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TABLE OF CONTENTS
Appendix B

Filed Pursuant to Rule 424(b)(3)
Commission File No. 333-133439

PROSPECTUS

3,820,097 Common Units

MarkWest Energy Partners, L.P.

Representing Limited Partner Interests

This prospectus has been supplemented to include the information contained in our quarterly report on Form 10-Q for the three months ended June 30, 2006, which is included herein as Appendix B. This prospectus replaces our prospectus dated July 18, 2006 in its entirety. Up to 3,820,097 of our common units may be offered from time to time by the selling unitholders named in this prospectus. All of the common units were originally sold to the selling unitholders in private placements exempt from the registration requirements of the Securities Act of 1933, as amended. We are registering the offer and sale of the common units to satisfy registration rights that we have granted to the selling unitholders. The selling unitholders may sell the common units at various times and in various types of transactions, including sales in the open market, sales in negotiated transactions and sales by a combination of methods. We are not selling any common units under this prospectus and will not receive any proceeds from the sale of common units by the selling unitholders.

Our common units are traded on the American Stock Exchange under the symbol "MWE." On July 17, 2006, the last reported sale price of our common units on the American Stock Exchange was $43.03 per common unit.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 9 of this prospectus.

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

The date of this prospectus is August 4, 2006

TABLE OF CONTENTS

PROSPECTUS SUMMARY
	MARKWEST ENERGY PARTNERS, L.P.
RISK FACTORS
	Risks Inherent in Our Business
	Risks Related to Our Partnership Structure
	Tax Risks to Common Unitholders
USE OF PROCEEDS
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
CASH DISTRIBUTION POLICY
	Distributions of Available Cash
	Operating Surplus and Capital Surplus
	Subordination Period
	Distributions of Available Cash from Operating Surplus During the Subordination Period
	Distributions of Available Cash from Operating Surplus After the Subordination Period
	Incentive Distribution Rights
	Target Amount of Quarterly Distribution
	Distributions from Capital Surplus
	Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
	Distributions of Cash upon Liquidation
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
SELECTED HISTORICAL FINANCIAL INFORMATION
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SELLING UNITHOLDERS
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
THE PARTNERSHIP AGREEMENT
	Organization and Duration
	Purpose
	Power of Attorney
	Capital Contributions
	Limited Liability
	Voting Rights
	Issuance of Additional Securities
	Amendment of the Partnership Agreement
	Action Relating to the Operating Company
	Merger, Sale or Other Disposition of Assets
	Termination and Dissolution
	Liquidation and Distribution of Proceeds
	Withdrawal or Removal of our General Partner
	Transfer of General Partner Interests
	Transfer of Ownership Interests in General Partner
	Transfer of Incentive Distribution Rights
	Change of Management Provisions
	Limited Call Right
	Meetings; Voting
	Status as Limited Partner or Assignee
	Non-citizen Assignees; Redemption
	Indemnification
	Books and Reports
	Right to Inspect our Books and Records
	Registration Rights

MATERIAL TAX CONSEQUENCES
	Partnership Status
	Limited Partner Status
	Tax Consequences of Unit Ownership
	Tax Treatment of Operations
	Disposition of Common Units
	Uniformity of Units
	Tax-Exempt Organizations and Other Investors
	Administrative Matters
	State, Local and Other Tax Considerations
INVESTMENT IN MARKWEST ENERGY PARTNERS BY EMPLOYEE BENEFIT PLANS
DESCRIPTION OF COMMON UNITS
	The Units
	Transfer Agent and Registrar
	Transfer of Common Units
PLAN OF DISTRIBUTION
VALIDITY OF THE COMMON UNITS
EXPERTS
WHERE YOU CAN FIND MORE INFORMATION
FORWARD-LOOKING STATEMENTS
APPENDIX A: GLOSSARY OF TERMS
APPENDIX B: QUARTERLY REPORT ON FORM 10-Q

You should rely only on the information contained or incorporated by reference in this prospectus. We have not authorized anyone to provide you with information that is different. This prospectus may only be used where it is legal to sell our common units. You should assume that the information contained or incorporated by reference in this prospectus is accurate as of the date on the front of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission (the "SEC") for a continuous offering. Under this prospectus, the selling unitholders may, from time to time, sell the shares of our common units described in this prospectus in one or more offerings. This prospectus may be supplemented from time to time to add, update or change information in this prospectus. Any statement contained in this prospectus will be deemed to be modified or superseded for the purposes of this prospectus to the extent that a statement contained in a prospectus supplement modifies such statement. Any statement so modified will be deemed to constitute a part of this prospectus only as so modified, and any statement so modified will be deemed to constitute a part of this prospectus.

Additional information, including our financial statements for the year ended December 31, 2005 and the three months ended March 31, 2006 and the notes related thereto, is incorporated by reference to our reports filed with the SEC. In addition, the registration statement containing this prospectus, including the exhibits to the registration statement, provides additional information about us, the selling unitholders and the common units offered under this prospectus. The registration statement, including the exhibits, and our reports filed with the SEC can be read on the SEC website or at the SEC office described under the heading "Where You Can Find More Information."

MarkWest Energy Partners, L.P., MarkWest Hydrocarbon, Inc., our logo and other trademarks mentioned in this prospectus are the property of their respective owners.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere or incorporated by reference in this prospectus. You should read the entire prospectus and any information incorporated herein by reference carefully, including the historical financial statements and notes to those financial statements incorporated by reference from our Annual Report on Form 10-K and "Unaudited Pro Forma Financial Statements" beginning on page 35 of this prospectus. You should read "Risk Factors" beginning on page 9 for more information about important factors that you should consider before buying common units. We include a glossary of some of the terms used in this prospectus as Appendix A to this prospectus.

Unless the context otherwise requires, references in this prospectus to "MarkWest Energy," "the Partnership," "we," "us," "our" or "ours" refer to MarkWest Energy Partners, L.P., together with its consolidated subsidiaries. When the context requires, we refer to these entities separately. References in this prospectus to "MarkWest Hydrocarbon" refer to MarkWest Hydrocarbon, Inc. and its direct and indirect consolidated subsidiaries.

MARKWEST ENERGY PARTNERS, L.P.

Overview

We are a publicly traded Delaware limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation and storage of NGLs; and the gathering and transportation of crude oil. We are the largest processor of natural gas in the Appalachia region. We also have a large natural gas gathering and transmission business in the southwestern United States, built primarily through acquisitions and investments: Pinnacle Natural Gas, the Lubbock transmission pipeline and the Foss Lake gathering system, all in 2003; the Carthage gathering system in East Texas in July 2004; and in 2005, the Javelina Processing Facilities in Corpus Christi, Texas, and a non-controlling 50% interest in Starfish Pipeline Company, LLC in southern Louisiana and the Gulf of Mexico.

We generate revenues by providing gathering, processing, transportation, fractionation, and storage services. We believe that the largely fee-based nature of our business and the relatively long-term nature of our contracts provide a relatively stable base of cash flows. As a publicly traded partnership, we have access to, and regularly utilize, both equity and debt capital markets as a source of financing, as well as that provided by our credit facility. Our limited partnership structure also provides tax advantages to our unitholders.

Underwritten Offering and Senior Notes Offering

We recently closed our underwritten public offering of 3,300,000 common units at a public offering price of $39.75 per unit. On July 6, 2006, we also closed our concurrent private placement of $200.0 million in aggregate principal amount of senior notes only to qualified institutional buyers The net proceeds from the offering of 3,300,000 common units was approximately $127.3 million, including a capital contribution of approximately $2.7 million from our general partner to maintain its 2% general partner interest in our partnership and after deducting underwriting discounts and expenses. The net proceeds from the private placement of senior notes was approximately $191.2 million, after deducting the initial purchasers' discounts and our estimated expenses. We intend to use the proceeds of the underwritten offering and the private placement to repay borrowings outstanding under our credit facility incurred in connection with our recent acquisitions.

Material Weaknesses Reported for the Years Ended December 31, 2005, 2004 and 2003

We have discovered deficiencies, including material weaknesses, in our internal controls over financial reporting as of December 31, 2005, 2004 and 2003. In particular, we identified, and the audit

report on management's assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting of our independent registered public accounting firms confirmed the presence of, the material weaknesses discussed below.

Year Ended December 31, 2003

PricewaterhouseCoopers LLC ("PwC"), our independent public accounting firm at the time, identified certain deficiencies in our internal accounting controls as of December 31, 2003. The identified deficiencies included the following:

•: a possible insufficiency in the personnel resources available to adequately maintain our financial reporting obligations as a public company;
•: inadequate implementation of uniform controls over certain acquired entities and operations;
•: inadequate control over classification of certain fixed asset balances and processes for accrual of certain accounts payable; and
•: potential need for separation of certain duties between payroll and other accounting personnel.

The deficiencies identified by PwC, considered collectively, may have constituted a material weakness in our internal controls pursuant to standards established by the American Institute of Certified Public Accountants. PwC also concluded that these deficiencies required them to increase the scope of its audit procedures in order for it to issue an unqualified report on our financial statements.

We believe that the deficiencies described above developed primarily due to an insufficient focus on internal controls and accounting activity during a period of significant growth and acquisition activity by the Partnership. During 2003 and 2004, we made six acquisitions and more than quadrupled in terms of revenue. As a result, a significant amount of management time and effort was spent on integration of these assets from an operational perspective. The vast majority of these assets had not been owned by publicly-held companies and as a result, existing controls and procedures were not adequate from a public company reporting perspective. As a result, we were not able to remediate these deficiencies during the year ended December 31, 2004.

Year Ended December 31, 2004

In connection with management's assessment of internal control over financial reporting for the year ended December 31, 2004, management identified and KPMG, our independent registered public accounting firm at that time confirmed the following material weaknesses in our internal control over financial reporting:

•: Ineffective control environment;
•: Insufficient technical accounting expertise, inadequate policies and procedures related to accounting matters, and inadequate management review in the financial reporting process;
•: Inadequate personnel, processes and controls at our Southwest Business Unit; and
•: Inadequately designed controls and procedures over property plant and equipment.

Ineffective control environment. Our control environment did not sufficiently promote effective internal control over financial reporting throughout our management structure, and this material weakness was a contributing factor in the development of other material weaknesses described below. Principal contributing factors included the lack of adequate personnel with sufficient expertise to perform accounting functions necessary to ensure preparation of financial statements in accordance with generally accepted accounting principles, and a lack of adequate policies and procedures to enable the timely preparation of reliable financial statements, as described more fully below. We believe that

this material weakness developed as a result of our rapid expansion in 2003 and 2004. The steps we have taken to remediate this material weakness are described in detail below.

Insufficient technical accounting expertise, inadequate policies and procedures related to accounting matters, and inadequate management review in the financial reporting process. We did not have sufficient policies and procedures in place or technical accounting expertise to address complex accounting matters. In addition, we did not maintain policies and procedures to ensure adequate management review of information supporting our financial statements. Specifically, we identified deficiencies in the following areas relating to the preparation of our financial statements:

•: We did not have a sufficient number of personnel with adequate technical expertise to effectively carry out our policies and procedures related to the review of technical accounting matters.
•: We did not maintain policies and procedures over the selection and application of appropriate accounting policies, or the assessment of the appropriate accounting treatment for non-routine transactions.
•: We did not maintain policies and procedures that provide for timely and effective management review of information supporting our financial statements prior to their issuance.

