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Filed Pursuant to Rule 424(b)(5)
Commission File No. 333-164323

           CALCULATION OF REGISTRATION FEE

(1)

The filing fee, calculated in accordance with Rule 457(r), has been transmitted to the SEC in connection with the securities offered from Registration Statement File No. 333-164323 by means of this prospectus supplement.

Prospectus Supplement
To Prospectus dated January 13, 2010

           $500,000,000

MarkWest Energy Partners, L.P.
MarkWest Energy Finance Corporation

6³/4% Senior Notes due 2020

MarkWest Energy Partners, L.P. and MarkWest Energy Finance Corporation are offering $500,000,000 aggregate principal amount of 6³/4% Senior Notes due 2020.

The notes will mature on November 1, 2020. Interest on the notes will accrue from November 2, 2010 and we will pay interest twice a year, beginning on May 1, 2011.

We may redeem some or all of the notes at any time on or after November 1, 2015 at the redemption prices listed in this prospectus supplement, together with accrued and unpaid interest, if any, to the date of redemption, and we may redeem all of the notes at any time prior to November 1, 2015 at the make-whole redemption price specified in this prospectus supplement. In addition, prior to November 1, 2013, we may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at the redemption price specified in this prospectus supplement under "Description of Notes — Optional Redemption." If we sell certain of our assets or experience specific kinds of changes of control, we must offer to repurchase the notes.

The notes will be the senior unsecured obligations of MarkWest Energy Partners, L.P. and MarkWest Energy Finance Corporation, a wholly-owned subsidiary of ours that has no material assets and was formed for the sole purpose of being a co-issuer of some of our indebtedness, including the notes. The notes will rank equally with all of our existing and future senior debt, senior to all of our future subordinated debt and effectively junior in right of payment to all of our existing and future senior secured debt to the extent of the value of the collateral securing such indebtedness. The notes will be guaranteed on a senior unsecured basis by each of our existing wholly-owned subsidiaries and certain of our future subsidiaries.

Investing in the notes involves risks. Please read "Risk Factors" beginning on page S-16.

None of the Securities and Exchange Commission, any state securities commission or any other regulatory body has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying base prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

We expect that the delivery of the notes will be made to investors in book-entry form through The Depository Trust Company on or about November 2, 2010.

Joint Book Running Managers

Senior Co-Managers

Co-Managers

The date of this prospectus supplement is October 19, 2010.

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TABLE OF CONTENTS

Prospectus Supplement

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          This document is in two parts. The first part is this prospectus supplement, which describes our business and the specific terms of this offering of the notes. The second part is the accompanying base prospectus, which gives more general information, some of which may not apply to this offering of the notes. Generally, when we refer only to the "prospectus," we are referring to both parts combined. If the information about the notes offering varies between this prospectus supplement and the accompanying base prospectus, you should rely on the information in this prospectus supplement.

          Any statement made in this prospectus or in a document incorporated or deemed to be incorporated by reference into this prospectus will be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in any other subsequently filed document that is also incorporated by reference into this prospectus modifies or supersedes that statement. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to constitute a part of this prospectus. Please read "Where You Can Find More Information" on page S-92 of this prospectus supplement.

          We expect delivery of the notes will be made against payment therefor on or about November 2, 2010, which is the tenth business day following the date of pricing of the notes (such settlement being referred to as "T+10"). Under Rule 15(c)6-1 of the Securities Exchange Act of 1934, as amended, trades in the secondary market generally are required to settle in three business days unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade the notes on the date of pricing of the notes or during the next succeeding seven business days will be required, by virtue of the fact that the notes initially will settle in T+10, to specify an alternate settlement cycle at the time of any such trade to prevent failed settlement and should consult their own advisers.

          You should rely only on the information contained in or incorporated by reference into this prospectus supplement, the accompanying base prospectus and any free writing prospectus relating to this offering of the notes. Neither we nor the underwriters have 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 are offering to sell the notes, and seeking offers to buy the notes, only in jurisdictions where offers and sales are permitted. You should not assume that the information contained in this prospectus supplement, the accompanying base prospectus or any free writing prospectus is accurate as of any date other than the dates shown in these documents or that any information we have incorporated by reference herein 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.

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SUMMARY

          This summary highlights information contained elsewhere in this prospectus supplement and the accompanying base prospectus. It does not contain all of the information that you should consider before making an investment decision. For a more complete understanding of this offering, you should read this entire prospectus supplement, the accompanying base prospectus, any free writing prospectus relating to the notes and the documents incorporated herein by reference, including our historical financial statements and the notes thereto, which are incorporated herein by reference from our annual report on Form 10-K for the year ended December 31, 2009, and our quarterly reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010. Please read "Where You Can Find More Information" on page S-92 of this prospectus supplement. Please read "Risk Factors" beginning on page S-16 of this prospectus supplement and Item 1A. "Risk Factors" in our annual report on Form 10-K for the year ended December 31, 2009 and our quarterly report on Form 10-Q for the quarter ended June 30, 2010 for information regarding risks you should consider before buying notes in this offering. We include a glossary of some of the terms used in this prospectus supplement as Appendix A.

          For purposes of this prospectus supplement and the accompanying base prospectus, unless the context clearly indicates otherwise, "we," "us," "our" and the "Partnership" refer to MarkWest Energy Partners, L.P. and its consolidated subsidiaries; and "MarkWest Hydrocarbon" refers to MarkWest Hydrocarbon, Inc. and its direct and indirect consolidated subsidiaries.

MarkWest Energy Partners, L.P.

          We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. We have extensive natural gas gathering, processing and transmission operations in the southwest, Gulf Coast and northeast regions of the United States, including the Marcellus Shale, and we are the largest natural gas processor in the Appalachian region.

Business Strategy

          Our primary business strategy is to provide top-tier midstream services by developing and operating high-quality, strategically-located assets in the United States. We plan to accomplish this through the following:

•

Developing long-term integrated relationships with our producer customers.  As a top-rated midstream service provider, we have worked to redefine our relationships with our key producer customers, as evidenced by our relationships with the primary producers in the Woodford Shale and the Marcellus Shale. We will continue to develop relationships that are characterized by joint planning for the development of the emerging resource plays and our commitment to grow to meet the specific needs of our customers.



•

Expanding operations through organic growth projects.  By expanding our existing infrastructure and customer relationships, we intend to continue to grow in our primary areas of operation to meet the anticipated demand for additional midstream services. During 2010, we and our joint venture partner plan to spend approximately $490 million to $540 million in total capital to develop midstream infrastructure in the Marcellus Shale through MarkWest Liberty Midstream & Resources, L.L.C. ("Liberty Midstream"), a joint venture with The Energy & Minerals Group ("EMG"), and expand several of our gathering and processing operations in our Southwest segment, including the Woodford gathering system in the Arkoma Basin, and our operations in East Texas and in Western Oklahoma, including Stiles Ranch. Our share of these growth and expansion capital expenditures is expected to be approximately $300 million to $350 million and the remainder will be funded through contributions from our Liberty Midstream joint venture partner and existing cash balances in the joint venture. As of June 30, 2010, we and our joint partner have spent approximately $253.3 million of this amount.

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•

Maintaining our financial flexibility.  During 2009, we received net proceeds of approximately $178.6 million from the issuance of our common units and $113.8 million from the issuance of long-term debt. In April 2010, we received net proceeds of approximately $142.3 million from the issuance of common units. In July 2010, we entered into an amended and restated credit agreement (the "Amended and Restated Credit Agreement") that provides for a revolving loan facility (the "Credit Facility") of up to $705 million, with an uncommitted accordion feature of up to $195 million. Our goal is to maintain a capital structure with approximately equal amounts of debt and equity on a long-term basis. We also consider the use of alternative financing strategies such as entering into joint venture arrangements and the sale of selected assets that are not a core component of our long-term objectives. Our Credit Facility, our ability to issue additional partnership units and long-term debt, our strong relationships with our joint venture partners, and the sale of non-strategic assets should provide us with the financial flexibility to facilitate the execution of our business strategy.



