarkWest Energy Partners.

Consolidation, Merger or Asset Sale

        Each indenture will, in general, allow us to consolidate or merge with or into another domestic entity. It will also allow each issuer to sell, lease, transfer or otherwise dispose of all or substantially all of its assets to another domestic entity. If this happens, the remaining or acquiring entity must assume all of the issuer's responsibilities and liabilities under the indenture including the payment of all amounts due on the debt securities and performance of the issuer's covenants in the indenture.

        However, each indenture will impose certain requirements with respect to any consolidation or merger with or into an entity, or any sale, lease, transfer or other disposition of all or substantially all of an issuer's assets, including:

•

the remaining or acquiring entity must be organized under the laws of the United States, any state or the District of Columbia;



•

the remaining or acquiring entity must assume the issuer's obligations under the indenture; and



•

immediately after giving effect to the transaction, no Default or Event of Default (as defined under "—Events of Default and Remedies" below) may exist.

        The remaining or acquiring entity will be substituted for the issuer in the indenture with the same effect as if it had been an original party to the indenture, and the issuer will be relieved from any further obligations under the indenture.

No Protection in the Event of a Change of Control

        Unless otherwise set forth in the prospectus supplement, the debt securities will not contain any provisions that protect the holders of the debt securities in the event of a change of control of us or in

19

the event of a highly leveraged transaction, whether or not such transaction results in a change of control of us.

Modification of Indentures

        We may supplement or amend an indenture if the holders of a majority in aggregate principal amount of the outstanding debt securities of all series issued under the indenture affected by the supplement or amendment consent to it. Further, the holders of a majority in aggregate principal amount of the outstanding debt securities of any series may waive past defaults under the indenture and compliance by us with our covenants with respect to the debt securities of that series only. Those holders may not, however, waive any default in any payment on any debt security of that series or compliance with a provision that cannot be supplemented or amended without the consent of each holder affected. Without the consent of each outstanding debt security affected, no modification of the indenture or waiver may:

•

reduce the principal amount of debt securities whose holders must consent to an amendment, supplement or waiver;



•

reduce the principal of or change the fixed maturity of any debt security;



•

reduce or waive the premium payable upon redemption or alter or waive the provisions with respect to the redemption of the debt securities (except as may be permitted in the case of a particular series of debt securities);



•

reduce the rate of or change the time for payment of interest on any debt security;



•

waive a Default or an Event of Default in the payment of principal of or premium, if any, or interest on the debt securities (except a rescission of acceleration of the debt securities by the holders of at least a majority in aggregate principal amount of the debt securities and a waiver of the payment default that resulted from such acceleration);



•

except as otherwise permitted under the indenture, release any security that may have been granted with respect to the debt securities;



•

make any debt security payable in currency other than that stated in the debt securities;



•

in the case of any subordinated debt security, make any change in the subordination provisions that adversely affects the rights of any holder under those provisions;



•

make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of holders of debt securities to receive payments of principal of or premium, if any, or interest on the debt securities;



•

waive a redemption payment with respect to any debt security (except as may be permitted in the case of a particular series of debt securities);



•

except as otherwise permitted in the indenture, release any guarantor from its obligations under its guarantee or the indenture or change any guarantee in any manner that would adversely affect the rights of holders; or



•

make any change in the preceding amendment, supplement and waiver provisions (except to increase any percentage set forth therein).

        We may supplement or amend an indenture without the consent of any holders of the debt securities in certain circumstances, including:

•

to establish the form of terms of any series of debt securities;



•

to cure any ambiguity, defect or inconsistency;

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•

to provide for the assumption of an issuer's or guarantor's obligations to holders of debt securities in the case of a merger or consolidation or disposition of all or substantially all of such issuer's or guarantor's assets;



•

in the case of any subordinated debt security, to make any change in the subordination provisions that limits or terminates the benefits applicable to any holder of Senior Indebtedness of MarkWest Energy Partners;



•

to add or release guarantors pursuant to the terms of the indenture;



•

to make any changes that would provide any additional rights or benefits to the holders of debt securities or that do not, taken as a whole, adversely affect the rights under the indenture of any holder of debt securities;



•

to evidence or provide for the acceptance of appointment under the indenture of a successor Trustee;



•

to add any additional Events of Default; or



•

to secure the debt securities and/or the guarantees.

Events of Default and Remedies

        "Event of Default," when used in an indenture, will mean any of the following with respect to the debt securities of any series:

•

failure to pay when due the principal of or any premium on any debt security of that series;



•

failure to pay, within 60 days of the due date, interest on any debt security of that series;



•

failure to pay when due any sinking fund payment with respect to any debt securities of that series;



•

failure on the part of the issuers to comply with the covenant described under "—Consolidation, Merger or Asset Sale";



•

failure to perform any other covenant in the indenture that continues for 30 days after written notice is given to the issuers;



•

certain events of bankruptcy, insolvency or reorganization of an issuer; or



•

any other Event of Default provided under the terms of the debt securities of that series.

        An Event of Default for a particular series of debt securities will not necessarily constitute an Event of Default for any other series of debt securities issued under an indenture. The Trustee may withhold notice to the holders of debt securities of any default (except in the payment of principal, premium, if any, or interest) if it considers such withholding of notice to be in the best interests of the holders.