These material weaknesses in internal control over financial reporting resulted in the material misstatement of compensation expense in 2002, 2003 and 2004. As a result of this material misstatement, we restated our financial statements for 2002, 2003 and the first three quarters of each of 2003 and 2004. These material weaknesses in internal control over financial reporting also resulted in material misstatements of (i) interest capitalized on major construction projects in process; (ii) asset retirement obligations relating to assets acquired in the third quarter of 2004; (iii) accrued liabilities and lease expense related to costs associated with our ceasing to use a portion of our leased office facility in Houston; and (iv) accrued liabilities and facility expenses as a result of an improper accrual for repairs to a pipeline we lease. As a result of the material misstatements described in (i) and (ii), we restated our financial statements for the third quarter of 2004. These material misstatements and the material misstatements described in (iii) and (iv) were corrected prior to issuance of our financial statements for the year 2004.

Inadequate personnel, processes and controls at our Southwest Business Unit. We believe these material weaknesses developed as a result of the growth explained above and our lack of resources to commit to focusing on an improved control environment and rapidly changing accounting rules and regulations and interpretations to existing rules. In addition, our staff was not adequately trained in the requirements of Section 404 of the Sarbanes-Oxley Act. Furthermore, at that time, our resources were focused on the restatement of financial reports rather than the updating of policies and procedures. The steps we have taken to remediate these material weaknesses are described in detail below.

We did not have adequate personnel, policies, and procedures at our Southwest Business Unit to enable timely preparation of reliable financial information for that business unit. Specifically, we identified the following internal control deficiencies at our Southwest Business Unit:

•: We did not employ personnel with sufficient expertise to perform accounting functions necessary to ensure preparation of financial information in accordance with generally accepted accounting principles.
•: We did not maintain policies and procedures to ensure that account analyses and reconciliations of supporting account details to the general ledger were accurately prepared and reviewed timely, and that any reconciling items were investigated and resolved on a timely basis.
•: We did not maintain policies and procedures to ensure that journal entries were accurately prepared and properly reviewed prior to being recorded in the general ledger.

•: We did not maintain policies and procedures to ensure that accruals for revenue and cost of purchased product were recorded accurately and in the appropriate financial reporting period.

These material weaknesses in internal control over financial reporting resulted in misstatements of cash; receivables; other current assets; property, plant and equipment; accumulated depreciation; intangible assets; accounts payable; accrued liabilities; other liabilities; and partners' capital. These material weaknesses also resulted in misstatements of revenues; purchased product costs; facility expenses; selling, general and administrative expenses; depreciation; amortization of intangible assets; accretion of asset retirement obligations; and interest expense. As a result, we restated our financial statements for the first three quarters of 2004. These misstatements, which were considered material in the aggregate, were corrected prior to issuance of our audited financial statements for the year 2004.

We acquired the privately-held Western Oklahoma assets from American Central in December of 2003. Its accounting functions were transitioned to Houston in early 2004. We acquired the East Texas assets from American Central in July 2004 and transitioned the accounting responsibilities for all of our Southwest Business Unit activities to Tulsa in October 2004. This transition, coupled with the lack of adequate experienced accounting personnel in Tulsa, significantly impacted our ability to timely train our personnel, implement appropriate process and procedures, test and remediate before the end of the reporting year.

The steps we have taken to remediate these material weaknesses are described in detail below. In addition, we are in the process of transitioning the accounting functions related to our Southwest Business Unit from Texas to to Denver. We expect to complete this transition by the end of 2006

Inadequately designed controls and procedures over property plant and equipment. We did not have adequately designed policies and procedures to ensure that costs associated with activities relating to our facilities were properly accounted for as capital expenditures or maintenance expense. This material weakness in internal control over financial reporting resulted in a material misstatement of property, plant and equipment, and facilities expenses. As a result of this material misstatement, we restated our financial statements for the second and third quarters of 2004 to expense costs that had previously been capitalized in error.

We believe that this material weakness developed as a result of our lack of formal policy for an annual inventory of fixed assets. Many assets were acquired in as-built condition with limited documentation on a component-by-component basis. This made it difficult to evaluate on an asset-by-asset basis. These assets were not adequately segregated at the time of our initial public offering and had not been re-evaluated since the time of our initial public offering but had experienced large growth in number over time.

These issues were identified late in 2004 and early in 2005. At that time, our resources were focused on completing the outstanding filings and the associated restatements, and we did not have additional resources to focus on standardizing and implementing new policies and procedures. The steps we have taken to remediate this material weakness are described in detail below.

Remediation of 2004 Material Weaknesses. In response to the material weaknesses identified by our management, with oversight from our general partner's audit committee, we dedicated significant resources to improve our control environment and to remedy the identified material weaknesses in the third and fourth quarters of 2005. These efforts focused on (i) expanding our organizational capabilities through the addition of employees with appropriate skills and abilities to improve our control environment and (ii) implementing process changes to strengthen our internal control design and monitoring activities.

From an organizational capabilities perspective, we made the following improvements to our control environment:

•: In November 2005, we hired a new chief accounting officer with significant public company audit, accounting and financial reporting experience and technical expertise. The chief accounting officer now reports directly to our chief executive officer.
•: In the third and fourth quarters of 2005, we hired additional external reporting, tax and accounting staff to supplement our existing technical accounting resources and mitigate segregation of duties deficiencies.
•: In July 2005, we hired a Vice President of Risk and Compliance with a strong public company risk management, compliance and audit background. This individual is responsible for coordinating our internal audit and internal control compliance efforts.
•: In the third and fourth quarters of 2005, we established an internal audit function and staffed it through an outsourcing and technical consultation arrangement with a professional accounting and consulting firm.

In addition, we implemented changes to our processes to improve disclosure controls and procedures and to improve our internal control over financial reporting. Among the changes we made during the third and fourth quarters of 2005 are the following:

•: We formalized the monthly account reconciliation process for all balance sheet accounts and have implemented a formal review of reconciliations by our business unit accounting management.
•: We established a compliance office focused on control deficiency identification and remediation, i.e., purchasing controls, revenue recognition controls and application and spreadsheet change controls that performs ongoing internal control evaluation and assessment and works actively with the process owners in developing appropriate remediation of control deficiencies.
•: We conducted an entity-level risk assessment, established an internal audit plan and began to execute that internal audit plan. Results are reported directly to our general partner's audit committee.
•: We enhanced entity level controls through the implementation of significant new controls.
•: We strengthened our disclosure review committee charter to solicit and review input from management personnel throughout the Partnership regarding possible instances of fraud or significant events requiring disclosure.
•: We implemented a technical accounting issues forum to address non-routine transactions and the use of critical estimates and judgment.

Year Ended December 31, 2005

Internal control environment. The steps taken to remediate the material weaknesses described above were not completed until the latter part of 2005 because our resources had been directed towards the restatements of our financial statements. As a result, the identified internal control weaknesses persisted throughout 2005. While we believe we have substantially improved our organizational capabilities, the full impact of the changes had not been realized by December 31, 2005. In connection with management's assessment of the effectiveness of internal control over financial reporting for the year ended December 31, 2005, we identified and Deloitte & Touche LLP confirmed, as of December 31, 2005, the presence of an ongoing material weakness related to our internal control environment. Specifically, our control environment did not sufficiently promote effective internal

control over financial reporting through the management structure to prevent a material misstatement, as was evidenced by deficiencies or significant deficiencies in the following areas:

•: Segregation of duties within certain key processes was inadequate to support management's assertions with respect to the accuracy and completeness of financial records.
•: Entity-level controls, including the anti-fraud program and controls necessary to address risk assessment, information and communication.
•: Application controls over financially significant applications with respect to change management and information systems operations.
•: Fixed assets controls, including instances of inappropriate authorization of invoices and improper reconciliation procedures.
•: Financial reporting controls related to the closing process, including control over non-routine transactions, unusual journal entries and the use of estimates and judgment.
•: Controls over expenditures, including instances of inappropriate authorization of invoices and the inability to independently validate the accuracy and validity of amounts recorded.
•: Spreadsheet controls related to change management within key financial spreadsheets.

Because the Javelina Entities were not acquired until November 2005, management did not include the internal control processes of the Javelina entities in its assessment of internal controls as of December 31, 2005. Management will include all aspects of the internal controls of the Javelina entities in its 2006 assessment.

In order to remediate this material weakness, we are in the process of fully implementing and standardizing the processes and procedures described above under "—Remediation of 2004 Material Weaknesses". In addition, we are enhancing employee awareness of our Code of Conduct, ethics and anti-fraud policies, including a revised training program to be delivered to all employees in 2006. This includes heightened awareness of the ethics hotline availability and access options. We are also conducting a detailed review and re-documentation of all of our internal control processes and will undertake significant internal control design changes to ensure that all internal control objectives are met.

We believe that the changes described above and the actions taken to remediate the material weaknesses identified as of December 31, 2004 have improved and will continue to improve our internal control over financial reporting, as well as our disclosure controls and procedures. However, given the breadth of areas affected, it has taken and will continue to take time to remediate all of our identified material weaknesses. Our management, with oversight of our general partner's audit committee, will continue to take steps to remedy all known material weaknesses as expeditiously as possible and enhance the overall design and capability of our internal control environment.

Risk Management and Accounting for Derivative Financial Instruments. In connection with management's assessment of the effectiveness of internal control over financial reporting for the year ended December 31, 2005, we identified and Deloitte & Touche LLP confirmed, as of December 31, 2005, the presence of an additional material weakness related to our risk management and accounting for derivative financial instruments. We did not have adequate internal controls and processes in place to support our management's assertions with respect to the completeness, accuracy and validity of commodity transactions. The design of internal controls over commodity transactions did not support the independent validation of data or control and review of transacting activity. In particular, personnel responsible for executing and entering transactions into commodity accounting systems also had duties that were not compatible with transaction execution and entry.

During 2004, our lack of internal controls around hedging activities and commodities trading was identified as a significant deficiency. In 2005, as the internal controls still lacked the appropriate coverage, this area was judged to be a material weakness. As well in 2005, the complexity of our risk management and commodity transactions increased. In the years prior to 2005, we did not engage in an active hedging program to a level that would be considered material. During 2005, our management recognized that its risk profile had changed as a result of the Javelina acquisition and the imminent January 1, 2006 start up of the Carthage processing plant. As a result, we began to expand the scope and scale of our hedging transactions and derivative activities. Prior to such new activities, we did not have in place or have the full opportunity to design and implement adequate controls, as this part of the business was expanding.

In order to remediate this material weakness, we added the following personnel to our management team in July 2005 and January 2006, respectively:

•: Vice President of Risk and Compliance, to oversee and ensure improvements in our commodity transaction verification and monitoring capabilities; and
•: Director of Risk Management and staff to establish appropriate verification and monitoring activities associated with our commodity transactions.