•

Reducing the sensitivity of our cash flows to commodity price fluctuations.  We intend to continue to secure long-term, fee-based contracts in order to further minimize our exposure to short-term changes in commodity prices. We expect that our fee-based contracts will account for approximately 50% of our net operating margin by 2012. We also engage in risk management activities in order to reduce the effect of commodity price volatility related to future sales of natural gas, NGLs and crude oil. We may utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps, and options available in the over-the-counter market. We monitor these activities through enforcement of our commodity risk management policy. For more details about our commodity risk management policy, please read Note 7 to our historical consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2009, which is incorporated herein by reference.



•

Increasing utilization of our facilities.  We seek to increase the utilization of our existing facilities by providing additional services to our existing customers, and by establishing relationships with new customers. We also continue to develop additional capacity at several of our facilities, which enables us to increase throughput with minimal incremental costs.



•

Expanding operations through strategic acquisitions.  We intend to continue pursuing strategic acquisitions of assets and businesses in our existing areas of operation that leverage our current asset base, personnel and customer relationships. We may also seek to acquire assets in certain regions outside of our current areas of operation. We believe that our capital structure, which no longer includes incentive distribution rights, positions us to compete more effectively for future transactions.

          Execution of our business strategy has allowed us to grow substantially since our inception. The majority of our growth since 2006 has focused on the development of natural gas supplies in emerging resource plays. As a result, we now have a strong presence in the Woodford Shale, Haynesville Shale, Granite Wash and Marcellus Shale, four emerging resource plays that are expected to be significant sources of domestic natural gas production in the future. The following table summarizes the capital investments associated with growth projects and acquisitions that we have completed since 2004 (amounts in millions).

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Competitive Strengths

          We believe that the following competitive strengths position us to continue to successfully execute our primary business strategy:

•

Leading position in the early development of the Marcellus Shale.  As a result of strategic agreements with key producers, we are currently the largest gatherer and processor of natural gas in the Marcellus Shale. These long-term agreements include significant acreage dedications in the rich-gas areas of the shale. Our gathering systems and processing plants in the Marcellus Shale are relatively new and highly efficient, and we continue to expand these facilities with a strong financial partner in EMG under the Liberty Midstream joint venture arrangement. Leveraging our current and planned fractionation capacity, our strategic transportation and storage agreements that provide access to NGL markets, and our extensive marketing experience in the northeast region, we are positioned to offer fully integrated midstream services for the producers in the Marcellus Shale.



•

Strategic and growing position with high-quality assets in the Southwest and the Gulf Coast.  Our acquisitions and internal growth projects have allowed us to establish and expand our presence in several long-lived natural gas supply basins in the Southwest, particularly in Texas and Oklahoma. In late 2006, we built the largest gathering system to date in the Woodford Shale play in Southeast Oklahoma pursuant to our agreement with Newfield Exploration Mid-Continent Inc. Our Gulf Coast assets provide high quality service to six strategically located Gulf Coast refineries that we believe will continue to play a key role in supporting U.S. demand for refined petroleum products in the long term. All of our major acquisitions in these regions have been characterized by several common critical success factors that include:



•

an existing strong competitive position;



•

access to a significant reserve or customer base with a stable or growing production profile;



•

ample opportunities for long-term continued organic growth;



•

ready access to markets; and



•

close proximity to other acquisition or expansion opportunities.

Specifically, our East Texas and Appleby gathering systems are located in the East Texas Basin, producing from both the Cotton Valley and Travis Peak reservoirs as well as the Haynesville Shale. Our western Oklahoma assets include the Foss Lake gathering system and the associated Arapaho gas processing plants located in the Anadarko Basin in Oklahoma and our Granite Wash gathering system in the Texas panhandle. Additionally, as mentioned above, our Woodford

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gathering system is located in the Woodford Shale reservoir. Our gathering systems are relatively new and provide producers with low-pressure and fuel-efficient service, a significant competitive advantage for us over many competing gathering systems in those areas.

•

Leading position and continued expansion in the Appalachian Basin.  We are the largest processor of natural gas in Appalachia. We believe our significant presence and asset base provide us with a competitive advantage in capturing and contracting for new supplies of natural gas. The Appalachian Basin is a large natural gas-producing region characterized by long-lived reserves with modest decline rates and natural gas with high NGL content. Our concentrated infrastructure, available land, storage assets and expansion plans in Appalachia should continue to provide us with a platform for additional cost-effective expansion opportunities. In 2009, we completed the expansion of our Cobb processing facility and the expansion of our Siloam fractionation facility.



•

Long-term contracts.  We believe that our long-term contracts, which we define as contracts with remaining terms of four years or more, enhance the stability of our cash flow profile. In East Texas, approximately 73% of our gathering volumes were under contract for longer than five years as of December 31, 2009. Due to new contracts signed in late 2008 and 2009, as of December 31, 2009, approximately 57% of our daily throughput in the Western Oklahoma gathering system and Arapaho processing plants was subject to contracts with remaining terms of more than eight years. As of December 31, 2009, approximately 94% of our throughput in the Woodford gathering system was subject to contracts with remaining terms of more than seven years. Also, as of December 31, 2009, in our Southwest segment, two of our lateral pipelines operated under fixed-fee contracts for the transmission of natural gas that expire in approximately 19 and 11 years, respectively. In Appalachia, our natural gas processing and NGL fractionation contracts with remaining terms of more than five years accounted for approximately 83% of our volumes as of December 31, 2009. In our Gulf Coast segment, as of December 31, 2009, approximately 56% of our volumes were under contract for more than four years. In our Liberty segment, as of December 31, 2009, all gathering and processing agreements with significant dedicated acreage had remaining terms of at least ten years.



•

Experienced management team with operational, technical and acquisition expertise.  Each member of our executive management team has substantial experience in the energy industry. Our facility managers have extensive experience operating our facilities. Our operational and technical expertise has enabled us to upgrade our existing facilities, as well as to design and build new facilities. Since our initial public offering in May 2002, our management team has utilized a disciplined approach to analyze and evaluate numerous acquisition opportunities, and has completed eleven acquisitions.

Our Operations

          We conduct our business in four reportable segments: Southwest, Northeast, Liberty and Gulf Coast. In addition to our non-controlling interest in Centrahoma Processing LLC ("Centrahoma"), we have seven distinct operating areas within these segments that are described below. For full-year 2010, we estimate that total capital expenditures to fund identified organic growth and expansion projects that already have been approved by our board of directors will be approximately $490 million to $540 million. Our share of these growth capital expenditures is expected to be approximately $300 million to $350 million, and the remainder will be funded through contributions from our Liberty Midstream joint venture partner and existing cash balances in the Liberty Midstream joint venture.

Southwest

•

East Texas.  We own a system that consists of natural gas gathering pipelines, centralized compressor stations, a natural gas processing facility and an NGL pipeline. The East Texas system is

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located in Panola, Harrison and Rusk Counties and services the Carthage Field. Producing formations in Panola County consist of the Cotton Valley, Pettit, Travis Peak and Haynesville formations. For natural gas that is processed in this area, we purchase the NGLs from the producers primarily under percent-of-proceeds arrangements, or we transport volumes for a fee.