        If an Event of Default for any series of debt securities occurs and continues, the Trustee or the holders of at least 25% in aggregate principal amount of the debt securities of the series may declare the entire principal of, and accrued interest on, all the debt securities of that series to be due and payable immediately. If this happens, subject to certain conditions, the holders of a majority in the aggregate principal amount of the debt securities of that series can rescind the declaration.

        Other than its duties in case of a default, a Trustee is not obligated to exercise any of its rights or powers under either indenture at the request, order or direction of any holders, unless the holders offer the Trustee reasonable security or indemnity. If they provide this reasonable security or indemnification, the holders of a majority in aggregate principal amount of any series of debt securities may direct the

21

time, method and place of conducting any proceeding or any remedy available to the Trustee, or exercising any power conferred upon the Trustee, for that series of debt securities.

No Limit on Amount of Debt Securities

        Neither indenture will limit the amount of debt securities that we may issue, unless we indicate otherwise in a prospectus supplement. Each indenture will allow us to issue debt securities of any series up to the aggregate principal amount that we authorize.

Registration of Notes

        We will issue debt securities of a series only in registered form, without coupons, unless otherwise indicated in the prospectus supplement.

Minimum Denominations

        Unless the prospectus supplement states otherwise, the debt securities will be issued only in principal amounts of $1,000 each or integral multiples of $1,000.

No Personal Liability

        None of the past, present or future partners, incorporators, managers, members, directors, officers, employees, unitholders or stockholders of either issuer, the general partner of MarkWest Energy Partners or any guarantor will have any liability for the obligations of the issuers or any guarantors under either indenture or the debt securities or for any claim based on such obligations or their creation. Each holder of debt securities by accepting a debt security waives and releases all such liability. The waiver and release are part of the consideration for the issuance of the debt securities. The waiver may not be effective under federal securities laws, however.

Payment and Transfer

        The Trustee will initially act as paying agent and registrar under each indenture. The issuers may change the paying agent or registrar without prior notice to the holders of debt securities, and the issuers or any of their subsidiaries may act as paying agent or registrar.

        If a holder of debt securities has given wire transfer instructions to the issuers, the issuers will make all payments on the debt securities in accordance with those instructions. All other payments on the debt securities will be made at the corporate trust office of the Trustee, unless the issuers elect to make interest payments by check mailed to the holders at their addresses set forth in the debt security register.

        The Trustee and any paying agent will repay to us upon request any funds held by them for payments on the debt securities that remain unclaimed for two years after the date upon which that payment has become due. After payment to us, holders entitled to the money must look to us for payment as general creditors.

Exchange, Registration and Transfer

        Debt securities of any series will be exchangeable for other debt securities of the same series, the same total principal amount and the same terms but in different authorized denominations in accordance with the indenture. Holders may present debt securities for exchange or registration of transfer at the office of the registrar. The registrar will effect the transfer or exchange when it is satisfied with the documents of title and identity of the person making the request. We will not charge a service charge for any registration of transfer or exchange of the debt securities. We may, however, require the payment of any tax or other governmental charge payable for that registration.

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        We will not be required:

•

to issue, register the transfer of, or exchange debt securities of a series either during a period beginning 15 business days prior to the selection of debt securities of that series for redemption and ending on the close of business on the day of mailing of the relevant notice of redemption or repurchase, or between a record date and the next succeeding interest payment date; or



•

to register the transfer of or exchange any debt security called for redemption or repurchase, except the unredeemed portion of any debt security we are redeeming or repurchasing in part.

Provisions Relating only to the Senior Debt Securities

        The senior debt securities will rank equally in right of payment with all of our other senior and unsubordinated debt. The senior debt securities will be effectively subordinated, however, to all of our secured debt to the extent of the value of the collateral for that debt. We will disclose the amount of our secured debt in the prospectus supplement.

Provisions Relating only to the Subordinated Debt Securities

Subordinated Debt Securities Subordinated to Senior Indebtedness

        The subordinated debt securities will rank junior in right of payment to all of the Senior Indebtedness of MarkWest Energy Partners. "Senior Indebtedness" will be defined in a supplemental indenture or authorizing resolutions respecting any issuance of a series of subordinated debt securities, and the definition will be set forth in the prospectus supplement.

Payment Blockages

        The subordinated indenture will provide that no payment of principal, interest and any premium on the subordinated debt securities may be made in the event:

•

we or our property is involved in any voluntary or involuntary liquidation or bankruptcy;



•

we fail to pay the principal, interest, any premium or any other amounts on any Senior Indebtedness of MarkWest Energy Partners within any applicable grace period or the maturity of such Senior Indebtedness is accelerated following any other default, subject to certain limited exceptions set forth in the subordinated indenture; or



•

any other default on any Senior Indebtedness of MarkWest Energy Partners occurs that permits immediate acceleration of its maturity, in which case a payment blockage on the subordinated debt securities will be imposed for a maximum of 179 days at any one time.

No Limitation on Amount of Senior Debt

        The subordinated indenture will not limit the amount of Senior Indebtedness that MarkWest Energy Partners may incur, unless otherwise indicated in the prospectus supplement.

Book Entry, Delivery and Form

        The debt securities of a particular series may be issued in whole or in part in the form of one or more global certificates that will be deposited with the Trustee as custodian for The Depository Trust Company, New York, New York ("DTC"), and registered in the name of DTC's nominee, Cede & Co. This means that we will not issue certificates to each holder. Instead, one or more global debt securities will be issued to DTC, who will keep a computerized record of its participants (for example, your broker) whose clients have purchased the debt securities. The participant will then keep a record of its clients who purchased the debt securities. Unless it is exchanged in whole or in part for a

23

certificated debt security, a global debt security may not be transferred, except that DTC, its nominees and their successors may transfer a global debt security as a whole to one another.