While we believe we have substantially improved our organizational capabilities, the full impact of the changes had not been realized by December 31, 2005. We will continue to evaluate our resources and remain committed to adding the necessary resources as needs are identified.

At the end of the first quarter of 2006, we also segregated our front-office, mid-office, and back-office processes related to our financial commodity transactions and a portion of our physical trading to ensure that proper segregation of duties exists and that control procedures are carried out by the appropriate groups. We are focused on attaining proper segregation for our remaining physical transactions over the coming months. We are enhancing our risk management policies and procedures related to the review and approval of material purchase or sale contracts that may meet the definition of derivatives. Additionally, we are enhancing our financial analysis around commodity transactions and our reporting to executive management and the board of directors. Finally, we moved the responsibility for credit risk management to the mid-office in the second quarter of 2006.

Recent Developments

Notice of Probable Violation and Proposed Civil Penalty

On June 20, 2006, we and Equitable Production Company, the owner of a pipeline that is leased by one of our subsidiaries to transport NGLs from our Maytown gas processing plant to our Siloam fractionator, received from the Department of Transportation ("DOT") a "Notice of Probable Violation and Proposed Civil Penalty" in the amount of $1,070,000. This notice relates to a leak incident that occurred on this pipeline on November 8, 2004. For further discussion of this incident, please see "Item 1. Business—Pipeline Safety Regulations" in our Annual Report on Form 10-K for the year ended December 31, 2005, as amended. We must respond to the DOT regarding this notice within 30 days and may request a hearing to contest these allegations and proposed penalty. We are currently evaluating the manner in which we will respond to this notice.

Recent Hedging Activity

As part of our ongoing comprehensive risk management plan designed to manage risk and future cash flows, we entered into the following derivative transactions during the second quarter of 2006:

Costless collars:	Period	Floor		Cap
Crude Oil — 78 Bbl/d	2006	$	67.50	$	77.30
Crude Oil — 155 Bbl/d	2007	$	67.50	$	78.55
Crude Oil — 250 Bbl/d	2007	$	67.50	$	79.15
Crude Oil — 200 Bbl/d	2007	$	70.00	$	75.95
Natural Gas — 400 Mmbtu/d	2007	$	8.25	$	10.03
Natural Gas — 1,500 Mmbtu/d	Apr - Dec 2007	$	7.25	$	10.25
Natural Gas — 1,500 Mmbtu/d	Jan - Mar 2008	$	8.00	$	11.29

Swaps:		Period		Fixed price
Crude Oil — 140 Bbl/d		2007		$	74.10
Propane — 5,000 Gal/d		Jul - Dec 2006		$	1.08

The following table sets forth our expected throughput volumes of each commodity to which we are price sensitive, along with the percentage of those volumes we have hedged for the periods described:

			Amount Hedged(1)
Product		Expected Volumes(1)	Amount Hedged(1)
Product	Units	Expected Volumes(1)	2006	%		2007	%
Natural Gas	MMBtu/day	3,500	1,575	45	%	1,900	54	%
Ethane	Bbl/day	3,450	545	16	%	—	0	%
NGLs	Bbl/day	3,600	2,470	69	%	995	28	%
Ethylene	Lbs/day	105,000	—	0	%	—	0	%
Propylene	Bbl/day	200	—	0	%	—	0	%

(1): Excludes keep-whole volumes

For a description of our derivative transactions entered into prior to March 31, 2006, as well as a discussion of our commodity risk management plan, please read "Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk and Our Commodity Risk Management Policy" in our Annual Report on Form 10-K for the year ended December 31, 2005, as amended, which is incorporated herein by reference.

Executive Office

Our principal executive offices are located at 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112, and our phone number is (303) 290-8700. We expect to relocate our principal executive offices to 1515 Arapahoe St., Tower II, Suite 700, Denver, Colorado 80202 in July 2006. We maintain a website at http://www.markwest.com. Except for information specifically incorporated by reference into this prospectus that may be accessed from our website, the information on our website is not part of this prospectus, and you should rely only on information contained or incorporated by reference in this prospectus when making a decision as to whether or not to invest in our common units.

RISK FACTORS

You should carefully consider each of the risks described below, together with all of the other information contained or incorporated by reference in this prospectus, before deciding to invest in shares of our common stock. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected and you may lose all or part of your investment.

Risks Inherent in Our Business

We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's fees and expenses to enable us to pay distributions at the current level.

We may not have sufficient available cash from operating surplus each quarter to pay the minimum quarterly distribution. The amount of cash we can distribute on our units depends principally on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•: the fees we charge and the margins we realize for our services and sales;
•: the prices of, level of production of, and demand for natural gas and NGLs;
•: the volumes of natural gas we gather, process and transport;
•: the level of our operating costs, including reimbursement of fees and expenses of our general partner; and
•: prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

•: our debt service requirements;
•: fluctuations in our working capital needs;
•: our ability to borrow funds and access capital markets;
•: restrictions contained in our debt agreements;
•: the level of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;
•: the cost of acquisitions, if any; and
•: the amount of cash reserves established by our general partner.

You should be aware that the amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

If we do not make acquisitions on economically acceptable terms, our future growth will 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 and ability to increase distributions will be limited.

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

Our future growth will depend in part on our ability to integrate our recent acquisitions. We recently completed the Starfish and Javelina acquisitions, which geographically expanded our operations into offshore and onshore Gulf of Mexico operations. We cannot guarantee that we will successfully integrate these, or any other, 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 financial condition and results of operations.

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

•: operating a significantly larger combined organization and integrating additional midstream operations into our existing operations;
•: 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;
•: the loss of customers or key employees from the acquired businesses;
•: the diversion of management's attention from other existing business concerns;
•: the failure to realize expected synergies and cost savings;
•: coordinating geographically disparate organizations, systems and facilities;
•: integrating personnel from diverse business backgrounds and organizational cultures; and
•: 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 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 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.

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

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

One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new gathering, processing and treating facilities. The construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital, which may exceed our expectations, and involves numerous regulatory,

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

Our 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. As of June 30, 2006, after giving effect for our public offering of common units and our private placement of senior notes and the application of the net proceeds of such offerings, including the contribution from our general partner to maintain its 2% general partner interest, we had $491.4 million in total debt outstanding, and our debt-to-total-capitalization ratio was 53.6%. Subject to the restrictions governing our indebtedness and other financial obligations, and the indenture 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 a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. Our existing 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 the credit facility are secured by substantially

all of our assets and guaranteed by us and all of our subsidiaries, other than our operating company, which is the borrower under the credit facility. Please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" in our Annual Report on Form 10-K for the year ended December 31, 2005, as amended. 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.

A significant decrease in natural gas production in our areas of operation would reduce our ability to make distributions to our unitholders.

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. 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. Currently, natural gas prices are high in relation to historical prices. For example, the rolling 12-month average NYMEX daily settlement price of natural gas has increased from $5.89 per MMBtu as of December 30, 2004 to $9.21 per MMBtu as of March 31, 2006. If the high price for natural gas were to decline, the level of drilling activity may decrease. A sustained declined in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering and pipeline transportation systems and our natural gas treatment and processing plants, which would lead to reduced utilization of these assets.

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, financial condition and ability to make cash distributions to you.

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 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 of similar magnitude.

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

MarkWest Hydrocarbon accounts for a significant portion of our revenues and net operating margin. These revenues and margins are generated by the volumes of natural gas contractually committed to MarkWest Hydrocarbon by certain producers in the Appalachian region, as well as the fees generated from processing, transportation, fractionation and storage services provided to MarkWest Hydrocarbon. We expect to derive a significant portion of our revenues and net operating margin from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future. Any default or nonperformance by MarkWest Hydrocarbon could significantly reduce our revenues and cash flows. Thus, any factor or event adversely affecting MarkWest Hydrocarbon's business, creditworthiness or its ability to perform under its contracts with us, or its other contracts related to our business, could also adversely affect us.

The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation and storage agreements may not escalate sufficiently to cover increases in costs. 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, storms, floods, acts of God, explosions, mechanical or physical failures of equipment or 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 distributions to our unitholders.

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 distributions to our unitholders. 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, 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 "Business—Industry Overview" incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2005, as amended.

Our profitability is 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 extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price of natural gas for the prompt month contract in 2005 ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu. In the first three months of 2006, the same index ranged from a high of $11.23 per MMBtu to a low of $6.55 per MMBtu. A composite of the weighted monthly average NGLs price at our Appalachian facilities based on our average NGLs composition in 2005 ranged from a high of approximately $1.25 per gallon to a low of $0.83 per gallon. In the first three months of 2006, the same composite ranged from approximately $1.18 per gallon to approximately $1.02 per gallon. The markets and prices for natural gas and NGLs depend 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;
•: 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
•: domestic 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, 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 existence of a potential difference in the gas price associated with each transaction.

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.

We account for derivative instruments in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities. 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 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 satisfy 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, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the 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.

We have found material weaknesses in our internal controls that require remediation and concluded, pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, that our internal controls over financial reporting at December 31, 2005, 2004 and 2003, were not effective. If we fail to remediate any material weaknesses, we could be unable to provide timely and reliable financial information, which could have a material adverse effect on our business, results of operations or financial condition.

We have identified, and the audit report on management's assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting of Deloitte & Touche LLP as of December 31, 2005 confirmed the presence of, material weaknesses in our internal controls over financial reporting. In particular, our control environment did not sufficiently promote effective internal control over financial reporting through the management structure to prevent a material misstatement. Furthermore, we did not have adequate internal controls and processes in place to allow independent validation of data or control and review of our management's assertions with respect to the completeness, accuracy and validity of commodity derivative transactions.

In addition, we and KPMG LLP, our independent registered public accounting firm at that time, identified material weaknesses in our internal control over financial reporting as of December 31, 2004. Additionally, PwC, our independent registered public accounting firm at the time, identified certain deficiencies in our internal accounting controls as of December 31, 2003. Considered collectively, these deficiencies may have constituted a material weakness in our internal controls pursuant to standards established by the American Institute of Certified Public Accountants. For a further discussion of these material weaknesses, please read "Prospectus Summary — Material Weaknesses Reported for the Years Ended December 31, 2005, 2004 and 2003."

The full impact of our efforts to remediate the identified material weaknesses had not been realized as of December 31, 2005 and may not be sufficient to maintain effective internal controls in the future. We may not be able to implement and maintain adequate controls over our financial processes and reporting, which may require us to restate our financial statements in the future. In addition, we may discover additional past, ongoing or future material weaknesses or significant deficiencies in our financial reporting system in the future. Any failure to implement new controls, or difficulty encountered in their implementation, could cause us to fail to meet our reporting obligations

or result in material misstatements in our financial statements. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could result in a lower trading price of our common units.

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:

•: damage to pipelines, plants, related equipment and surrounding properties caused by floods, hurricanes and other natural disasters;
•: inadvertent damage from construction and farm equipment;
•: leakage of crude oil, natural gas, NGLs and other hydrocarbons;
•: fires and explosions; and
•: 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. In addition, insurance carriers have indicated hurricane insurance premiums may increase significantly and policy limits may be significantly reduced. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

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 profitability.