•

Oklahoma.  We own a Foss Lake natural gas gathering system and the Arapaho I and II natural gas processing plants, all located in Roger Mills, Custer and Ellis Counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities. The majority of the gathered gas ultimately is compressed and delivered to the processing plants. We also own and operate a gathering system in the Granite Wash formation in the Texas panhandle that is connected to our Foss Lake processing plants and our Grimes gathering system that is located in Roger Mills and Beckham Counties in western Oklahoma. In addition, we own a natural gas gathering system in the Woodford Shale in the Arkoma Basin of southeast Oklahoma. Natural gas gathered in the Woodford system is processed by Centrahoma, in which we have a 40% non-operating membership interest.

Through our joint venture MarkWest Pioneer, L.L.C. ("MarkWest Pioneer"), we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with Midcontinent Express Pipeline and Gulf Crossing Pipeline at Bennington, Oklahoma and is designed to provide approximately 638,000 Dth/d of Arkoma Basin takeaway capacity. For a complete discussion of the formation of, and accounting treatment for, MarkWest Pioneer, please read Note 4 to our historical consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2009.

•

Other Southwest.  We own a number of natural gas gathering systems in Texas, Louisiana, Mississippi and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. We gather a significant portion of the natural gas produced from fields adjacent to our gathering systems, including from wells targeting the Haynesville formation. In many areas we are the primary gatherer, and in some of the areas served by our smaller systems we are the sole gatherer. In addition, we own four lateral pipelines in Texas and New Mexico.

Northeast

•

Appalachia.  We are the largest processor of natural gas in the Appalachian Basin, with fully integrated processing, fractionation, storage and marketing operations. The Appalachian Basin is a large natural gas producing region characterized by long-lived reserves and modest decline rates. Our Appalachian assets include the Kenova, Boldman, Cobb and Kermit natural gas processing plants, an NGL pipeline, the Siloam NGL fractionation plant and two caverns for storing propane. The Appalachia operations include fractionation and marketing services on behalf of the Liberty segment.



•

Michigan.  We own and operate a FERC-regulated crude oil pipeline in Michigan that provides transportation services for three shippers.

Liberty

•

Marcellus Shale.  We operate natural gas gathering systems and processing facilities located primarily in western Pennsylvania and northern West Virginia through Liberty Midstream. We have 155 MMcf/d of cryogenic processing capacity at our Houston, Pennsylvania processing complex and plan to complete the installation of a 200 MMcf/d cryogenic plant in the first half of 2011. We also plan to complete a 60,000 Bbl/d fractionation facility at our Houston complex in 2011. We commenced operation of a 120 MMcf/d cryogenic plant at our Majorsville site in the third quarter of 2010 and expect to increase the cryogenic processing capacity at this site to approximately 270 MMcf/d by the third quarter of 2011. Until such time, the majority of the raw NGLs produced at our Liberty facilities are fractionated at the Siloam NGL fractionation plant in

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our Northeast segment. We expect the total planned processing capacity to be supported by existing and new long-term agreements with our producer customers. Certain volumes of propane and raw NGLs produced at the Liberty facilities are sold without fractionation at Siloam. We have completed construction of an interconnect with a key interstate NGL pipeline, providing an additional market outlet for the propane. In addition, we are developing a market outlet for the ethane produced in the Marcellus Shale through a combined pipeline and marine project (the "Mariner Project") to deliver purity ethane to Gulf Coast markets. The Mariner Project is a joint project with Sunoco Logistics that is anticipated to have initial capacity to transport up to 50,000 Bbl/d of ethane by mid-2012 and may be expanded to support additional Marcellus production. For a complete discussion of the formation of, and accounting treatment for, Liberty Midstream, please read Note 4 to our historical consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2009.

Liberty Midstream and NiSource Gas Transmission & Storage ("NGT&S") intend to jointly develop natural gas gathering, processing, and transmission projects to support increased Marcellus production volumes in the northern West Virginia area of the Appalachian Basin. It is anticipated that the joint project would initially include existing and new pipelines that deliver gas to NGT&S' Smithfield, West Virginia compressor station where Liberty Midstream would install a 120 MMcf/d cryogenic processing facility. Liberty Midstream would complement these processing facilities with fractionation services provided at its Houston, Pennsylvania NGL fractionation, storage, and marketing complex to take advantage of the premium regional markets and to maximize the value of the producers' gas.

We are currently in negotiations with a producer customer with significant Marcellus Shale acreage in Pennsylvania and West Virginia that would include the construction of natural gas processing and pipeline facilities and the utilization of our existing fractionation facility to fractionate the natural gas liquids produced. If this agreement is consummated, our total potential commitment would be up to $350 million, a portion of which would be funded by EMG, our Liberty Midstream joint venture partner. We anticipate funding of the project will begin in late 2010 and continue through the fourth quarter of 2011, and we further anticipate that our portion of the financial commitment will be funded through available cash and borrowings on our Credit Facility.

Gulf Coast

•

Javelina.  We own and operate the Javelina processing facility, a natural gas processing facility in Corpus Christi, Texas that treats and processes off-gas from six local refineries operated by three different refinery customers. We have a hydrogen supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the hydrogen processed by the steam methane reformer ("SMR") that is operated by a third party. The hydrogen received under this agreement will be sold to a refinery customer pursuant to a corresponding long-term agreement. For further discussion of this agreement and the related divestiture of the SMR, please read Note 6 to our historical consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2009.

Recent Developments

Amended and Restated Credit Agreement

          In July 2010, we entered into the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement replaces our prior credit agreement in its entirety and provides for a revolving loan facility of up to $705 million, with an uncommitted accordion feature of up to $195 million. The borrowings under the Credit Facility continue to bear interest at a variable interest rate, plus basis points. The variable interest rate is based either on LIBOR ("LIBOR Loans") or the higher of (a) the

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prime rate set by the Credit Facility's administrative agent, (b) the Federal Funds Rate plus 0.5% and (c) the rate for LIBOR for a one month interest period plus 1% ("Alternate Base Rate Loans"). The basis points correspond to the ratio of our Consolidated Funded Debt (as defined in the Amended and Restated Credit Agreement) to our Adjusted Consolidated EBITDA (as defined in the Amended and Restated Credit Agreement), ranging from 1.5% to 2.5% for Alternate Base Rate Loans and from 2.5% to 3.5% for LIBOR Loans. We may use up to $150 million of the Credit Facility for the issuance of letters of credit and $10 million for shorter term swingline loans.

          The Credit Facility is guaranteed by all of our wholly-owned subsidiaries and is collateralized by substantially all of our assets.

Tender Offers

          Concurrently with the launch of this offering, we commenced tender offers for any and all of our outstanding 6.875% Senior Notes due 2014 (the "2014 Notes"). The aggregate principal amount outstanding of both series of the 2014 Notes is $375 million. We are offering to purchase the 2014 Notes and related consent solicitations for cash equal to 99.5% of their principal amount, together with accrued and unpaid interest to the purchase date and a consent fee of 3.0%, of the principal amount of notes tendered before 5:00 p.m., New York City time, on November 1, 2010, unless extended by us. No consent fees will be paid to holders who tender their notes after November 1, 2010 and prior to the expiration of the tender offers on November 16, 2010, unless extended by us. We also will solicit consents to certain proposed amendments to the indentures governing the notes. Our offers to purchase the 2014 Notes are being made on the terms and subject to the conditions set forth in an Offer to Purchase and Consent Solicitation Statement dated October 19, 2010.