        Beneficial interests in global debt securities will be shown on, and transfers of beneficial interests in global debt securities will be made only through, records maintained by DTC and its participants.

        DTC has provided us the following information: DTC is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the United States Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code and a "clearing agency" registered under the provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds securities that its participants ("Direct Participants") deposit with DTC. DTC also records the settlement among Direct Participants of securities transactions, such as transfers and pledges, in deposited securities through computerized records for Direct Participants' accounts. This eliminates the need to exchange certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations.

        DTC's book-entry system is also used by other organizations such as securities brokers and dealers, banks and trust companies that work through a Direct Participant. The rules that apply to DTC and its Direct Participants are on file with the SEC.

        DTC is owned by a number of its Direct Participants and by the New York Stock Exchange, Inc., The American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc.

        We will wire all payments on the global debt securities to DTC's nominee. We and the Trustee will treat DTC's nominee as the owner of the global debt securities for all purposes. Accordingly, we, the Trustee and any paying agent will have no direct responsibility or liability to pay amounts due on the global debt securities to owners of beneficial interests in the global debt securities.

        It is DTC's current practice, upon receipt of any payment on the global debt securities, to credit Direct Participants' accounts on the payment date according to their respective holdings of beneficial interests in the global debt securities as shown on DTC's records. In addition, it is DTC's current practice to assign any consenting or voting rights to Direct Participants whose accounts are credited with debt securities on a record date, by using an omnibus proxy. Payments by Direct Participants to owners of beneficial interests in the global debt securities, and voting by Direct Participants, will be governed by the customary practices between the Direct Participants and owners of beneficial interests, as is the case with debt securities held for the account of customers registered in "street name." However, payments will be the responsibility of the Direct Participants and not of DTC, the Trustee or us.

        Debt securities represented by a global debt security will be exchangeable for certificated debt securities with the same terms in authorized denominations only if:

•

DTC notifies us that it is unwilling or unable to continue as depositary or if DTC ceases to be a clearing agency registered under applicable law and in either event a successor depositary is not appointed by us within 90 days; or



•

we determine not to require all of the debt securities of a series to be represented by a global debt security.

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Satisfaction and Discharge; Defeasance

        Each indenture will be discharged and will cease to be of further effect as to all outstanding debt securities of any series issued thereunder, when:

        (a)   either:

        (1)   all outstanding debt securities of that series that have been authenticated (except lost, stolen or destroyed debt securities that have been replaced or paid and debt securities for whose payment money has theretofore been deposited in trust and thereafter repaid to us) have been delivered to the Trustee for cancellation; or

        (2)   all outstanding debt securities of that series that have not been delivered to the Trustee for cancellation have become due and payable by reason of the giving of a notice of redemption or otherwise or will become due and payable at their stated maturity within one year or are to be called for redemption within one year under arrangements satisfactory to the Trustee and in any case we have irrevocably deposited or caused to be irrevocably deposited with the Trustee as trust funds in trust cash in U.S. dollars, non-callable U.S. Government Obligations or a combination thereof, in such amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness of such debt securities not delivered to the Trustee for cancellation, for principal, premium, if any, and accrued interest to the date of such deposit (in the case of debt securities that have been due and payable) or the stated maturity or redemption date;

        (b)   we have paid or caused to be paid all other sums payable by us under the indenture; and

        (c)   we have delivered an officers' certificate and an opinion of counsel to the Trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

        The debt securities of a particular series will be subject to legal or covenant defeasance to the extent, and upon the terms and conditions, set forth in the prospectus supplement.

The Trustee

        Wells Fargo Bank, National Association will be the initial Trustee under each indenture. We maintain a banking relation in the ordinary course of business with Wells Fargo, National Association and some of its affiliates.

Limitations on Trustee if it is a Creditor

        Each indenture will limit the right of the Trustee thereunder, in the event that it becomes a creditor of an issuer or guarantor, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise.

Certificates and Opinions to be Furnished to Trustee

        Each indenture will provide that, in addition to other certificates or opinions that may be specifically required by other provisions of the indenture, every application by us for action by the Trustee must be accompanied by a certificate of certain of our officers and an opinion of counsel (who may be our counsel) stating that, in the opinion of the signers, all conditions precedent to such action have been complied with by us.

Governing Law

        Each indenture and all of the debt securities will be governed by the laws of the State of New York.

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DESCRIPTION OF THE COMMON UNITS

General

        The common units represent limited partner interests that entitle the holders to participate in our cash distributions and to exercise the rights and privileges available to limited partners under our partnership agreement.

        Our outstanding common units are listed in the American Stock Exchange, or AMEX, under the symbol "MWE."

        The transfer agent and registrar for our common units is Computershare Trust Company, Inc.

Status as Limited Partner or Assignee

        Except as described below under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional capital contributions to us.

Transfer of Common Units

        Each purchaser of common units offered by this prospectus must execute a transfer application whereby the purchaser requests admission as a substituted limited partner and makes representations and agrees to provisions started in the transfer application. If this action is not taken, a purchaser will not be registered as a record holder of common units on the books of our transfer agent or issued a common unit certificate. Purchasers may hold common units in nominee accounts.