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. 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 ("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 fair return on the aggregate value of the facilities used to render services. We cannot assure you 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 "Business—Regulatory Matters" incorporated by reference to our Annual Report on Form 10-K for the year ended December 31, 2005, as amended.

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 and our cash flows could be adversely affected.

The construction of additions to our existing gathering assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines 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, then our cash flows could be adversely affected.

We are indemnified for liabilities arising from an ongoing remediation of property on which our facilities are located and our results of operation and our ability to make payments of principal and interest 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 and Kermit facilities are located and is the previous operator of our Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman and Cobb facilities pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and the U.S. Environmental Protection Agency and, in the case of the Boldman facility, an "Agreed Order" with the Kentucky Natural Resources and Environmental Protection Cabinet.

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

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

Numerous governmental agencies enforce comprehensive and stringent 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. New environmental laws and regulations might adversely influence our products and activities. Federal, state and local agencies also could impose additional safety requirements, any of which could affect our profitability. In addition, we face the risk of accidental releases or spills associated with our operations. These could result in material costs and liabilities, including those relating to claims for damages to property 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 our operations. For more information regarding the environmental, safety and

other regulatory matters that could affect our business, please read "Business—Regulatory Matters," "Business—Environmental Matters" and "Business—Pipeline Safety Regulations" incorporated by reference to our Annual Report on Form 10-K for the year ended December 31, 2005, as amended.

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

All of the natural gas we process, gather and transmit is delivered into pipelines for further delivery to end-users. If these pipelines cannot, or will not, accept delivery of the gas due to downstream constraints on the pipeline, we will be forced to limit or stop the flow of gas through our pipelines and processing systems. In addition, interruption of pipeline service upstream of our processing facilities would likewise 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 result in a material reduction in our net operating margin.

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

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 transport crude oil to or from these facilities or pipelines for any reason, would adversely affect our results of operations. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:

•: unscheduled turnarounds or catastrophic events at our physical plants;
•: labor difficulties that result in a work stoppage or slowdown; and
•: a disruption in the supply of crude oil to our crude oil pipeline, natural gas to our processing plants or gathering pipelines, or a disruption in the supply of NGLs to our transportation pipeline and fractionation facility.

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

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

As a result of damage caused by Hurricanes Katrina and Rita in the Gulf of Mexico and Gulf Coast regions, insurance costs related to oil and gas assets in these regions have increased significantly. We may be unable to obtain insurance on our interest in Starfish at rates we consider reasonable.

During 2005, Hurricanes Katrina and Rita caused severe and widespread damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions. The resulting loss to both offshore and onshore

assets led to substantial insurance claims within the oil and gas industry. Along with other industry participants, we expect insurance costs to increase within this region as a result of these developments. We are currently negotiating with our insurer regarding the renewal of our insurance coverage relating to Starfish. We may be unable to obtain insurance on our interest in Starfish at rates we consider reasonable and as a result may experience losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant negative event that is not fully insured occurs with respect to Starfish, it could materially and adversely affect our financial condition and results of operations.

A shortage of skilled labor may make it difficult for us to maintain labor productivity, and competitive costs and could adversely affect our profitability.

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 profitability.

Risks Related to Our Partnership Structure

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

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

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

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

•: Employees of MarkWest Hydrocarbon who provide services to us also devote significant time to the businesses of MarkWest Hydrocarbon and are compensated by MarkWest Hydrocarbon for these services.
•: Neither our Partnership Agreement nor any other agreement requires MarkWest Hydrocarbon to pursue a future business strategy that favors us or utilizes our assets for processing, transportation or fractionation services we provide. MarkWest Hydrocarbon's directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of MarkWest Hydrocarbon.

•: Our general partner is allowed to take into account the interests of other parties, such as MarkWest Hydrocarbon, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.
•: Our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
•: Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the processing, transportation and fractionation agreements with MarkWest Hydrocarbon.
•: Our general partner decides whether to retain separate counsel, accountants or others to perform services for us
•: In some instances, our general partner may cause us to borrow funds in order to make cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units or to make incentive distributions or to hasten the conversion of subordinated units.
•: Our Partnership Agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.
•: Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to our unitholders.
•: Our general partner determines which costs incurred by MarkWest Hydrocarbon and its affiliates are reimbursable by us.
•: Our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

MarkWest Hydrocarbon and its affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses and which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our partnership agreement nor the omnibus agreement among us, MarkWest Hydrocarbon and others prohibits MarkWest Hydrocarbon and its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, MarkWest Hydrocarbon and its affiliates may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. MarkWest Hydrocarbon is a large, established participant in the midstream energy business and has significantly greater resources and experience than we have, which may make it more difficult for us to compete with it with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely impact our results of operations and cash available for distribution. Please read "Conflicts of Interest and Fiduciary Duties."

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•: the issuance of common units in connection with acquisitions or capital improvements that increase cash flow from operations per unit on a pro forma basis;
•: the conversion of subordinated units into common units;
•: the conversion of units of equal rank with the common units into common units under some circumstances;
•: the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner;
•: issuances of common units under our long-term incentive plan; or
•: issuances of common units to repay indebtedness, the cost of servicing which is greater than the distribution obligations associated with the units issued in connection with the debt's retirement.

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

•: our unitholders' proportionate ownership interest in us will decrease;
•: the amount of cash available for distribution on each unit may decrease;
•: because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
•: the relative voting strength of each previously outstanding unit may be diminished;
•: the market price of the common units may decline; and

•: the ratio of taxable income to distributions may increase.

After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our Partnership Agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

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

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

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

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

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

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

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read "Material Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction

in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all of our counsel's conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

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

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income

allocated to organizations that are exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income.

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

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we adopted.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. Please read "Material Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

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

In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We currently do business or own property in nine states, most of which impose income taxes. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

USE OF PROCEEDS

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

PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

Our common units have been listed on the American Stock Exchange ("AMEX"), under the symbol "MWE." The following table sets forth the high and low sales prices of the common units as reported by AMEX, as well as the amount of cash distributions paid per quarter for 2006, 2005 and 2004 and subsequent interim periods.

Quarter Ended	High		Low		Distributions Per Unit(1)		Record Date	Payment Date
Through July 17, 2006	$	43.25	$	41.00		—	—	—
June 30, 2006	$	46.65	$	39.50		—	—	—
March 31, 2006	$	47.99	$	43.51	$	0.87	May 5, 2006	May 15, 2006
December 31, 2005	$	50.95	$	42.01	$	0.82	February 8, 2006	February 14, 2006
September 30, 2005	$	53.50	$	47.18	$	0.82	November 8, 2005	November 14, 2005
June 30, 2005	$	51.54	$	46.51	$	0.80	August 9, 2005	August 15, 2005
March 31, 2005	$	52.50	$	45.25	$	0.80	May 10, 2005	May 16, 2005
December 31, 2004	$	48.69	$	42.50	$	0.78	February 2, 2005	February 11, 2005
September 30, 2004	$	45.80	$	37.73	$	0.76	November 3, 2004	November 12, 2004
June 30, 2004	$	40.07	$	33.50	$	0.74	July 30, 2004	August 13, 2004
March 31, 2004	$	41.66	$	37.70	$	0.69	April 30, 2004	May 14, 2004

(1): Includes both common units and subordinated units.

We have also issued 3,000,000 subordinated units, for which there is no established public-trading market. Pursuant to the terms of the partnership agreement, 1,200,000 of these units were converted into common units during 2005. 1,800,000 subordinated units were outstanding as of July 10, 2006. There were two holders of record of our subordinated units as of July 10, 2006.

The last reported sale price of the common units on the American Stock Exchange on July 17, 2006 was $43.03. As of July 10, 2006, there were 143 holders of record of our common units.

CASH DISTRIBUTION POLICY

Distributions of Available Cash

General. Within approximately 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash. We define available cash in the glossary, and it generally means, for each fiscal quarter:

•

all cash on hand at the end of the quarter;

•

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

•: provide for the proper conduct of our business;
•: comply with applicable law, any of our debt instruments, or other agreements; or
•: provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

•

plus all cash 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.

Minimum Quarterly Distribution. Common units are entitled to receive distributions from operating surplus of $0.50 per quarter, or $2.00 on an annualized basis, before any distributions are paid on our subordinated units. There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we are prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility. As reflected below, our definition of operating surplus contains a $6.3 million basket. This basket is a provision that enables us, if we choose, to distribute as operating surplus up to $6.3 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, that would otherwise be distributed as capital surplus.

Contractual Restrictions on our Ability to Distribute Available Cash. Our ability to distribute available cash is contractually restricted by the terms of our credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios and a minimum net worth. We are prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under our credit facility. In addition, our credit facility prohibits us from borrowing more than $0.75 per outstanding unit during any consecutive 12-month period for the purpose of making distributions to our unitholders. Our credit facility provides that any amount so borrowed must be repaid once annually. Please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Description of Credit Facility" incorporated by reference to our Annual Report on Form 10-K for the year ended December 31, 2005, as amended.

Operating Surplus and Capital Surplus

General. All cash distributed to unitholders is characterized as either "operating surplus" or "capital surplus." We distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of Operating Surplus. We define operating surplus in the glossary, and for any period it generally means:

•: $470,000 representing cash on hand at the closing of our initial public offering; plus
•: $6.3 million (as described above); plus
•: all of our cash receipts since the initial public offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus
•: working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less
•: all of our operating expenditures since the initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; and less
•: the amount of cash reserves that our general partner deems necessary or advisable to provide funds for future operating expenditures.

Definition of Capital Surplus. We also define capital surplus in the glossary, and it is generally generated only by:

•: borrowings other than working capital borrowings;
•: sales of debt and equity securities; and
•: sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Characterization of Cash Distributions. We treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. While we do not currently anticipate that we will make any distributions from capital surplus in the near term, we may determine that the sale or disposition of an asset or business owned or acquired by us may be beneficial to our unitholders. If we distribute to you the equity we own in a subsidiary or the proceeds from the sale of one of our businesses, such a distribution would be characterized as a distribution from capital surplus.

Subordination Period

General. During the subordination period, which we define below and in the glossary, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Definition of Subordination Period. We define the subordination period in the glossary. The subordination period will extend until the first day of any quarter beginning after June 30, 2009 that each of the following tests are met:

•: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
•: the "adjusted operating surplus" (as defined below) generated during each of the three immediately preceding, non-overlapping four-quarter periods equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
•: there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Conversion of Subordinated Units. Before the end of the subordination period, a portion of the subordinated units may convert into common units on a one-for-one basis immediately after the distribution of available cash to the partners in respect of any quarter ending on or after:

•: June 30, 2006 with respect to 20% of the subordinated units;
•: June 30, 2007 with respect to 20% of the subordinated units; and
•: June 30, 2008 with respect to 20% of the subordinated units.

The early conversions will occur if at the end of the applicable quarter each of the following occurs:

•: distributions of available cash from operating surplus on each common unit and subordinated unit equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
•: the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
•: there are no arrearages in payment of the minimum quarterly distribution on the common units.