          The tender offers are conditioned upon, among other things, our completion of this offering so that with the net proceeds from this offering we will have sufficient funds to pay for all tendered 2014 Notes and delivered consents plus all related fees and expenses. However, this offering is not conditioned upon the consummation of either tender offer at any minimum level of acceptance.

          If fully subscribed by November 1, 2010, we expect that the tender offers and consent solicitations will result in a pre-tax charge to our net income of approximately $46.5 million, and that they will cost approximately $397.7 million (including accrued and unpaid interest and the consent fees), which would be funded with a portion of net proceeds from this offering as described in "Use of Proceeds."

          There is no assurance that the tender offers will be subscribed for in any amount, and we currently intend to redeem any 2014 Notes that remain outstanding following the tender offers as permitted under the governing indentures, although we have no legal obligation to do so and the selection of any particular redemption date is in our discretion.

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PARTNERSHIP STRUCTURE AND MANAGEMENT

          MarkWest Energy Finance Corporation, the co-issuer of the notes, is a direct wholly-owned subsidiary of MarkWest Energy Partners and carries on no independent business other than acting as a co-issuer of the notes and our other senior notes.

          For more details about our ownership structure, please read "Organizational Structure" included in Item 1 in our annual report on Form 10-K for the year ended December 31, 2009, which is incorporated herein by reference.

Management of MarkWest Energy Partners, L.P.

          Our general partner, which we indirectly own and control, has sole responsibility for conducting our business and for managing our operations. Our common unitholders have the right to elect the members of the board of directors of our general partner at our annual meeting of unitholders.

Principal Executive Offices and Internet Address

          Our principal executive offices are located at 1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado 80202. We maintain a website at http://www.markwest.com. The information on our website is not part of this prospectus supplement, and you should rely only on information contained in or incorporated by reference herein and any free writing prospectus filed in connection with this offering when making an investment decision.

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THE OFFERING

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SUMMARY HISTORICAL CONDENSED COMBINED FINANCIAL
AND OPERATING DATA

          The following tables show our summary historical financial and operating data as of and for the periods indicated. We derived the information in the following tables from, and that information should be read together with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2009, and our quarterly report on Form 10-Q for the quarter ended June 30, 2010, which are incorporated herein by reference. The tables should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in our annual report on Form 10-K for the year ended December 31, 2009, and our quarterly report on Form 10-Q for the quarter ended June 30, 2010, which are incorporated herein by reference.

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(1)

Revenue, purchased product costs, facility expenses and interest expense have been impacted by our commodity derivative instruments. Miscellaneous income (expense), net has been impacted by an embedded derivative related to certain outstanding senior notes. As discussed further in Note 7 to our historical consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2009, which is incorporated herein by reference, volatility in any given period related to unrealized gains and losses on our derivative positions can be significant. The following table summarizes the unrealized and realized losses and gains for the periods indicated:

(2)

We define net operating margin as revenue, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss). These charges have been excluded for the purpose of enhancing the understanding, by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin is not a measure calculated in accordance with GAAP and should not be considered in isolation from, or as a substitute for, net income, net income attributable to the Partnership, income from operations or cash flow from operating activities as reflected in our financial statements. Net operating margin does not have any standardized definition and therefore is unlikely to be comparable to similar measures presented by other reporting companies. Our use of net operating margin,

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and the underlying methodology in excluding certain charges, is not necessarily an indication of the results of operations that may be expected in the future, or that we will not, in fact, incur such charges in future periods. The following table reconciles net operating margin to (loss) income from operations, which is the most directly comparable GAAP financial performance measure:

(3)

In general, we define Adjusted EBITDA as net income (loss) adjusted for (i) depreciation, amortization, accretion, and impairment expense; (ii) interest expense; (iii) amortization of deferred financing costs; (iv) losses (gains) on the disposal of property, plant and equipment ("PP&E") and unconsolidated affiliates; (v) non-cash derivative activity; (vi) non-cash compensation expense; (vii) provision for income taxes; (viii) adjustment related to non-wholly owned subsidiaries; (ix) adjustments for cash flow from unconsolidated investments; and (x) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period. Adjusted EBITDA is a financial performance measure used by management, industry analysts, investors, lenders, and rating agencies to assess the financial performance and operating results of the Partnership's ongoing business operations. Additionally, we believe Adjusted EBITDA provides useful information to investors for trending, analyzing, and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures.

There are material limitations to using a measure such as Adjusted 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 Adjusted EBITDA in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income, net income attributable to the Partnership and cash flow from operating activities. In addition, our calculation of Adjusted EBITDA may not be consistent with similarly titled measures presented by other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. The following table reconciles Adjusted EBITDA to net (loss) income, which is the most directly comparable GAAP financial performance measure:

(4)

Maintenance capital includes capital expenditures made to maintain our operating capacity and asset base. Growth capital includes expenditures made to expand the existing operating capacity, to increase the efficiency of our existing assets, and to facilitate an increase in volumes within our operations. Growth capital also includes costs associated with new well connections, expenditures for construction, third-party acquisitions and equity investments.

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Operating Statistics

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RISK FACTORS

          An investment in the notes is subject to a number of risks. You should carefully consider the risk factors beginning on page 5 of the accompanying prospectus and the risk factors included below and those in Item 1A. "Risk Factors" in our annual report on Form 10-K for the year ended December 31, 2009 and in our quarterly report on Form 10-Q for the quarter ended June 30, 2010, together with all of the other information included or incorporated by reference in this prospectus supplement. You should consider the following risk factors in evaluating this investment. If any of these risks materialize into actual events, our business, financial condition or results of operations could be adversely affected.

Risks Related to our Business

Our substantial debt and other financial obligations could impair our financial condition, results of operations and cash flows, and our ability to fulfill our debt obligations.

          We have substantial indebtedness and other financial obligations. Subject to the restrictions governing our indebtedness and other financial obligations, including the indentures governing our outstanding notes, we may incur significant additional indebtedness and other financial obligations.

          Our substantial indebtedness and other financial obligations could have important consequences. For example, they could:

•

make it more difficult for us to satisfy our obligations with respect to our existing debt;



•

impair our ability to obtain additional financings in the future for working capital, capital expenditures, acquisitions, or general partnership and other purposes;



•

have a material adverse effect on us if we fail to comply with financial and restrictive covenants in our debt agreements, and an event of default occurs as a result of that failure that is not cured or waived;



•

require us to dedicate a substantial portion of our cash flow to payments on our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, distributions and other general partnership requirements;



•

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and



•

place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

          Furthermore, these consequences could limit our ability, and the ability of our subsidiaries, to obtain future financings, make needed capital expenditures, withstand the prevailing economic uncertainty or any future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. Our Credit Facility contains covenants requiring us to maintain specified financial ratios and satisfy other financial conditions, which may limit our ability to grant liens on our assets, make or own certain investments, enter into any swap contracts other than in the ordinary course of business, merge, consolidate, or sell assets, incur indebtedness senior to our Credit Facility, make distributions on equity investments, and declare or make, directly or indirectly, any distribution on our common units. Our obligations under our Credit Facility are secured by substantially all of our assets and guaranteed by all of our wholly-owned subsidiaries, including our operating company (please read "Description of Other Indebtedness — Credit Facility"). We may be unable to meet those ratios and conditions. Any future breach of any of these covenants or our failure to meet any of these ratios or conditions could result in a default under the terms of our Credit Facility, which could result in acceleration of our debt and other financial obligations. If we were unable to repay those amounts, the lenders could initiate a bankruptcy or liquidation proceeding, or proceed against the collateral.

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Global economic conditions may have adverse impacts on our business and financial condition.