        An assignee, pending its admission as a substituted limited partner, is entitled to an interest in us equivalent to that of a limited partner with respect to the right to share in allocations and distributions, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee who has not become a substituted limited partner at the written direction of the assignee. Transferees who do not execute and deliver transfer applications will be treated neither as assignees nor as record holders of common units and will not receive distributions, federal income tax allocations or reports furnished to record holders of common units. The only right the transferees will have is the right to admission as a substituted limited partner in respect of the transferred common units upon execution of a transfer application in respect of the common units. A nominee or broker who has executed a transfer application with respect to common units held in street name or nominee accounts will receive distributions and reports pertaining to its common units.

Limited Liability

        Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to some possible exceptions, generally to the amount of capital he is obligated to contribute to us in respect of his common units plus his share of any undistributed profits and assets.

        Under the Delaware Act, a limited partnership may not make a distribution to a partner to the extent that at the time of the distribution, after giving effect to the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, exceed the fair value of the assets of the limited partnership.

Reports and Records

        As soon as practicable, but in no event later than 120 days after the close of each fiscal year, our general partner will furnish or make available to each unitholder of record (as of a record date selected

26

by our general partner) an annual report containing our audited financial statements for the past fiscal year. These financial statements will be prepared in accordance with generally accepted accounting principles. In addition, no later than 90 days after the close of each quarter (except the fourth quarter), our general partner will furnish or make available to each unitholder of record (as of a record date selected by our general partner) a report containing our unaudited financial statements and any other information required by law.

        Our general partner will use all reasonable efforts to furnish each unitholder of record information reasonably required for tax reporting purposes within 90 days after the close of each fiscal year. Our general partner's ability to furnish this summary tax information will depend on the cooperation of unitholders in supplying information to our general partner. Each unitholder will receive information to assist him in determing his U.S. federal and state and Canadian federal and provincial tax liability and filing his U.S. federal and state and Canadian federal and provincial income tax returns.

        A limited partner can, for a purpose reasonably related to the limited partner's interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

•

a current list of the name and last known address of each partner;



•

a copy of our tax returns;



•

information as to the amount of cash and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;



•

copies of our partnership agreement, our certificate of limited partnership, amendments to either of them and powers of attorney which have been executed under our partnership agreement;



•

information regarding the status of our business and financial condition; and



•

any other information regarding our affairs as is just and reasonable.

Preemptive Rights

        None of the holders of common units are entitled to preemptive rights in respect of issuances of securities by us. Our general partner has the right, upon our issuance of any class of partnership securities to third parties, to purchase partnership securities of such class from us on the same terms that we issue such class of partnership securities to those third parties to the extent necessary to maintain the percentage interests of our general partner and its affiliates equal to that which existed immediately prior to our issuance of such class of partnership securities. Moreover, upon the issuance of any additional limited partner interests by us, our general partner is required to make additional capital contributions to maintain its general partner equity interest in us.

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CASH DISTRIBUTION POLICY

        One of our principal objectives is to generate cash from our operations and to distribute cash to our partners each quarter. We are required to distribute to our partners 100% of our available cash each quarter. Our available cash is defined in our partnership agreement and is generally the sum of the cash we receive in a quarter less cash disbursements, adjusted for net changes in reserves.

        During the subordination period the holders of our common units are entitled to receive each quarter a minimum quarterly distribution of $0.50 per unit ($2.00 annualized) prior to any distribution of available cash to holders of our subordinated units. The subordination period is defined generally as the period that will end on the first day of any quarter beginning after June 30, 2009 if (1) we have distributed at least the minimum quarterly distribution on all outstanding units with respect to each of the immediately preceding three consecutive, non-overlapping four-quarter periods and (2) our adjusted operating surplus, as defined in our partnership agreement, during such periods equals or exceeds the amount that would have been sufficient to enable us to distribute the minimum quarterly distribution on all outstanding units on a fully diluted basis and the related distribution on the 2% general partner interest during those periods. In addition, one-quarter of the subordinated units may convert to common units on a one-for-one basis after June 30, 2005 if we meet the tests set forth in our partnership agreement.

        During the subordination period, our cash is distributed first 98% to the holders of common units and 2% to our general partner until there has been distributed to the holders of common units an amount equal to the minimum quarterly distribution and any arrearages in the payment of the minimum quarterly distribution on the common units for any prior quarter. Any additional cash is distributed 98% to the holders of subordinated units and 2% to our general partner until there has been distributed to the holders of subordinated units an amount equal to the minimum quarterly distribution. If the subordination period ends, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units and the subordinated units may be converted into common units.

        Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 15% of amounts we distribute in excess of $0.55 per common unit, 25% of amounts we distribute in excess of $0.625 per common unit and 50% of amounts we distribute in excess of $0.75 per common unit.

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DESCRIPTION OF OUR PARTNERSHIP AGREEMENT

        The following is a summary of the material provisions of our partnership agreement. Our amended and restated partnership agreement has been filed with the Securities and Exchange Commission, and is incorporated by reference in this prospectus. The following provisions of our partnership agreement are summarized elsewhere in this prospectus:

•

allocations of taxable income and other tax matters are described under "Tax Consequences"; and



•

rights of holders of common units are described under "Description of Our Common Units."