However, the early conversion of the second, third or fourth 20% of the subordinated units may not occur until at least one year following the early conversion of the first, second or third 20% of the subordinated units, as the case may be. On August 15, 2005, after meeting the financial tests set forth in our partnership agreement for the first early conversion of subordinated units, we completed the conversion, on a one-for-one basis, of 600,000 subordinated units into common units.

In addition, on November 14, 2005, we completed the conversion, on a one-for-one basis, of 600,000 subordinated units into common units as a result of satisfying the following conditions in our partnership agreement:

•: distributions of available cash from operating surplus on each common unit and subordinated unit equaled or exceeded $2.50 for each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date;
•: the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $2.50 on all of the outstanding common units and subordinated units during those

periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

•: there were no arrearages in payment of the minimum quarterly distribution on the common units.

This additional early conversion was a one time occurrence.

In addition to the early conversion of subordinated units described above, 20% of the subordinated units may convert into common units on a one-for-one basis prior to the end of the subordination period if, at the end of a quarter ending on or after June 30, 2005, each of the following occurs:

•: distributions of available cash from operating surplus on each common unit and subordinated unit equaled or exceeded $3.00 for each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date;
•: the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $3.00 on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
•: there are no arrearages in payment of the minimum quarterly distribution on the common units.

This additional early conversion is a one time occurrence.

Generally, the earliest possible date by which all subordinated units may be converted into common units is June 30, 2007.

Definition of Adjusted Operating Surplus. We define adjusted operating surplus in the glossary and for any period it generally means:

•: operating surplus generated during that period; less
•: any net increase in working capital borrowings during that period; less
•: any net reduction in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period; plus
•: any net decrease in working capital borrowings during that period; and plus
•: any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal, the subordination period will end, any then-existing arrearages on the common units will terminate and each subordinated unit will immediately convert into one common unit.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•: First, 98% to the common unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
•: Second, 98% to the common unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
•: Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
•: Thereafter, in the manner described in "—Incentive Distribution Rights" below.

Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•: First, 98% to all unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
•: Thereafter, in the manner described in "—Incentive Distribution Rights" below.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

If for any quarter:

•: we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
•: we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

•: First, 98% to all unitholders, pro rata, and 2% to our general partner until each unit receives a total of $0.55 per unit for that quarter (the "first target distribution");
•: Second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.625 per unit for that quarter (the "second target distribution");
•: Third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.75 per unit for that quarter (the "third target distribution"); and

•: Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

Target Amount of Quarterly Distribution

The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of the unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Unitholders		General Partner
Minimum Quarterly Distribution	$0.50	98	%	2	%
First Target Distribution	up to $0.55	98	%	2	%
Second Target Distribution	above $0.55 up to $0.625	85	%	15	%
Third Target Distribution	above $0.625 up to $0.75	75	%	25	%
Thereafter	above $0.75	50	%	50	%

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made. We will make distributions of available cash from capital surplus, if any, in the following manner:

•: First, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit that was issued in the initial public offering, an amount of available cash from capital surplus equal to the initial public offering price;
•: Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
•: Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus. The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units, 48% to the holders of the incentive distribution rights and 2% to our general partner.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•: the minimum quarterly distribution;
•: target distribution levels;
•: unrecovered initial unit price;
•: the number of common units issuable during the subordination period without a unitholder vote; and
•: the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum marginal federal, and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distributions levels would each be reduced to 62% of their previous levels.

Distributions of Cash upon Liquidation

General. If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

•

First, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

•

Second, 98% to the common unitholders, pro rata, and 2% to our general partner until the capital account for each common unit is equal to the sum of:

(1): the unrecovered initial unit price for that common unit; plus
(2): the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and plus
(3): any unpaid arrearages in payment of the minimum quarterly distribution;

•

Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of:

(1): the unrecovered initial unit price on that subordinated unit; and
(2): the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•

Fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1): the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less
(2): the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

•

Fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1): the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less
(2): the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence;

•

Sixth, 75% to all unitholders, pro rata, and 25% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1): the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less
(2): the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence;

•

Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second priority above and all of the third priority above will no longer be applicable.

Manner of Adjustments for Losses. Upon our liquidation, we will generally allocate any loss to our general partner and the unitholders in the following manner:

•: First, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner until the capital accounts of the subordinated unitholders have been reduced to zero;
•: Second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner until the capital accounts of the common unitholders have been reduced to zero; and
•: Thereafter, 100% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first priority above will no longer be applicable.

Adjustments to Capital Accounts. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our general partner's capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

On March 31, 2005, we acquired a 50% non-operating membership interest in Starfish Pipeline Company, LLC (the "Starfish acquisition") from an affiliate of Enterprise Products Partners, L.P. for $41.7 million. The acquisition was financed through our credit facility. On November 1, 2005, we acquired 100% of the equity interests in Javelina Company, Javelina Pipeline Company, Javelina Land Company, L.L.C. and related entities (collectively, "Javelina") for $357.0 million, plus $41.3 million for net working capital. We had a net draw of $386.5 million on our credit facility to finance the Javelina acquisition. We also incurred $10.4 million of debt issuance costs, of which $5.4 million was paid in cash and $5.0 million was paid from drawings on the credit facility. The final determination of the working capital amount and allocation of the purchase price has not been completed.

The following unaudited pro forma consolidated statement of operations for the year ended December 31, 2005 and the three months ended March 31, 2006 gives effect to the following transactions as if they all occurred on January 1, 2005:

•: the Javelina acquisition;
•: our net borrowings under our credit facility to finance the Javelina acquisition;
•: the Starfish acquisition;
•: our net borrowings on our credit facility to partially finance the Starfish acquisition;
•: our November 2005 private placement of 1,644,065 common units, and a capital contribution from our general partner to maintain its 2% general partner interest;
•: our December 2005 private placement of 574,714 common units, and a capital contribution from our general partner to maintain its 2% general partner interest;
•: our June 2006 public offering of 3,300,000 common units at a public offering price of $39.75, and a capital contribution from our general partner to maintain its 2% general partner interest;
•: our June 2006 private placement of $200 million in aggregate principal amount of senior notes to qualified institutional buyers; and
•: the application of the net proceeds from our November 2005 private placement, December 2005 private placement and our June 2006 public offering of common units, including, in each case, the contribution from our general partner, and the application of the net proceeds from our June 2006 private placement of senior notes to partially repay borrowings under our credit facility incurred in connection with the acquisition of both Javelina and Starfish.

These transaction adjustments are presented and discussed in the notes to the unaudited pro forma financial statements. You should read the unaudited pro forma financial statements and accompanying notes along with our historical financial statements and the accompanying notes and the historical financial statements of Javelina and Starfish and the accompanying notes incorporated by reference into this prospectus.

The information presented under the heading "Javelina" in the pro forma financial statements reflects the results of operations of Javelina Company and Javelina Pipeline Company for the ten months ended October 31, 2005. No separate information for the other Javelina entities has been presented as the amounts are immaterial. In addition to property, plant and equipment, the acquisition of equity interests resulted in the assumption of certain current assets and liabilities of the companies as of November 1, 2005. Our historical consolidated statements of operations for the year ended December 31, 2005 and the three months ended March 31, 2006 include results of Javelina from November 1, 2005 through December 31, 2005 and March 31, 2006, respectively. Accordingly, the separate Javelina information only includes the ten months ended October 31, 2005 that are not already included in our results.

The information presented under the heading "Starfish" reflects the results of operations of Starfish Pipeline Company, LLC for the three months ended March 31, 2005. Our historical consolidated statements of operations for the year ended December 31, 2005 and the three months ended March 31, 2006 include the Starfish acquisition from April 1, 2005, through December 31, 2005 and March 31, 2006, respectively. Accordingly, the separate Starfish information reflects only the three months ended March 31, 2005, that are not already included in our results.

The pro forma statements of operations were derived by adjusting the historical financial statements of MarkWest Energy Partners, L.P. The adjustments are based on currently available information. We believe, however, that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. The unaudited pro forma financial statements do not purport to present our results of operations had the acquisitions or the other transactions actually been completed as of the dates indicated. Moreover, the statements do not project our financial position or results of operations for any future date or period.

			Twelve Months Ended December 31, 2005													Three Months Ended March 31, 2006
			MarkWest Energy			Starfish		Javelina		Pro Forma Adjustments			Pro Forma As Adjusted			MarkWest Energy			Pro Forma Adjustments			Pro Forma As Adjusted
			(in thousands, except per unit amounts)
Revenues:
	Sales to unaffiliated parties		$	434,162		$	—	$	255,864	$	—		$	690,026		$	138,788		$	—		$	138,788
	Sales to affiliate			64,922			—		—		—			64,922			17,715			—			17,715
Derivatives				—			—		—		—			—			240			—			240

		Total Revenues		499,084			—		255,864		—			754,948			156,743			—			156,743

Operating expenses:
	Purchased product costs			366,878			—		178,147		—			545,025			100,797			—			100,797
	Facility expenses			47,972			—		42,613		—			90,585			13,994			—			13,994
	Selling, general and administrative expenses			21,573			—		1,363		—			22,936			8,338			—			8,338
	Depreciation			19,534			—		7,677		(964	)(a)		26,247			7,173			—			7,173
	Amortization of intangible assets			9,656			—		—		6,405	(b)		16,061			4,016			—			4,016
	Accretion of asset retirement and lease obligations			159			—		—		—			159			25			—			25

		Total operating expenses		465,772			—		229,800		5,441			701,013			134,343			—			134,343

		Income from operations		33,312			—		26,064		(5,441	)		53,935			22,400			—			22,400
Other income (expense):
	Earnings in unconsolidated affiliates			(2,153	)		984		—		(72	)(c)		(1,241	)		945			—			945
	Interest income			367			—		354		—			721			220						220
	Interest expense			(22,469	)		—		—		(24,060 (750 6,518 9,564 (2,356	)(d) )(e) (f) (g) )(h)		(33,553	)		(10,976	)		2,391 (589	(g) )(h)		(9,174	)
	Amortization of deferred financing costs			(6,780	)		—		—		(4,926 (8,907	)(d) )(h)		(20,613	)		(808	)		558	(h)		(250	)
	Miscellaneous income (expense)			78			—		—		—			78			2,092			—			2,092

Net income (loss)			$	2,355		$	984	$	26,418	$	(30,430	)	$	(673	)	$	13,873		$	2,360		$	16,233

Interest in net income:
	General partner		$	2,113									$	2,052		$	828					$	875
	Limited partners		$	242									$	(2,725	)	$	13,045					$	15,358
Net income per limited partner unit:
	Basic		$	0.02									$	(0.17	)	$	1.01					$	0.95
	Diluted		$	0.02									$	(0.17	)	$	1.01					$	0.95

		Twelve Months Ended December 31, 2005					Three Months Ended March 31, 2006
		MarkWest Energy	Starfish	Javelina	Pro Forma Adjustments	Pro Forma As Adjusted	MarkWest Energy	Pro Forma Adjustments	Pro Forma As Adjusted
		(in thousands)
Weighted average units outstanding
	Basic	10,895			5,519	16,414	12,873	3,300	16,173
	Diluted	10,929			5,519	16,448	12,922	3,300	16,222