          Changes in economic conditions could adversely affect our financial condition and results of operations. A number of economic factors, including, but not limited to, gross domestic product, consumer interest rates, strength of U.S. currency, consumer confidence and debt levels, retail trends, housing starts, sales of existing homes, the level of mortgage refinancing, inflation and foreign currency exchange rates, may generally affect our business. Recessionary economic cycles, higher unemployment rates, higher fuel and other energy costs, and higher tax rates may adversely affect demand for natural gas, NGLs and crude oil. A decline in economic activity and conditions in the United States and any other markets in which we operate could adversely affect our financial condition and results of operations.

          The significant disruption in the global markets and financial systems and the decline in the U.S. economy in 2008, which continued through 2009 and into 2010 has only recently begun to improve, increased both the volatility and the amplitude of the risk associated with the other risk factors identified in this report. In particular, these events impacted our yield and unit price, and substantially increased our cost of capital during 2009. If the prevailing economic uncertainty persists or in the event of renewed turmoil in the financial systems, there could be an incremental tightening in the capital markets. Our ability to access the capital markets may be restricted or be available only on unfavorable terms, which could significantly and adversely impact our ability to execute our long term organic growth projects and meet obligations to our producer customers. Limited access to the capital markets could also adversely impact our ability to otherwise take advantage of business opportunities or react to changing economic and business conditions. Our ability to obtain capital from our Amended and Restated Credit Agreement could be adversely impacted by the failure of one or more of the members of the participating bank group. Ultimately we may be required to substantially reduce our future capital expenditures. The prevailing economic uncertainty could also have an impact on our producers, other customers, or counterparties to our commodity hedging arrangements causing them to fail to meet their obligations to us. These factors could have a material adverse effect on our revenues, income from operations and cash flows and our ability to make payment on the notes. The uncertainty and volatility of the global economy may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

          Furthermore, the current conditions of the global financial markets have contributed, and recent declines in commodity prices may have contributed, to a decline in our unit price and corresponding market capitalization in 2009, and could reoccur in the last quarter of 2010. Continued declines in our market capitalization could result in an additional noncash impairment of our recorded goodwill. Continued declines in commodity prices could have an adverse impact on cash flows from operations that could result in noncash impairments of long-lived assets, as well as other-than-temporary noncash impairments of our equity method investments.

Our profitability and cash flows are affected by the volatility of NGL product and natural gas prices.

          We are subject to significant risks associated with frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas and NGLs have been volatile, and we expect this volatility to continue. The New York Mercantile Exchange ("NYMEX") daily settlement price of natural gas for the prompt month contract in 2008 ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu. In 2009, the same index ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu. A composite of the weighted monthly average NGLs price at our Appalachian facilities based on our average NGLs composition in 2008 ranged from a high of approximately $2.24 per gallon to a low of approximately $0.55 per gallon. In 2009, the same composite ranged from approximately $1.44 per gallon to approximately $0.68 per gallon. The markets and prices for natural gas and NGLs depend

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upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

•

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



•

demand for natural gas and NGL products in localized markets;



•

changes in interstate pipeline gas quality specifications;



•

imports of crude oil, natural gas and NGLs;



•

seasonality;



•

the condition of the U.S. economy;



•

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



•

government regulation, legislation and policies.

          Our net operating margins under various types of commodity-based contracts are directly affected by changes in NGL product prices and natural gas prices, and thus are more sensitive to volatility in commodity prices than our fee-based contracts. Additionally, our purchase and resale of gas in the ordinary course of business exposes us to significant risk of volatility in gas prices due to the potential difference in the time of the purchases and sales, and the potential existence of a difference in the gas price associated with each transaction. Significant declines in commodity prices could have an adverse impact on cash flows from operations that could result in noncash impairments of long-lived assets, as well as other-than-temporary noncash impairments of our equity method investments.

Relative changes in NGL product and natural gas prices may adversely impact our results due to frac spread, natural gas and liquids exposure.

          Under our keep-whole arrangements, our principal cost is delivering dry gas of an equivalent Btu content to replace Btus extracted from the gas stream in the form of NGLs, or consumed as fuel during processing. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the "frac spread." Generally, the frac spread and, consequently, the net operating margins are positive under these contracts. In the event natural gas becomes more expensive on a Btu equivalent basis than NGL products, the cost of keeping the producer "whole" results in operating losses.

          Due to timing of gas purchases and liquid sales, direct exposure to changes in market prices of either gas or liquids can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through our marketing and derivatives activity, direct exposure may occur naturally or we may choose direct price exposure to either gas or liquids when we favor that exposure over frac spread risk. Given that we have derivative positions, adverse movement in prices to the positions we have taken will negatively impact results.

Our commodity derivative activities may reduce our earnings, profitability and cash flows.

          Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices.

          The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater

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commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to settle all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which could result in a substantial diminution of our liquidity. Additionally, because we primarily use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk, the volatility or our future cash flows and net income may increase if there is a change in the pricing relationship between crude oil and NGLs. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the downside volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. For further information about our risk management policies and procedures, please read Item 7A. "Quantitative and Qualitative Disclosures About Mark Risk — Commodity Price Risk" in our annual report on Form 10-K for the year ended December 31, 2009.

We conduct risk management activities but we may not accurately predict future commodity price fluctuations and therefore expose us to financial risks and reduce our opportunity to benefit from price increases.

          We evaluate our exposure to commodity price risk from an overall portfolio basis. We have discretion in determining whether and how to manage the commodity price risk associated with our physical and derivative positions.

          To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity price risk, and commodity prices move adversely, we could suffer losses. Such losses could be substantial, and could adversely affect our operations and cash flows and our ability to make payments on the notes. In addition, managing the commodity risk may actually reduce our opportunity to benefit from increases in the market or spot prices.

The enactment of the Dodd-Frank Act could have an adverse impact on our ability to hedge risks associated with our business.

          In July 2010, Congress enacted and the President signed broad financial regulatory reform legislation that, among other things, will impose comprehensive regulation on the OTC derivatives marketplace and will affect the use of derivatives in hedging transactions. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") will subject "swap dealers" and "major swap participants" to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also will require central clearing for transactions unless one of the parties is not a swap dealer or major swap participant, is using the transaction to hedge commercial risk and elects not to clear the transaction under the so-called "end-user" exemption. However, the "end-user" exemption does not expressly extend to margin requirements, and uncleared transactions may still be subject to regulated margin requirements. The Dodd-Frank Act delegates significant authority to generally regulate and develop implementing regulations for OTC commodity derivatives to the Commodity Futures Trading Commission ("CFTC") and the Securities and Exchange Commission ("SEC"), including express authority to impose position limits for derivatives related to energy commodities. Separately, in late January 2010, the CFTC proposed regulations that would impose speculative position limits for certain futures and option contracts in natural gas, crude oil, heating oil, and gasoline. These proposed regulations would make an exemption available for certain bona fide hedging of commercial risks. The Dodd-Frank Act and regulations promulgated thereunder will generally become effective one year after the date of enactment of the Act. While we

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know the substance of the Dodd-Frank Act, it is not possible at this time to predict the final form and substance of the CFTC or the SEC regulations that must be adopted to carry out the Act. The CFTC and the SEC must adopt regulations within one year from the date of enactment of the Dodd-Frank Act. Any such regulations that subject us or our counterparties to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. We may be unable to hedge a significant portion of our exposure to commodity price risk which could have a material adverse impact on our income from operations and cash flows and our ability to make payments on the notes.

A significant decrease in natural gas production in our areas of operation would reduce our ability to make payments on the notes.

          Our gathering systems are connected to natural gas reserves and wells, from which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas supplies. Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our gathering systems.