Purpose

        Our purpose under our partnership agreement is to serve as a member of our operating company and to engage in any business activities that may be engaged in by our operating company or that are approved by our general partner. All of our operations are conducted through our operating company, MarkWest Energy Operating Company, L.L.C., and its subsidiaries. We own 100% of the outstanding membership interest of the operating company. The limited liability company agreement of our operating company provide that it may engage in its operations as conducted immediately before our initial public offering or reasonably related thereto and any other activity approved by our general partner.

Power of Attorney

        Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants the general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Reimbursements of Our General Partner

        Our general partner does not receive any compensation for its services as our general partner. It is, however, entitled to be reimbursed for all of its costs incurred in managing and operating our business. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

Issuance of Additional Securities

        Our partnership agreement authorizes us to issue an unlimited number of additional partner securities and rights to buy parthership securities that are equal in rank with or junior to our common units on terms and conditions established by our general partner in its sole discretion without the approval of the unitholders. During the subordination period, however, except as set forth in the following paragraph, we may not issue equity securities ranking senior to the common units or an aggregate of more than approximately 1.2 million additional common units or an equivalent number of units that are equal in rank with our common units, in each case, without the approval of at least a majority of our outstanding common units and subordianted units, voting as separate classes.

        During or after the the subordination period, we may issues an unlimited number of common units without the approval of the unitholders as follows:

•

upon the exercise of an underwriters' over-allotment option;



•

upon conversion of the subordinated units;

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•

under employee benefit plans;



•

upon conversion of the general partner interest and incentive distribution rights as a result of a withdrawal of our general partner;



•

in the event of a combination or subdividision of common units;



•

in connection with an acquisition or a capital improvement that increases cash flow from operations per unit on a pro form a basis; or



•

if the proceeds of the issuance are used exclusively to repay indebtedness the cost of which to service is greater than the distribution obligations associated with the units issued in connection with its retirement.

        It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

        In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, in the sole discretion of our general partner, may have special voting rights to which common units are not entitled.

        Our general partner has the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordianted units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain its percentage interest, including its interest represented by common units and subordinated units, that existed immediately prior to the issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendments to Our Partnership Agreement

        Amendments to our partnership agreement may be proposed only by our general partner. Any amendment that materially and adversely affects the rights or preferences of any type or class of limited partner interests in relation to other types or classes of limited partner interests or our general partner interest will require the approval of at least a majority of the type or class of limited partner interests or general partner interests so affected. However, in some circumstances, more particularly described in our partnership agreement, our general partner may make amendments to our partnership agreement without the approval of our limited partners or assignees.

Withdrawal or Removal of Our General Partner

        Our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2012 without obtaining the approval of the holders of a majority of our outstanding common units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2012, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner may withdraw without unitholder approval upon 90 days' notice to our limited partners if at least 50% of our outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates.

        Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding common units and subordinated units, excluding the common units held by the withdrawing general

30

partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal, the holders of a majority of our outstanding common and subordinated units, voting as separate classes, agree in writing to continue our business and to appoint a successor general partner.

        Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than two-thirds of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of this kind is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units and subordinated units, voting as separate classes.

        While our partnership agreement limits the ability of our general partner to withdraw, it allows the general partner interest and incentive distribution rights to be transferred to an affiliate or to a third party in conjunction with a merger or sale of all or substantially all of the assets of our general partner. In addition, our partnership agreement expressly permits the sale, in whole or in part, of the ownership of our general partner. Our general partner may also transfer, in whole or in part, the common units and any other partnership securities it owns.

Liquidation and Distribution of Proceeds

        Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our general partner that the liquidator deems necessary or desirable in its judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:

•

first, towards the payment of all of our creditors; and



•

then, to our unitholders and our general partner in accordance with the positive balance in their respective capital accounts.

        The liquidator may defer liquidation of our assets for a reasonable period or distribute assets to our partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Change of Management Provisions

        Our partnership agreement contains the following specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change management:

•

any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter; and



•

the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Limited Call Right

        If at any time our general partner and its affiliates own 80% or more of the issued and outstanding limited partner interests of any class, our general partner will have the right to acquire all, but not less than all, of the outstanding limited partner interests of that class that are held by non-affiliated persons. The record date for determining ownership of the limited partner interests would be selected by our general partner on at least ten but not more than 60 days notice. The

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purchase price in the event of a purchase under these provisions would be the greater of (1) the current market price (as defined in our partnership agreement) of the limited partner interests of the class as of the date three days prior to the date that notice is mailed to the limited partners as provided in the partnership agreement and (2) the highest cash price paid by our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date our general partner first mails notice of its election to purchase those partnership securities.

Indemnification

        Under our partnership agreement, in most circumstances, we will indemnify our general partner, its affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer by reason of their status as general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to our best interest. Any indemnification under these provisions will only be out of our assets. Our general partner and its affiliated shall not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate any indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Registration Rights

        Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates (including MarkWest Hydrocarbon, its officers and the officers, directors and owners of our general partner) or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

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MATERIAL TAX CONSEQUENCES

        This section is a summary of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, expresses the opinion of Vinson & Elkins L.L.P., counsel to the general partner and us, insofar as it relates to federal income tax matters. If we offer and sell any debt securities, a description of the material federal income tax consequences of the acquisition, ownership and disposition of the debt securities will be set forth in the prospectus supplement relating to the offering. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to MarkWest Energy Partners and the operating company.