(a): The pro forma adjustment to Javelina depreciation expense for the year ended December 31, 2005 are as follows (in thousands):

Historical depreciation	$	(7,677	)
Pro forma depreciation(1)		6,713

Pro forma adjustment to depreciation expense		(964	)

(1): Pro forma depreciation is based on the following lives: Buildings (40 years), Pipeline and plant equipment (20 years), Other (3 years).
(b): Amortization of identifiable intangible assets and customer contracts of $192.1 million for the year ended December 31, 2005, over the estimated useful life of 25 years.
(c): Amortization of the excess Starfish purchase price over net book value of $4.9 million for the three months from January 1, 2005, to the Starfish acquisition date, over the estimated useful life of 17 years.
(d): Interest expense on the debt associated with the Javelina acquisition of $386.5 million for the first 10 months of the year ended December 31, 2005, at a weighted average interest of 7.50%. The effect of a 0.125% variance in annual interest rates under our credit facility on pro forma interest expense would have been approximately $0.4 million. Amortized deferred financing costs for the nine months ended September 30, 2005, based upon the term of the debt facility, and expensed debt issuance costs were both associated with the debt for the Javelina acquisition.
(e): Interest expense on the incremental debt associated with the Starfish acquisition of $40.0 million for the three months from January 1, 2005, to the Starfish acquisition date, at a weighted average interest rate of 7.50%. The effect of a 0.125% variance in annual interest rates under our credit facility on pro forma interest expense would have been approximately $12,500.
(f): Reduction of interest expense resulting from the application of the net proceeds from our November 2005 private placement and December 2005 private placements of $74.1 million and $25.4 million, respectively.
(g): Reduction of interest expense resulting from the application of the estimated net proceeds from our June 2006 public equity offering of $127.3 million.
(h): Adjusted to reflect our June 2006 private placement of senior notes. The twelve months ended December 31, 2005, reflect additional interest expense of $4.0 million and additional amortization of deferred financing costs ($0.6 million associated with the notes in our June 2006 private placement, $2.8 million reduction associated with retirement of existing debt, and $11.1 million acceleration associated with existing debt). The three months ended March 31, 2006, reflect additional interest expense of $0.6 million and a reduction in deferred financing costs ($0.1 million associated with the notes in our June 2006 private placement, and $0.7 million associated with existing debt).

SELECTED HISTORICAL FINANCIAL INFORMATION

The following table shows selected historical financial and operating data of the MarkWest Hydrocarbon Midstream Business and us as of and for the periods indicated. The MarkWest Hydrocarbon Midstream Business represents substantially all of MarkWest Hydrocarbon's historical natural gas gathering and processing and NGL transportation, fractionation and storage businesses prior to our formation. The selected historical financial data for the MarkWest Hydrocarbon Midstream Business as of and for the year ended December 31, 2001 is derived from the audited financial statements of the MarkWest Hydrocarbon Midstream Business. Our selected historical financial data as of and for the years ended December 31, 2002, 2003, 2004 and 2005 is derived from our audited financial statements.

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

•: its revenues included the aggregate sales price for all the NGL products produced in its operations; and
•: its purchased product costs included the cost of natural gas purchases needed to replace the Btu content of the NGLs extracted in its processing operations under keep-whole contracts and the percentage of the proceeds from the sale of NGL products remitted to producers under percent-of-proceeds contracts.

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

•: our revenues related to these assets include only the fees we receive for processing natural gas, transporting, fractionating and storing NGLs and the aggregate proceeds from NGL sales we receive under our percent-of-proceeds contracts; and
•: our purchased product costs related to these assets primarily consist of the percentage of proceeds from the sale of NGL products remitted to producers under our percent-of-proceeds contracts, with a small portion of our purchased product costs attributable to natural gas purchase to satisfy our obligations under our keep-whole contracts.

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

We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should be read together with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2005, as amended, and "Item 2. Management's Discussion and Analysius of Financial Condition and Results of Operations" incorporated by reference from our Quarterly Report on Form 10-Q for the three months ended March 31, 2006, as amended.

		MarkWest Hydrocarbon Midstream Business			Partnership
		Year Ended December 31,															Three Months Ended March 31,
		2001			2002			2003(a)			2004(b)			2005(c)			2005			2006
		(in thousands, except per unit amounts)
Statement of Operations:
Revenues		$	93,675		$	70,246		$	117,430		$	301,314		$	499,084		$	89,637		$	156,743
Operating expenses:
	Purchased product costs		65,483			38,906			70,832			211,534			366,878			60,785			100,797
	Facility expenses		13,138			15,101			20,463			29,911			47,972			9,331			13,994
	Selling, general and administrative expenses		5,047			5,411			8,598			16,133			21,573			4,639			8,338
	Depreciation and amortization of intangible assets		4,490			4,980			7,548			19,196			29,199			6,421			11,189
	Impairments		—			—			1,148			130			—			—			—
	Accretion of asset retirement obligation		—			—			—			13			159			10			25

Total operating expenses			88,158			64,398			108,589			276,917			465,772			81,186			134,343

Income from operations			5,517			5,848			8,841			24,397			33,312			8,451			22,400
	Interest expense, net		(1,307	)		(1,414	)		(4,057	)		(14,385	)		(28,882	)		(4,082	)		(11,564	)
	Loss from unconsolidated affiliates		—			—			—			(65	)		(2,153	)		—			945
	Miscellaneous income (expense)		—			52			(25	)		15			78			(104	)		2,092

Income before income taxes			4,210			4,486			4,759			9,962			2,355			4,265			13,873
	Provision (benefit) for income taxes		1,624			(17,175	)		—			—			—

Net income		$	2,586		$	21,661		$	4,759		$	9,962		$	2,355		$	4,265		$	13,873

Net income per limited partner unit:
	Basic	$	0.86		$	4.86		$	0.95		$	1.31		$	0.02		$	0.41		$	1.01
	Diluted	$	0.86		$	4.83		$	0.94		$	1.31		$	0.02		$	0.41		$	1.01
Cash distributions declared per limited partner unit			—		$	1.23		$	2.47		$	2.97		$	3.28			—			—

	MarkWest Hydrocarbon Midstream Business		Partnership
	Year Ended December 31,										Three Months Ended March 31,
	2001		2002		2003(a)		2004(b)		2005(c)		2006
	(in thousands)
Balance Sheet Data (at period end):
Working capital	$	18,240	$	1,762	$	2,457	$	10,547	$	11,944	$	(1,098	)
Property, plant and equipment, net		82,008		79,824		184,214		280,635		492,961		499,315
Total assets		104,891		87,709		212,871		529,422		1,046,093		1,019,322
Total long-term debt		19,179		21,400		126,200		225,000		601,262		588,850
Partners' capital		65,429		60,863		64,944		241,142		307,175		310,163

			MarkWest Hydrocarbon Midstream Business			Partnership
			Year Ended December 31,															Three Months Ended March 31,
			2001			2002			2003(a)			2004(b)			2005(c)			2005			2006
			(in thousands)
Cash Flow Data:
Net cash flow provided by (used in):
	Operating activities		$	(524	)	$	33,502		$	21,229		$	42,275		$	42,090		$	17,522		$	41,035
	Investing activities			(8,997	)		(2,056	)		(112,893	)		(273,176	)		(469,308	)		(57,556	)		(15,510	)
	Financing activities			9,521			(28,670	)		97,641			246,411			423,060			30,955			(18,807	)
Other Financial Data:
Sustaining capital expenditures(d)			$	576		$	511		$	1,041		$	1,163		$	2,181		$	15		$	377
Expansion capital expenditures(d)				9,075			1,634			1,903			29,304			68,569			15,864			12,783

		Total capital expenditures	$	9,651		$	2,145		$	2,944		$	30,467		$	70,750		$	15,879		$	13,160

Net operating margin(e)			$	28,192		$	31,340		$	46,598		$	89,780		$	132,206		$	28,852		$	55,946
EBITDA(f)			$	10,007		$	10,885		$	16,378		$	43,630		$	60,794		$	14,835		$	36,846

		MarkWest Hydrocarbon Midstream Business	Partnership
		Year Ended December 31,					Three Months Ended March 31,
		2001	2002	2003(a)	2004(b)	2005(c)	2005	2006
Operating Data:
Southwest:
East Texas
	Gathering systems throughput (Mcf/d)	—	—	—	259,300	321,000	287,000	346,000
	NGL product sales (gallons)	—	—	—	41,478,000	126,476,000	27,612,000	35,436,000

Oklahoma
	Foss Lake gathering systems throughput (Mcf/d)	—	—	57,000	60,900	75,800	67,000	87,600
	Arapaho NGL product sales (gallons)	—	—	2,910,000	45,273,000	60,903,000	15,217,000	18,417,000
Other
	Appleby gathering systems throughput (Mcf/d)	—	—	23,800	27,100	33,400	28,000	33,500
	Other gathering systems throughput (Mcf/d)	—	—	20,500	17,000	16,500	17,000	19,100
	Lateral throughput volumes (Mcf/d)(g)	—	—	32,100	75,500	81,000	52,000	49,700
Gulf Coast:
	Natural gas processed for a fee (Mcf/d)	—	—	—	—	115,000	—	120,000
	NGLs fractionated for a fee (Gal/day)	—	—	—	—	19,400	—	820,000
	NGL product sales (gallons)
Northeast:
Appalachia:
	Natural gas processed for a fee (Mcf/d)	192,000	202,000	202,000	203,000	197,000	210,000	205,000
	NGLs fractionated for a fee (Gal/day)	423,000	476,000	458,000	475,000	430,000	462,000	449,000
	NGL product sales (gallons)	—	38,813,000	40,305,000	42,105,000	41,700,000	10,765,000	10,482,000


Michigan:
	Natural gas processed for a fee (Mcf/d)	8,800	13,800	15,000	12,300	6,600	6,900	6,300
	Crude oil transported for a fee (Bbl/d)	—	—	15,100	14,700	14,200	14,100	14,000
	NGL product sales (gallons)	8,000,000	11,100,000	11,800,000	9,818,000	5,697,000	1,563,000	1,449,000

(a): We acquired our Foss Lake gathering system in December 2003. We acquired our Arapaho processing plant in December 2003. We acquired our Pinnacle gathering systems in late March 2003. We acquired our Lubbock pipeline in September 2003 and our Michigan Crude Pipeline in December 2003.
(b): We acquired our East Texas System in late July 2004. We acquired our Hobbs lateral pipeline in April 2004.
(c): We completed our investment in Starfish on March 31, 2005, and acquired Javelina on November 1, 2005.
(d): Sustaining capital expenditures include expenditures to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition.
(e): Management evaluates contract performance on the basis of net operating margin (a "non-GAAP" financial measure), which is defined as income (loss) from operations, excluding facility expenses, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement obligations. 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 future periods. Net operating margin does not have any standardized definition and, therefore, is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Our use of net operating margin, 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 reconciles non-GAAP financial measure to income from operations, the most directly comparable GAAP financial performance measure:

		Year Ended December 31,										Three Months Ended March 31,
		2001		2002		2003		2004		2005		2005		2006
		(in thousands)
Revenues		$	93,675	$	70,246	$	117,430	$	301,314	$	499,084	$	89,637	$	156,743
Purchased product costs			65,483		38,906		70,832		211,534		366,878		60,785		100,797

Net operating margin			28,192		31,340		46,598		89,780		132,206		28,852		55,946
	Facility expenses		13,138		15,101		20,463		29,911		47,972		9,331		13,994
	Selling, general and administrative expenses		5,047		5,411		8,598		16,133		21,573		4,639		8,338
	Depreciation		4,490		4,980		7,548		15,556		19,534		4,326		7,173
	Amortization of intangible assets		—		—		—		3,640		9,656		2,095		4,016
	Accretion of asset retirement obligation		—		—		—		13		159		10		25
	Impairments		—		—		1,148		130		—		—		—

Income from operations		$	5,517	$	5,848	$	8,841	$	24,397	$	33,312	$	8,451	$	22,400

(f): EBITDA is defined as earnings before income taxes, plus depreciation and amortization expense and interest expense. EBITDA (i) is not a measure of performance calculated in accordance with GAAP,

and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our financial statements.