          We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over 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 regulations and the availability and cost of capital. The cost of capital in the current market environment may make it more difficult for producers to finance drilling programs around our systems which could lead to decreased volumes. In addition, 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. During 2009, we saw decreases in the prices of natural gas in connection with the prevailing economic uncertainty, and we cannot predict if these prices will recover or continue to decline in the future. Declines in natural gas prices, if sustained, could lead to a material decrease in such production activity and ultimately to a decrease in exploration activity.

          Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, throughput on our pipelines and the utilization rates of our treating and processing facilities would decline, which could have a material adverse effect on our business, results of operations and financial condition and our ability to make payments on the notes.

Alternative financing strategies may not be successful.

          Periodically, we will consider the use of alternative financing strategies such as joint venture arrangements and the sale of non-strategic assets. Joint venture agreements may not share the risks and rewards of ownership in proportion to the voting interests. Joint venture arrangements may require us to pay certain costs or to make certain capital investments and we may have little control over the amount or the timing of these payments and investments. We may not be able to negotiate terms that adequately reimburse us for our costs to fulfill service obligations for those joint ventures where we are the operator. In addition, our joint venture partners may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone.

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          We may periodically sell assets or portions of our business. Separating the existing operations from our assets or operations of which we dispose may result in significant expense and accounting charges, disrupt our business or divert management's time and attention. We may not achieve expected cost savings from these dispositions or the proceeds from sales of assets or portions of our business may be lower than the net book value of the assets sold. We may not be relieved of all of our obligations related to the assets or businesses sold. These factors could have a material adverse effect on our revenues, income from operations and cash flows and our ability to make payments on the notes.

We depend on third parties for the natural gas and refinery off-gas we process, and the NGLs we fractionate at our facilities, and a reduction in these quantities could reduce our revenues and cash flow.

          Although we obtain our supply of natural gas, refinery off-gas and NGLs from numerous third-party producers, a significant portion comes from a limited number of key producers/suppliers who are committed to us under processing contracts. According to these contracts or other supply arrangements, however, the producers are usually under no obligation to deliver a specific quantity of natural gas or NGLs to our facilities. If these key suppliers, or a significant number of other producers, were to decrease the supply of natural gas or NGLs to our systems and 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 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.

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, legal and inflationary uncertainties, which may delay our construction activities. 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, if at all.

          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 operations and cash flows and our ability to make payments on the notes.

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, or the agreements may not be renewed or may be suspended in some circumstances.

          Our costs may increase at a rate greater than the fees we charge to third parties. 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 due to 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,

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storms, floods, acts of God, explosions and mechanical or physical failures of equipment affecting our facilities or facilities of 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 financial results would suffer.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could reduce our ability to make payments on the notes.

          We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make payments on the notes. The prevailing economic uncertainty may increase this risk. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

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 competition from other gatherers, processors, pipelines and fractionators, 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 which have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, and greater access to natural gas and NGL supplies than we do. Additionally, our customers that 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. Certain of our competitors may also have advantages in competing for acquisitions, or other new business opportunities, because of their financial resources and synergies in operations.

          As a consequence of the increase in competition in the industry, and the 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 affect our profitability. For more information regarding our competition, please read Item 1. "Business — Competition" in our annual report on Form 10-K for the year ended December 31, 2009.

Transportation on certain of our pipelines may be subject to federal or state rate and service regulation, and the imposition and/or cost of compliance with such regulation could adversely affect our operations and cash flows and our ability to make payments on the notes.

          Some of our gas, liquids and crude oil transmission operations are subject to rate and service regulations under FERC or various state regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas and oil in interstate commerce, and FERC's regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities; accounts and records; and depreciation and amortization policies. FERC's action in any of these areas or modifications of its current regulations can adversely impact our ability to compete for business, the costs we incur in our operations, the construction of new facilities or our ability to recover the full cost of operating our pipelines. Intrastate natural gas pipeline operations and transportation on proprietary natural gas or petroleum products pipelines are generally not subject to regulation by FERC, and the Natural Gas Act, which is referred to as "NGA," specifically exempts some gathering systems. Yet such operations may still be subject to regulation by various state agencies. The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a

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fair return on the aggregate value of the facilities used to render services. We cannot assure noteholders that FERC will not at some point determine that such gathering and transportation services are within its jurisdiction, and regulate such services. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please read Item 1. "Business — Regulatory Matters" in our annual report on Form 10-K for the year ended December 31, 2009.

Some of our natural gas and crude oil transportation operations are subject to FERC's rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating our pipelines including a reasonable return.

          Action by FERC on currently pending matters as well as matters arising in the future could adversely affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition and results of operations.

          For example, one such matter relates to FERC's policy regarding allowances for income taxes in determining a regulated entity's cost of service. In May 2005, FERC adopted a policy statement ("Policy Statement"), stating that it would permit entities owning public utility assets, including oil pipelines, to include an income tax allowance in such utilities' cost-of-service rates to reflect actual or potential tax liability attributable to their public utility income, regardless of the form of ownership. Pursuant to the Policy Statement, a tax pass-through entity seeking such an income tax allowance would have to establish that its partners or members have an actual or potential income tax obligation on the entity's public utility income. This tax allowance policy was upheld by the D.C. Circuit in May 2007. Whether a pipeline's owners have actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. How the Policy Statement is applied in practice to pipelines owned by publicly traded partnerships could impose limits on our ability to include a full income tax allowance in cost of service.

If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then we may be unable to fully execute our growth strategy, which may adversely affect our operations and cash flows and our ability to make payments on the notes.

          The construction of additions to our existing gathering assets or in the expansion of Liberty may require us to obtain new rights-of-way prior to constructing new pipelines and other transportation facilities. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines, to connect our existing facilities to new natural gas or natural gas liquids markets, or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, it may adversely affect our operations and cash flows and our ability to make payments on the notes.

We are indemnified for liabilities arising from an ongoing remediation of property on which certain of our facilities are located and our results of operation and our ability to make payments on the notes 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, Kermit and Majorsville 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, Cobb and Majorsville 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.

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          Columbia Gas has agreed to retain sole liability and responsibility for, and to indemnify us 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. Our results of operation and our ability to make payments on the notes could be adversely affected if in the future Columbia Gas fails to perform under the indemnification provisions of which we are the beneficiary.

Our business is subject to federal, regional, 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 operations and cash flows and our ability to make payments on the notes.

          Numerous governmental agencies enforce comprehensive and stringent federal, state, regional and local laws and regulations on a wide range of environmental, safety and other regulatory matters. We could be adversely affected by increased costs due to stricter pollution-control requirements or liabilities resulting from non-compliance with operating or other regulatory permits. Strict and, under certain circumstances, joint and several liability may be incurred without regard to fault, or the legality of the original conduct, under certain of the environmental laws for remediation of contaminated areas, including the Comprehensive Environmental Response, Compensation and Liability Act, as amended, the Resource Conservation and Recovery Act, as amended, and analogous state laws. Private parties, including the owners of properties located near our storage, fractionation and processing facilities or through which our pipeline systems pass, also may have the right to pursue legal actions to enforce compliance, as well as seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. New, more stringent environmental laws, regulations and enforcement policies might adversely influence our products and activities, and existing laws, regulations and policies could be reinterpreted or modified to impose additional requirements or constraints on our operations. Federal, regional, state and local agencies also could impose additional safety requirements, any of which could affect our profitability. Local governments may adopt more stringent zoning ordinances requiring the relocation of our facilities or increasing our costs to construct and operate our facilities. In addition, we face the risk of accidental releases or spills associated with our operations. These could result in material costs and liabilities, including those relating to claims for damages to property, natural resources and persons. Our failure to comply with environmental or safety-related laws and regulations could result in administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and even injunctions that restrict or prohibit some or all of our operations. For more information regarding the environmental, safety and other regulatory matters that could affect our business, please read Item 1. "Business — Regulatory Matters", "Item 1. Business — Environmental Matters", and Item 1. "Business — Pipeline Safety Regulations", each as set forth in our annual report on Form 10-K for the year ended December 31, 2009.