        This section does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we recommend that each prospective unitholder consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

        All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations mde by us and our general partner. No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we rely on opinions and advice of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and the general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

        For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:

        (1)   the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales" in this prospectus);

        (2)   whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees" in this prospectus); and

        (3)   whether our method for depreciating Section 743 adjustments is sustainable (please read "—Tax Consequences of Unit Ownership—Section 754 Election" in this prospectus).

Partnership Status

        A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash

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distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner's adjusted basis in his partnership interest.

        Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof and fertilizer. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 4% of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.

        No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status as a partnership for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership for federal income tax purposes.

        In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which counsel has relied are:

        (a)   Neither we nor the operating company has elected or will elect to be treated as a corporation; and

        (b)   For each taxable year, more than 90% of our gross income has been and will be income from sources that Vinson & Elkins L.L.P. has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.

        If we fail to meet the Qualifying Income Exception, other than a failure which is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

        If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

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        The remainder of this section is based on Vinson & Elkins L.L.P.'s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

        Unitholders who have become limited partners of MarkWest Energy Partners will be treated as partners of MarkWest Energy Partners for federal income tax purposes. Also:

        (a)   assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and

        (b)   unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units,

will be treated as partners of MarkWest Energy Partners for federal income tax purposes. As there is no direct authority addressing assignees of common units who are entitled to execute and deliver transfer applications and become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Vinson & Elkins L.L.P. does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

        A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales" in this prospectus.

        Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in MarkWest Energy Partners for federal income tax purposes.

Tax Consequences of Unit Ownership

        Flow-through of Taxable Income.    We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

        Treatment of Distributions.    Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder's "at risk" amount to be less than

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zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

        A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, and/or substantially appreciated "inventory items," both as defined in Section 751 of the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

        Basis of Common Units.    A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt which is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

        Limitations on Deductibility of Losses.    The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder's stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

        In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

        The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any losses we generate will only be available

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to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly-traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when such unitholder disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

        A unitholder's share of our net income may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.

        Limitations on Interest Deductions.    The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

•

interest on indebtedness properly allocable to property held for investment;



•

our interest expense attributed to portfolio income; and



•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

        The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income from a publicly-traded partnership constitutes investment income for purposes of the limitations on the deductibility of investment interest. In addition, the unitholder's share of our portfolio income will be treated as investment income.

        Entity-Level Collections.    If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

        Allocation of Income, Gain, Loss and Deduction.    In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

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        Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as "Contributed Property." The effect of these allocations to a unitholder purchasing common units in our offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

        An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity," will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including his relative contributions to us, the interests of all the partners in profits and losses, the interest of all the partners in cash flow and other nonliquidating distributions and rights of all the partners to distributions of capital upon liquidation.

        Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," in this prospectus allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

        Treatment of Short Sales.    A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;



•

any cash distributions received by the unitholder as to those units would be fully taxable; and



•

all of these distributions would appear to be ordinary income.

        Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

        Alternative Minimum Tax.    Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

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        Tax Rates.    In general, the highest effective United States federal income tax rate for individuals currently is 35% and the maximum United States federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than 12 months at the time of disposition.

        Section 754 Election.    We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other partners. For purposes of this discussion, a partner's inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets ("common basis") and (2) his Section 743(b) adjustment to that basis.

        Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we have adopted), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury regulations. Please read "—Tax Treatment of Operations—Uniformity of Units" in this prospectus.

        Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Tax Treatment of Operations—Uniformity of Units" in this prospectus.

        A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

        The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the

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Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

        Accounting Method and Taxable Year.    We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees" in this prospectus.

        Tax Basis, Depreciation and Amortization.    The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by the general partner, its affiliates and our other unitholders as of that time. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" in this prospectus.

        To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We were not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

        If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a partner who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss" in this prospectus.

        The costs incurred in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

        Valuation and Tax Basis of Our Properties.    The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the

40

tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

        Recognition of Gain or Loss.    Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

        Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

        Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. A portion of this gain or loss, which will likely be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

        The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method. Treasury regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury regulations.

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        Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•

a short sale;



•

an offsetting notional principal contract; or



•

a futures or forward contract with respect to the partnership interest or substantially identical property.

        Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

        Allocations Between Transferors and Transferees.    In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

        The use of this method may not be permitted under existing Treasury regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders to conform to a method permitted under future Treasury regulations.

        A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

        Notification Requirements.    A purchaser of units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.

        Constructive Termination.    We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a

42

termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

        Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election" in this prospectus.

        We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6) which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election" in this prospectus. To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss" in this prospectus.

Tax-Exempt Organizations and Other Investors

        Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

        Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder which is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

        A regulated investment company or "mutual fund" is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or

43

specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income.

        Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective rate applicable to individuals, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

        In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

        Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

        Information Returns and Audit Procedures.    We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

        The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his own return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

        Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. The partnership agreement names MarkWest Energy GP, L.L.C. as our Tax Matters Partner.

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        The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

        A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

        Nominee Reporting.    Persons who hold an interest in us as a nominee for another person are required to furnish to us:

        (a)   the name, address and taxpayer identification number of the beneficial owner and the nominee;

        (b)   whether the beneficial owner is

        (1)   a person that is not a United States person,

        (2)   a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

        (3)   a tax-exempt entity;

        (c)   the amount and description of units held, acquired or transferred for the beneficial owner; and

        (d)   specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

        Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

        Registration as a Tax Shelter.    The Internal Revenue Code requires that "tax shelters" be registered with the Secretary of the Treasury. It is arguable that we are not subject to the registration requirement on the basis that we will not constitute a tax shelter. However, we have registered as a tax shelter with the Secretary of Treasury in the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which might be imposed if registration is required and not undertaken. Our tax shelter registration number is 0218400024.