EBITDA is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Management believes that the presentation of EBITDA is useful to lenders and investors because of its use in the midstream natural gas industry and for master limited partnerships as an indicator of the strength and performance of our ongoing business operations. Additionally, management believes that EBITDA provides additional and useful information to our investors for trending, analyzing and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures. The presentation of EBITDA allows investors to view our performance in a manner similar to the methods used by management and provides additional insight to our operating results.

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

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

The following table reconciles EBITDA with our net income:

	Year Ended December 31,											Three Months Ended March 31,
	2001		2002			2003		2004		2005		2005		2006
	(in thousands)
Net income	$	2,586	$	21,661		$	4,759	$	9,962	$	2,355	$	4,265	$	13,873
Interest expense		1,307		1,419			4,071		14,472		29,249		4,149		11,784
Taxes		1,624		(17,175	)		—		—		—		—		—
Depreciation and amortization		4,490		4,980			7,548		19,196		29,190		6,421		11,189

EBITDA	$	10,007	$	10,885		$	16,378	$	43,630	$	60,794	$	14,835	$	36,846

(g): The Lubbock and Hobbs pipelines are the only lateral pipelines we own that produce revenue on a volumetric basis. We receive a flat fee for the use of our other lateral pipelines, and consequently, the throughput volume data from these other lateral pipelines is excluded from this data.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units as of July 12, 2006, held by beneficial owners of 5% or more of the units; by directors of our general partner; by each named executive officer listed in the summary compensation table incorporated by reference in this prospectus; and by all directors and officers of our general partner as a group.

Name of Beneficial Owner	Common Units Beneficially Owned(1)	Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Units Beneficially Owned
MarkWest Energy GP, L.L.C(2)	—	—		—	—		—
MarkWest Hydrocarbon, Inc.(3)	836,162	5.8	%	1,633,334	90.7	%	15.3	%
John M. Fox(4)	880,893	6.1	%	1,637,384	91.0	%	15.6	%
Kayne Anderson Capital Advisors, L.P(5) 1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067	1,670,380	11.6	%	—	—		10.3	%
Richard A. Kayne(5) 1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067	1,670,380	11.6	%	—	—		10.3	%
Tortoise Capital Advisors L.L.C.(6) 10801 Mastin Boulevard, Suite 222 Overland Park, KS 66210	966,704	6.7	%	—	—		6.0	%
Tortoise Energy Infrastructure Corporation(6) 10801 Mastin Boulevard, Suite 222 Overland Park, KS 66210	805,810	5.6	%	—	—		5.0	%
Tortoise MWEP, L.P.(7) 10801 Mastin Boulevard, Suite 222 Overland Park, KS 66210	—	—		166,666	9.3	%	1.0	%
Frank M. Semple(2)	13,734	*		—	*		—
James G. Ivey(2)	3,151	*		—	—		*
Randy S. Nickerson(2)	12,495	*		—	*		—
John C. Mollenkopf(2)	7,936	*		—	*		—
David L. Young(2)	136	*		—	—		*
Keith E. Bailey(2)	10,700	*		—	—		*
Donald C. Heppermann(2)	11,667	*		—	*		*
William A. Kellstrom(2)	4,042	*		—	—		*
William P. Nicoletti(2)	3,542	*		—	—		*
Charles K. Dempster(2)	1,042	*		—	—		*
All directors and executive officers as a group (17 persons)	951,927	6.6	%	1,637,384	91.0	%	16.0	%

*: Less than 1%
(1): Beneficial ownership for the purposes of the foregoing table is defined by Rule 13d-3 under the Securities Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof ("Voting Power") or to dispose or direct the disposition thereof ("Investment Power") or has the right to acquire either of those powers within sixty (60) days.
(2): The address of each of these entities and individuals is 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112.

(3): Includes securities owned directly and indirectly through subsidiaries.
(4): Includes 1,633,334 subordinated units owned by MarkWest Hydrocarbon and its subsidiaries, and approximately 4,050 subordinated units owned by Tortoise MWEP, L.P. in which Mr. Fox owns an equity interest. As of March 31, 2006, Mr. Fox beneficially owned approximately 43% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon's Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003, and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the common units and subordinated units owned by MarkWest Hydrocarbon.
(5): Information is based solely on a Schedule 13G filed with the Securities and Exchange Commission by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne, on February 9, 2006, with respect to units held as of December 31, 2005. The Schedule 13G indicates that Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne have shared voting power and dispositive power with respect to 1,670,380 units. The reported units are owned by investment accounts managed, with discretion to purchase or sell securities, by Kayne Anderson Capital Advisors, L.P., as a registered investment advisor. Kayne Anderson Capital Advisors, L.P. is the general partner of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital Advisors, L.P. disclaims beneficial ownership of the units reported, except those units attributable to it by virtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the units reported, except those units held by him or attributable to him by virtue of his limited partnership interests in the limited partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnership, and his ownership of common units of the registered investment company.
(6): Information is based solely on a Schedule 13G filed with the Securities and Exchange Commission by Tortoise Capital Advisors, L.L.C. ("TCA") and Tortoise Energy Infrastructure Corporation ("TYG"), a closed-end investment company on February 10, 2006. The Schedule 13G indicates that TCA acts as an investment advisor to TYG and that TCA, and by virtue of the Investment Advisory Agreement with TYG, has all investment and voting power over securities owned of record by TYG. Despite its delegation of investment and voting power to TCA, however, TYG may be deemed to be the beneficial owner under Rule 13d-3 of the Securities and Exchange Act of 1940, of the securities it owns of record because it has the right to acquire investment and voting power through termination of the Investment Advisory Agreement. Thus, TCA and TYG have reported that they share voting power and dispositive power over the securities owned of record by TYG. TCA also acts as an investment advisor to certain managed accounts. Under contractual agreements with individual account holders, TCA, with respect to the securities held in the managed accounts, shares investment and voting power with certain account holders, and has no voting power but shares investment power with certain other account holders. TCA may be deemed the beneficial owner under Rule 13d-3 of the Exchange Act of the securities covered by the Schedule 13G. None of the securities are owned of record by TCA, and TCA disclaims any beneficial interest in such shares.
(7): Tortoise Capital General Partner, L.C., the general partner of Tortoise MWEP, L.P., is a limited liability company whose sole member is TCA. Tortoise Capital General Partner, L.C. exercises voting and dispositive power with respect to the subordinated units held by Tortoise MWEP, L.P.

The following table sets forth the beneficial ownership of our general partner as of June 15, 2006, held by MarkWest Hydrocarbon, the directors of our general partner, each named executive officer and by all directors and officers of our general partner as a group.

Name of Beneficial Owner	Percentage of Limited Liability Company Interests Owned
MarkWest Hydrocarbon, Inc.	89.2	%
John M. Fox(1)	90.8
Frank M. Semple	2.0
James G. Ivey	0.5
Randy S. Nickerson	1.6
John C. Mollenkopf	1.6
David L. Young	—
Keith E. Bailey	—
Donald C. Heppermann	1.0
William A. Kellstrom	—
William P. Nicoletti	—
Charles K. Dempster	—
All directors and executive officers as a group (17 persons)	98.0

(1): Includes a 1.6% ownership interest held directly by Mr. Fox and an 89.2% ownership interest held by MarkWest Hydrocarbon. As of December 31, 2005, Mr. Fox beneficially owned approximately 43% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon's Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003, and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the ownership interests owned by MarkWest Hydrocarbon.

SELLING UNITHOLDERS

This prospectus covers the offering for resale of up to 3,820,097 common units by selling unitholders. Unless otherwise indicated, each of the selling unitholders acquired its common units in connection with our June 2003, July 2004, November 2005 or December 2005 private placements. We and the selling unitholders entered into various registration rights agreements in connection with those private placements. We are registering the common units described below pursuant to such registration rights agreements.

No offer or sale may be made by a unitholder unless that unitholder is listed in the table below. The selling unitholders may sell all, some or none of the common units covered by this prospectus. Please read "Plan of Distribuiton." We will bear all costs, fees and expenses incurred in connection with the registration of the common units offered by this prospectus. Brokerage commissions and similar selling expenses, if any, attributable to the sale of common units will be borne by the selling unitholders.

No such sales may occur unless the selling unitholder has notified us of his or her intention to sell our common units and this prospectus has been declared effective by the SEC, and remains effective at the time such selling unitholder offers or sells such common units. We are required to update this prospectus to reflect material developments in our business, financial position and results of operations.

The following table sets forth, the name of each selling unitholder, the amount of common units beneficially owned and the percentage of common units outstanding owned by each selling unitholder prior to the offering, the number of common units being offered for each selling unitholder's account, and the amount to be owned and the percentage of common units outstanding owned by each selling unitholder following the completion of the offering (assuming each selling unitholder sells all of the common units covered by this prospectus). The percentages of common units outstanding have been calculated based on 14,379,214 common units outstanding as of July 12, 2006. Unless otherwise indicated, the selling unitholders have held no position or office or had any other material relationship with us or any of our affiliates or predecessors, other than as a unitholder, during the past three years.

We have prepared the table and the related notes based on information supplied to us by the selling unitholders. We have not sought to verify such information. Additionally, some or all of the selling unitholders may have sold or transferred some or all of the units listed below in exempt or non-exempt transactions since the date on which the information was provided to us. Other information about the selling unitholders may change over time.