Climate change legislation or regulations restricting emissions of "greenhouse gasses" could result in increased operating costs and reduced demand for our midstream services.

          On December 15, 2009, the U.S. EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases, or "GHGs," present an endangerment to public heath and the environment because emissions of such gasses are, according to the EPA, contributing to the warming of the earth's atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or "PSD," and Title V permitting programs. This rule "tailors" these permitting programs to apply to certain stationary

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sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to "best available control technology" standards for GHG that have yet to be developed. Most recently, on August 12, 2010, the EPA proposed two actions to govern the implementation of PSD permitting requirements for GHGs in states whose existing State Implementation Plans ("SIPs") do not accommodate the regulation of GHGs. First, the EPA has proposed to issue a "Finding of Substantial Inadequacy" and SIP Call to 13 such states. Second, the EPA has proposed to establish a Federal Implementation Plan in any state that does not revise its SIP to accommodate GHG permitting. Also, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. On April 12, 2010, the EPA proposed to expand this GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. If the proposed rule is finalized as proposed, reporting of GHG emissions from such facilities would be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.

          In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for our midstream services. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in reduced volumes available for us to gather, process and fractionate.

          Congress is currently considering two companions bills for the "Fracturing Responsibility and Awareness of Chemicals Act," or "FRAC Act." The bills would repeal an exemption in the federal Safe Drinking Water Act ("SWDA") for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of natural gas, and to a lesser extent, oil wells in shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. Sponsors of the FRAC Act have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The FRAC Act also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of the FRAC Act or any other federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells in shale formations and increase our producers' costs of compliance. This could significantly reduce the volumes that

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we gather, process and fractionate which could adversely impact our earnings, profitability and cash flows.

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 or changes in interstate pipeline gas quality specifications, we will be forced to limit or stop the flow of gas through our pipelines and processing systems. In addition, interruption of pipeline service upstream of our processing facilities would limit or stop flow 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. Any number of factors beyond our control could cause such interruptions or constraints on pipeline service, including necessary and scheduled maintenance, or unexpected damage to the pipeline. Because our revenues and net operating margins depend upon (1) the volumes of natural gas we process, gather and transmit, (2) the throughput of NGLs through our transportation, fractionation and storage facilities and (3) the volume of crude oil we gather and transport, any reduction of volumes could adversely affect our operations and cash flows and our ability to make payments on the notes.

Interruptions in operations at any of our facilities may adversely affect our operations and cash flows and our ability to make payments on the notes.

          Our operations depend 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 to transport crude oil to or from these facilities or pipelines for any reason, would adversely affect our operations and cash flows and our ability to make payments on the notes.

          Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:

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unscheduled turnarounds or catastrophic events at our physical plants;



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



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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.

Due to our lack of asset diversification, adverse developments in our gathering, processing, transportation, transmission, fractionation and storage businesses could reduce our operations and cash flows and our ability to make payments on the notes.

          We rely exclusively on the revenues generated from our gathering, processing, transportation, transmission, fractionation and storage businesses. An adverse development in one of these businesses would have a significantly greater impact on our operations and cash flows available for payments on the notes than if we maintained more diverse assets.

We may not be able to successfully execute our business plan and may not be able to grow our business, which could adversely affect our operations and cash flows and our ability to make payments on the notes.

          Our ability to successfully operate our business, generate sufficient cash to make payments on the notes, and to allow for growth, is subject to a number of risks and uncertainties. Similarly, we may not be able to successfully expand our business through acquiring or growing our assets, because of various factors, including economic and competitive factors beyond our control. If we are unable to grow our business, or execute on our business plan including increasing or maintaining distributions, the market price of the common units is likely to decline.

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

          Our industry is subject to numerous operating hazards and risks incidental to processing, transporting, fractionating and storing natural gas and NGLs and to transporting and storing crude oil. These include:

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



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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. Market conditions could cause certain insurance premiums and deductibles to become unavailable, or available only for reduced amounts of coverage. For example, insurance carriers now require 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 operations and cash flows and our ability to make payments on the notes.

Our business may suffer if any of our key senior executives or other key employees discontinues employment with us or if we are unable to recruit and retain highly skilled staff.

          Our future success depends to a large extent on the services of our key employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees, including accounting, business operations, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these employees could harm our business. Our equity based long-term incentive plans are a significant component of our strategy to retain key employees. Further, our ability to successfully integrate acquired companies or handle complexities related to managing joint ventures depends in part on our ability to retain key management and existing employees at the time of the acquisition or joint venture transaction.

A shortage of skilled labor may make it difficult for us to maintain labor productivity, and competitive costs could adversely affect our operations and cash flows and our ability to make payments on the notes.

          Our operations require skilled and experienced laborers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the midstream energy business has caused us to conduct certain operations without full staff, which decreases our productivity and increases our costs. This shortage of trained workers is the result of the previous generation's experienced workers reaching the age for retirement, combined with the difficulty of attracting new laborers to the midstream energy industry. Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations and cash flows and our ability to make payments on the notes.

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If we do not make acquisitions on economically acceptable terms, our future growth may be limited.

          Our ability to grow depends in part on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth will be limited.

If we are unable to timely and successfully integrate our future acquisitions, our future financial performance may suffer, and we may fail to realize all of the anticipated benefits of the transaction.

          Our future growth will depend in part on our ability to integrate our future acquisitions. We cannot guarantee that we will successfully integrate any acquisitions into our existing operations, or that we will achieve the desired profitability and anticipated results from such acquisitions. Failure to achieve such planned results could adversely affect our operations and cash flows and our ability to make payments on the notes.

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

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



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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 geographical 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 existing business concerns;



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the failure to realize expected synergies and cost savings;



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coordinating geographically disparate organizations, systems and facilities;



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integrating personnel from diverse business backgrounds and organizational cultures; and



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consolidating corporate and administrative functions.

          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 including those under the same stringent environmental laws and regulations relating to releases of pollutants into the environment and environmental protection as are applicable to our existing plants, pipelines and facilities. If so, our operation of these new assets could cause us to incur increased costs to address these liabilities or to attain or maintain compliance with such requirements. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and unitholders 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.

Terrorist attacks aimed at our facilities could adversely affect our business.

          Since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that energy assets, specifically the nation's pipeline infrastructure, may be future targets of terrorist organizations. These developments will subject our operations to increased risks. Any future terrorist attack that may target our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

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We have partial ownership interests in a number of joint venture legal entities, including Liberty Midstream, Markwest Pioneer, Wirth Gathering, and Centrahoma, which could adversely affect our ability to control certain decisions of these entities. In addition, we may be unable to control the amount of cash we will receive from the operation of these entities and where we do not have control, we could be required to contribute significant cash to fund our share of their operations, which could adversely affect our ability to make payments on the notes.