Issuance of this registration number does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.

        A unitholder who sells or otherwise transfers a unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a unit to furnish the registration number to the transferee is $100 for each failure. The unitholders must disclose our tax

45

shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.

        Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a "reportable transaction." Unitholders may be required to file this form with the IRS if we participate in a "reportable transaction." A transaction may be a reportable transaction based upon any of several factors. Unitholders are urged to consult with their own tax advisor concerning the application of any of these factors to their investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on "material advisors" that organize, manage or sell interests in registered "tax shelters." As stated above, we have registered as a tax shelter, and, thus, one of our material advisors will be required to maintain a list with specific information, including unitholder names and tax identification numbers, and to furnish this information to the IRS upon request. Unitholders are urged to consult with their own tax advisor concerning any possible disclosure obligation with respect to their investment and should be aware that we and our material advisors intend to comply with the list and disclosure requirements.

        Accuracy-related Penalties.    An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

        A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

        (1)   for which there is, or was, "substantial authority," or

        (2)   as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

        More stringent rules apply to "tax shelters," a term that in this context does not appear to include us. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.

        A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

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State, Local and Other Tax Considerations

        In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business or own property in 9 states, most of which impose income taxes. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder is urged to consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections" in this prospectus.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Accordingly, we strongly recommend that each prospective unitholder consult, and depend upon, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state and local, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state or local tax consequences of an investment in us.

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SELLING UNITHOLDERS

        In addition to covering our offering of securities, this prospectus covers the offering for resale of up to 827,444 common units by selling unitholders, including 500,000 common units that are issuable upon the conversion of subordinated units. The following table sets forth information relating to the selling unitholders' beneficial ownership of our common units and subordinated units that are convertible into common units:

Selling Unitholders	Number of Common Units Owned	Number of Subordinated Units Owned
Tortoise MWEP, L.P.	0	500,000
Delmar Equity Partners, L.P.	19,062
JAS Trust, Country Club Bank N.A. Trustee	19,062
Jeane Marie Swalm	19,062
Robert A. Tucci and Cynthia L. Tucci JTWROS	9,531
Ellkan, L.L.C.	9,531
Evan D. Jennings, II	16,000
Lewis E. Nerman Revocable Trust Dtd 10/19/89, Lewis E. Nerman Trustee	15,249
Curtis A. Krizek Revocable Trust UTA dated 12/17/98, Curtis A. Krizek Trustee	11,437
Jonathan E. Baum Revocable Trust U/A Dated 1/29/92, Jonathan E. Baum Trustee	4,765
Timothy S. Webster Revocable Trust dated 4/10/2000	9,531
Richard B. Klein Revocable Trust, Richard B. Klein and Lynn M. Klein, Trustees	9,531
Michael G. Smith	9,531
Sally S. Hilkene Revocable Trust Dated 8/30/2002, Sally S. Hilkene Trustee	3,812
Jerome S. Nerman Trust UA DTD 11/08/88, Jerome S. Nerman Trustee	7,624
Frederick M. Solberg, Jr. & Elizabeth T. Solberg Ten Entirety	3,812
Gary M. Truitt and Kay Lee Truitt JTWROS	7,624
Steven W. Satkamp	7,624
Edward D. Durwood	5,718
Bradford M. Epsten	5,718
Laura Marcia Wolff Greenbaum Trust Dated 9/20/78, Laura Marcia Wolff Greenbaum Trustee	5,718
Brian N. Kaufman and Susan C. Kaufman JTWROS	4,765
A. Scott Ritchie, III	4,000
Frank J. Cucchiara and Jo Marie Cucchiara JTWROS	3,812
The Lewis White Trust U/D/T dated 12/29/86, as amended	3,812
Dolores Arn Underhill Trust, Dolores Arn Underhill Trustee	3,812
John D. Starr Trust dated 11/10/93, John D. Starr Trustee	3,049
Jeffrey C. Reene Revocable Trust dated 10/20/99, Jeffrey C. Reene Trustee	2,859
George D. Shadid and Lisa M. Shadid, Trustees U/T/A dtd 07/03/00, George D. Shadid, Donor	2,859
Jason Talley and Amarilis Talley Ten Entirety	2,287
Theresa K. Freilich Revocable Trust Dated 3/28/2003, Theresa K. Freilich Trustee	1,906

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Peter P. Dreher and Nancy D. Dreher JTWROS	1,906
Thomas M. Cray Revocable Trust Dtd October 9, 2000, Thomas M. Cray Trustee	1,906
Robyn R. Schneider Revocable Trust, Robyn R. Schneider Trustee	1,906
Sandra H. Fried, Trustee U/I/T Dated July 25, 1996, as amended and restated July 25, 2002, Sandra H. Fried Trustee	1,906
James S. Gerson Revocable Trust Dtd 04/94, James S. Gerson Trustee	1,524
Stuart M. Bauman Revocable Trust U/A Dtd. 1/28/93, Stuart M. Bauman and Terry Bauman, Trustees	1,143
Cara Zanotti Newell	953
Charles M. Newell	953
Midwest Venture Capital, LLC	12,000
Farmer Family Asset Allocation Co.—c/o John O Farmer, III	9,531
Greenway Capital, LP—c/o Bob Green	9,166
J. Thomas and Cynthia F. Burcham; JTWROS	7,624
H. Kevin Birzer	3,813
Doug Gaeddert	3,812
KC Partners in Growth	3,812
Gregory S. and Elizabeth B. Maday; JTWROS	3,812
GEM Long Beach, LLC	2,860
Roger Brent Stover	2,860
Kansas City Equity Partners, LC	2,028
Paul A. Lyons, Jr.	2,000
David J. and Ellen E. Schulte; JTWROS	1,965
Douglas E. Campbell	1,906
Terry Matlack	1,583
Scott and Holly Fesler; JTWROS	1,143
Donald W. Trotter	1,143
Gerald W. Buetow, Jr.	1,000
Marshall D. Parker	1,000
Brian K. Smith Trust	1,000
David M. Becker	1,000
David W. Verhille	1,000
Larry H. Powell	953
Bart S. Bergman	953
Zachary A. Hamel	953
Kenneth P. Malvey	953
IMREX, L.P.	762
Steven B. Glassman	762
SLK Family Trust, Sharon L. Kessler Trustee	750

        The applicable prospectus supplement will set forth, with respect to the selling unitholders:

•

the name of the selling unitholders;



•

the nature of the position, office or other material relationship which the selling unitholders will have had within the prior three years with us or any of our affiliates;



•

the number of common units owned by the selling unitholders prior to the offering;

49

•

the amount of common units to be offered for the selling unitholders' account and;



•

the amount and (if one percent or more) the percentage of common units to be owned by the selling unitholders after the completion of the offering.

        All expenses incurred with the registration of the common units owned by the selling unitholders will be borne by us.

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PLAN OF DISTRIBUTION

        Under this prospectus, both we and the selling unitholders intend to offer our securities to the public:

•

through one or more broker-dealers;



•

through underwriters; or



•

directly to investors.

        We will fix a price or prices, and we may change the price of the securities offered from time to time:

•

at market prices prevailing at the time of any sale under this registration statement;



•

prices related to market prices; or



•

negotiated prices.

        We and the selling unitholders will pay or allow distributors' or sellers' commissions that will not exceed those customary in the types of transactions involved. Broker-dealers may act as agents or may purchase securities as principals and thereafter resell the securities from time to time:

•

in or through one or more transactions (which may involve crosses and block transactions) or distributions;



•

on the American Stock Exchange;



•

in the over-the-counter market; or



•

in private transactions.

        Broker-dealers or underwriters may receive compensation in the form of underwriting discounts or commissions and may receive commissions from purchasers of the securities for whom they may act as agents. If any broker-dealer purchases the securities as a principal, it may effect resales of the securities from time to time to or through other broker-dealers, and other broker-dealers may receive compensation in the form of concessions or commissions from the purchasers of securities for whom they may act as agents.

        To the extent required, the names of the specific managing underwriter or underwriters, if any, as well as other important information, will be set forth in the applicable prospectus supplement. In that event, the discounts and commissions we and the selling unitholderswill allow or pay to the underwriters, if any, and the discounts and commissions the underwriters may allow or pay to dealers or agents, if any, will be set forth in, or may be calculated from, the prospectus supplements. Any underwriters, broker, dealers and agents who participate in any sale of the securities may also engage in transactions with, or perform services for, us or our affiliates in the ordinary course of their businesses.

        In addition, the selling unitholders have advised us that they may sell common units in compliance with Rule 144, if available, or pursuant to other available exemptions from the registration requirements under the Securities Act, rather than pursuant to this prospectus.

        To the extent required, this prospectus may be amended or supplemented from time to time to describe a specific plan of distribution.

        In connection with offerings under this shelf registration and in compliance with applicable law, underwriters, brokers or dealers may engage in transactions that stabilize or maintain the market price of the securities at levels above those that might otherwise prevail in the open market in accordance with Regulation M under the Exchange Act. Specifically, underwriters, brokers or dealers may

51

over-allot in connection with offerings, creating a short position in the securities for their own accounts. For the purpose of covering a syndicate short position or stabilizing the price of the securities, the underwriters, brokers or dealers may place bids for the securities or effect purchases of the securities in the open market. Finally, the underwriters may impose a penalty whereby selling concessions allowed to syndicate members or other brokers or dealers for distribution the securities in offerings may be reclaimed by the syndicate if the syndicate repurchases previously distributed securities in transactions to cover short positions, in stabilization transactions or otherwise. These activities may stabilize, maintain or otherwise affect the market price of the securities, which may be higher than the price that might otherwise prevail in the open market, and, if commenced, may be discontinued at any time.

LEGAL MATTERS

        Vinson & Elkins L.L.P., will pass upon the validity of the securities offered in this registration statement. The selling unitholder's counsel will advise them about other issues related to the offering.

EXPERTS

        The financial statements incorporated in this Prospectus by reference to the Annual Report on Form 10-K for the year ended December 31, 2003 have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

52

2,159,138 Common Units

Representing Limited Partner Interests

PROSPECTUS SUPPLEMENT

RBC CAPITAL MARKETS

A.G. EDWARDS

WACHOVIA SECURITIES

KEYBANC CAPITAL MARKETS

STIFEL, NICOLAUS & COMPANY

   INCORPORATED

September    , 2004