          Our inability, or limited ability, to control certain aspects of management of joint venture legal entities that we have a partial ownership interest in may mean that we will not receive the amount of cash we expect to be distributed to us. In addition, for entities where we have a non-controlling ownership interest such as in Centrahoma we will be unable to control ongoing operational decisions, including the incurrence of capital expenditures that we may be required to fund. Specifically,

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We may have limited ability to influence certain management decisions with respect to these entities and their subsidiaries, including decisions with respect to incurrence of expenses and distributions to us;



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These entities may establish reserves for working capital, capital projects, environmental matters and legal proceedings which would otherwise reduce cash available for distribution to us;



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These entities may incur additional indebtedness, and principal and interest made on such indebtedness may reduce cash otherwise available for distribution to us; and



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These entities may require us to make additional capital contributions to fund working capital and capital expenditures, our funding of which could reduce the amount of cash otherwise available for distribution.

          All of these things could significantly and adversely impact our ability to make payments on the notes.

Certain changes in accounting and/or financial reporting standards issued by the FASB, the SEC or other standard-setting bodies could have a material adverse impact on our financial position or results of operations.

          We are subject to the application of GAAP, which periodically is revised and/or expanded. As such, we periodically are required to adopt new or revised accounting and/or financial reporting standards issued by recognized accounting standard setters or regulators, including the FASB and the SEC. It is possible that future requirements, including the recently proposed implementation of International Financial Reporting Standards ("IFRS"), could change our current application of GAAP, resulting in a material adverse impact on our financial position or results of operations.

The potential requirement to convert our financial statements from being prepared in conformity with GAAP to IFRS may strain our resources and increase our annual expenses.

          As a public entity, the SEC may require in the future that we report our financial results under IFRS instead of GAAP. IFRS is a set of accounting principles that has been gaining acceptance on a worldwide basis. These standards are published by the London-based International Accounting Standards Board and are more focused on objectives and principles and less reliant on detailed rules than GAAP. Today, there remain significant and material differences in several key areas between GAAP and IFRS which would affect us. Additionally, GAAP provides specific guidance in classes of accounting transactions for which equivalent guidance in IFRS does not exist. The adoption of IFRS is highly complex and would have an impact on many aspects and operations of us, including but not limited to financial accounting and reporting systems, internal controls, taxes, borrowing covenants and cash management. It is expected that a significant amount of time, internal and external resources and expenses over a multi-year period would be required for this conversion.

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Risks Related to the Notes

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

          We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the partnership interests, stock and the other equity interests in our subsidiaries. As a result, our ability to make required payments on the notes 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, our Amended and Restated Credit Agreement and applicable state business organization laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of the notes, or to repurchase the notes upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of the notes. We cannot assure you that we would be able to refinance the notes or obtain the funds to pay principal or interest on the notes.

Payment of principal and interest on the notes will be effectively subordinated to our senior secured debt to the extent of the value of the assets securing that debt and structurally subordinated to the liabilities of any of our subsidiaries that do not guarantee the notes.

          The notes are effectively subordinated to claims of our secured creditors and the subsidiary guarantees are effectively subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. As of October 15, 2010, we and our subsidiary guarantors had $27.6 million in aggregate principal amount of secured indebtedness outstanding (excluding $27.4 million of outstanding letters of credit). Holders of our secured obligations, including obligations under our Amended and Restated Credit Agreement, will have claims that are prior to claims of the holders of the notes with respect to the assets securing those obligations. In the event of a liquidation, dissolution, reorganization, bankruptcy or any similar proceeding, our assets and those of our subsidiaries will be available to pay obligations on the notes and the guarantees only after holders of our senior secured debt have been paid the value of the assets securing such debt. Although all of our wholly-owned subsidiaries, other than MarkWest Energy Finance Corporation, the co-issuer of the notes, will initially guarantee the notes, in the future, under certain circumstances, the guarantees are subject to release and we may have subsidiaries that are not guarantors. In that case, the notes would be structurally subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the liquidation, dissolution, reorganization, bankruptcy or similar proceeding of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the notes. Accordingly, there may not be sufficient funds remaining to pay amounts due on all or any of the notes.

We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.

          Our ability to make payments on and to refinance our indebtedness, including the notes, and to fund planned capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.

          We cannot assure you that we will generate sufficient cash flow from operations or that future borrowings will be available to us under our Amended and Restated Credit Agreement or otherwise in an amount sufficient to enable us to pay our indebtedness, including these notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the notes, on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including outstanding indebtedness pursuant to our Amended and Restated Credit Agreement and the notes, on commercially reasonable terms or at all.

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We distribute all of our available cash to our unitholders and we are not required to accumulate cash for the purpose of meeting our future obligations to our noteholders, which may limit the cash available to service the notes.

          Subject to the limitations on restricted payments contained in the indenture governing the notes and in our Amended and Restated Credit Agreement and other indebtedness, we distribute all of our "available cash" each quarter to our limited partners and our general partner. "Available cash" is defined in our partnership agreement, and it generally means, for each fiscal quarter:

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all cash and cash equivalents on hand at the end of the quarter (excluding cash at MarkWest Hydrocarbon);



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less the amount of cash that our general partner determines in its reasonable discretion is necessary or appropriate to:



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provide for the proper conduct of our business;



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comply with applicable law, any of our debt instruments, or other agreements; or



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provide funds for distributions to unitholders for any one or more of the next four quarters;



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plus all cash and cash equivalents on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our Credit Facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

          As a result, we do not expect to accumulate significant amounts of cash. Depending on the timing and amount of our cash distributions, these distributions could significantly reduce the cash available to us in subsequent periods to make payments on the notes.

We may not be able to fund a change of control offer.

          In the event of a change of control, we will be required, subject to certain conditions, to offer to purchase all outstanding notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest thereon to the date of purchase. If a change of control were to occur today, we would not have sufficient funds available to purchase all of the outstanding notes were they to be tendered in response to an offer made as a result of a change of control. We cannot assure you that we will have sufficient funds available or that we will be permitted by our other debt instruments to fulfill these obligations upon a change of control in the future. Furthermore, certain change of control events would constitute an event of default under our Credit Facility. Please read "Description of Notes — Repurchase at the Option of Holders — Change of Control."

Many of the covenants contained in the indenture will terminate if the notes are rated investment grade by both Standard & Poor's and Moody's and no default has occurred and is continuing.

          Many of the covenants in the indenture governing the notes will terminate if the notes are rated investment grade by both Standard & Poor's and Moody's provided at such time no default or event of default has occurred and is continuing. The covenants will restrict, among other things, our ability to pay dividends, incur debt, and to enter into certain other transactions. There can be no assurance that the notes will ever be rated investment grade. However, termination of these covenants would allow us to engage in certain transactions that would not be permitted while these covenants were in force, and the effects of any such transactions will be permitted to remain in place even if the notes are subsequently downgraded below investment grade. Please read "Description of Notes — Covenant Termination."

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The subsidiary guarantees could be deemed fraudulent conveyances under certain circumstances, and a court may try to subordinate or void the subsidiary guarantees.

          Under the federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, a subsidiary guarantee could be voided, or claims in respect of a subsidiary guarantee could be subordinated to all other debts of that subsidiary guarantor if, among other things, the subsidiary guarantor, at the time it incurred the indebtedness evidenced by its subsidiary guarantee:

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received less than reasonably equivalent value or fair consideration for the incurrence of such subsidiary guarantee; and



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was insolvent or rendered insolvent by reason of such incurrence;



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was engaged in a business or transaction for which the subsidiary guarantor's remaining assets constituted unreasonably small capital; or



•

intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.

          In addition, any payment by that subsidiary guarantor pursuant to its subsidiary guarantee could be voided and required to be returned to the subsidiary guarantor, or to a fund for the benefit of the creditors of the subsidiary guarantor. The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a subsidiary guarantor would be considered insolvent if:

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the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;



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the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability, including contingent liabilities, on its existing debts, as they become absolute and mature; or



•

it could not pay its debts as they become due.