	Common Units Beneficially Owned Prior to this Offering			Common Units Beneficially Owned Following this Offering
Name of Selling Unitholder	Number	Percentage Owned	Units Offered in this Offering	Number	Percentage Owned
Kayne Anderson Energy Fund I, L.P.(1)	433,200	3.0	433,200	0	0
Kayne Anderson Capital Income Partners (QP), L.P.(1)	17,000	*	17,000	0	0
Kayne Anderson MLP Fund, L.P.(1)	280,587	2.0	72,000	208,587	1.5
Kayne Anderson Capital Income Fund, Ltd.(1)	14,000	*	14,000	0	0
Kayne Anderson Capital Income Partners, L.P.(1)	11,100	*	6,000	5,100	*
HFR RV Performance Master Trust(2)	20,300	*	5,800	14,500	*
Kayne Anderson MLP Investment Company(3)	871,680	6.1	678,580	193,100	1.3
Tortoise Energy Infrastructure Corporation(4)	805,810	5.6	579,710	226,100	1.6

Energy Income and Growth Fund(5)	230,178	1.6	144,928	85,250	*
Fiduciary/Claymore MLP Opportunity Fund(6)	299,347	2.1	113,097	186,250	1.3
Alerian Capital Partners LP(7)	80,935	*	63,335	17,600	*
Structured Finance Americas, LLC(8)	395,600	2.8	340,000	55,600	*
Credit Suisse Management LLC(9)	60,000	*	60,000	0	0
RCH Energy MLP Fund, L.P.(10)	184,182	1.3	110,982	73,200	*
RCH Energy MLP Fund-A, L.P.(10)	2,115	*	2,115	0	0
RCH Energy Opportunity Fund , L.P.(11)	341,137	2.4	341,137	0	0
Fort Mason Partners, L.P.(12)	9,800	*	9,800	0	0
Fort Mason Master, L.P.(12)	151,120	1.0	151,120	0	0
Swank MLP Convergence Fund, LP(13)	327,485	2.3	229,885	97,600	*
Eagle Income Appreciation Partners, L.P.(14)	121,766	*	68,966	52,800	*
Royal Bank of Canada(15)	73,877	*	49,762	24,115	*
Delmar Equity Partners, L.P.(16)	35,947	*	19,062	16,885	*
Jeane Marie Swalm(17)	4,547	*	4,547	0	0
Robert A. Tucci and Cynthia L. Tucci TEN(18)	3,731	*	3,731	0	0
Evan D. Jennings, II(19)	16,000	*	16,000	0	0
Lewis E. Nerman Revocable Trust Dtd 10/19/89, as amended, Lewis E. Nerman, Trustee(17)	28,757	*	15,249	13,508	*
Richard B. Klein Revocable Trust dated 6/08/1993, Richard B. Klein and Lynn M. Klein, Trustees(17)	6,031	*	6,031	0	0
Jerome S. Nerman Trust UA dated 11/08/88, Jerome S. Nerman, Trustee(17)	7,624	*	7,624	0	0
Gary M. Truitt and Kay Lee Truitt JT TEN(18)	16,067	*	7,624	8,443	*
Laura Marcia Wolff Greenbaum Trust Dated 9/20/78, Laura W. Greenbaum Trustee(17)	3,960	*	2,268	1,692	*
Peter P. Dreher and Nancy D. Dreher JT TEN(17)	1,000	*	1,000	0	0
Thomas M. Cray Revocable Trust dated 10/9/2000, Thomas M. Cray Trustee(17)	1,906	*	1,906	0	0
Robyn R. Schneider Revocable Trust dated 3/25/99, Robyn R. Schneider Trustee(20)	1,000	*	1,000	0	0
Sandra H. Fried Trust U/I/T Dated July 25, 1996, as amended and restated July 25, 2002, Sandra H. Fried Trustee(17)	1,906	*	1,906	0	0
Stuart M. Bauman Revocable Trust U/A Dtd. 1/28/93, Stuart M. Bauman, Trustee(19)	1,143	*	1,143	0	0
Cara Zanotti Newell(21)	953	*	953	0	0
Charles M. Newell(19)	953	*	953	0	0

James Thomas and Cynthia F. Burcham; JTWROS(19)		7,624	*	7,624	0	0
H. Kevin Birzer(22)		3,924	*	3,813	111	*
KC Partners in Growth(23)		3,812	*	3,812	0	0
IMREX Partners, L.P.(25)		762	*	762	0	0
Ellen E. Schulte(22)		2,978	*	1,965	1,013	*
Douglas E. Campbell(24)		1,906	*	1,906	0	0
Donald W. Trotter(24)		1,143	*	1,143	0	0
Larry H. Powell(24)		1,064	*	953	111	*
Terry Matlack(24)		2,787	*	1,583	1,204	*
Steven W. Satkamp(24)		7,624	*	7,624	0	0
Gregory S. and Elizabeth B. Maday, JWTROS(24)		20,180	*	6,672	13,508	*
Zachary A. Hamel(24)		1,486	*	953	533	*
Kenneth P. Malvey(24)		1,521	*	953	568	*
SLK Family Trust, Sharon L. Kessler, Trustee(24)		750	*	750	0	0
Frank M. Semple(26)		13,734	*	5,000	8,734	*
John M. Fox(27)		44,731	*	4,626	40,105	*
John C. Mollenkopf(28)		7,936	*	4,626	3,310	*
Randy S. Nickerson(29)		12,495	*	4,626	7,869	*
Arthur J. Denney(30)		8,876	*	4,626	4,250	*
Donald C. Heppermann(31)		11,667	*	4,000	7,667	*
Andrew Schroeder(32)		2,203	*	1,500	703	*
Ted S. Smith(33)		2,720	*	1,500	1,220	*
Tortoise MWEP, L.P.(34)		166,666	1.1	166,666	0	0
	Total:	5,191,323	36.1	3,820,097	1,370,486	9.5

*: Less than 1%.
(1): As of March 27, 2006. Richard A. Kayne, in his capacity as the controlling stockholder of Kayne Anderson Investment Management, Inc. ("Kayne Management"), the ultimate parent of the selling unitholder, may be deemed to have voting and dispositive power with respect to the units held by the selling unitholder. KA Associates, Inc., an affiliate of the selling unitholder, is a broker-dealer registered pursuant to Section 15(b) of the Securities and Exchange Act of 1934, as amended (the "Exchange Act") and is a member of the National Association of Securities Dealers, Inc., or NASD. The selling unitholder has represented that (i) it purchased the securities for the selling unitholder's own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing such securities in any transaction in violation of securities laws and (ii) at the time of purchase, the selling unitholder did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the purchased securities.
(2): As of March 27, 2006. Pursuant to investment advisory agreements entered into with the selling unitholder, Kayne Anderson Capital Advisors, L.P. ("Kayne Advisors") has voting and dispositive power with respect to the units held by the selling unitholder. Richard A. Kayne, in his capacity as the controlling stockholder of Kayne Management, the general partner of Kayne Advisors, may be

deemed to have voting and dispositive power with respect to the units held by the selling unitholder.

(3): As of March 28, 2006. The selling unitholder is a publicly-held closed-end fund. Pursuant to investment advisory agreements entered into with the selling unitholder, Kayne Advisors has voting and dispositive power with respect to the units held by the selling unitholder. Richard A. Kayne, in his capacity as the controlling stockholder of Kayne Management, the general partner of Kayne Advisors, may be deemed to have voting and dispositive power over the units held by the selling unitholder.
(4): As of March 27, 2006. Tortoise Capital Advisors, L.L.C. ("TCA") serves as the investment advisor to the selling unitholder. Pursuant to a Investment Advisory Agreement entered into with the selling unitholder, TCA holds voting and dispositive power with respect to the units held by the selling unitholder. The investment committee of TCA is responsible for the investment management of the selling unitholder's portfolio. The investment committee is comprised of H. Kevin Birzer, Zachary A. Hamel, Kenneth P. Malvey, Terry C. Matlack and David J. Schulte.
(5): As of March 24, 2006. Does not include 431,957 common units controlled and managed by Fiduciary Asset Management, LLC ("FAMCO"), an affiliate of the selling unitholder. Pursuant to investment advisory agreements entered into with the selling unitholder, FAMCO holds voting and dispositive power with respect to the units held by the selling unitholder. The investment committee of FAMCO is responsible for the investment management of the selling unitholder's portfolio. The investment committee of FAMCO is comprised of Charles D. Walbrandt, Wiley D. Angell, Joseph E. Gallager, James J. Cunnane, Jr., Mohammed Riad, Thomas L. Engle, Timothy Swanson, Quinn T. Kiley, Katherine K. Dienner and William N. Adams. First Trust Portfolios L.P., an affiliate of the selling unitholder, is a broker-dealer registered pursuant to Section 15(b) of the Exchange Act and a member of the NASD. The selling unitholder has represented that (i) it purchased the securities for the selling unitholder's own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing such securities in any transaction in violation of securities laws and (ii) at the time of purchase, the selling unitholder did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the purchased securities.
(6): As of March 24, 2006. Does not include 463,788 common units controlled and managed by Fiduciary Asset Management, LLC ("FAMCO"), an affiliate of the selling unitholder. Pursuant to investment advisory agreements entered into with the selling unitholder, FAMCO holds voting and dispositive power with respect to the units held by the selling unitholder. The investment committee of FAMCO is responsible for the investment management of the selling unitholder's portfolio. The investment committee of FAMCO is comprised of Charles D. Walbrandt, Wiley D. Angell, Joseph E. Gallager, James J. Cunnane, Jr., Mohammed Riad, Thomas L. Engle, Timothy Swanson, Quinn T. Kiley, Katherine K. Dienner and William N. Adams. Claymore Securities, Inc., an affiliate of the selling unitholder, is a broker-dealer registered pursuant to Section 15(b) of the Exchange Act and a member of the NASD. The selling unitholder has represented that (i) it purchased the securities for the selling unitholder's own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing such securities in any transaction in violation of securities laws and (ii) at the time of purchase, the selling unitholder did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the purchased securities.
(7): As of March 23, 2006. Alerian Capital Management LLC ("Alerian Management") holds voting and dispositive power with respect to the units held by the selling unitholder Gabriel Hammond, in his capacity controlling shareholder of Alerian Management, may be deemed to have voting and dispositive power with respect to the units held by the selling unitholder.

(8): As of March 27, 2006. Deutsche Bank AG, a German banking corporation, holds voting and dispositive power with respect to the shares held by the selling unitholder. Deutsche Bank Securities Inc., an affiliate of the selling unitholder, is a broker-dealer registered pursuant to Section 15(b) of the Exchange Act and a member of the NASD. The selling unitholder has represented that (i) it purchased the securities for the selling unitholder's own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing such securities in any transaction in violation of securities laws and (ii) at the time of purchase, the selling unitholder did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the purchased securities.
(9): As of March 27, 2006. Credit Suisse (USA) Inc., a Delaware corporation ("CSFB-USA"), holds voting and dispositive power with respect to the shares held by the selling unitholder. Credit Suisse, a Swiss bank (the "Bank"), owns the majority of the voting stock of Credit Suisse Holdings (USA), Inc., a Delaware corporation, which in turn owns all of the voting stock of CSFB-USA. The ultimate parent company of the Bank is Credit Suisse Group ("CSG"). CSG disclaims beneficial ownership of the reported common stock that is beneficially owned by its direct and indirect subsidiaries. Credit Suisse Securities (USA) LLC, an affiliate of the selling unitholder, is a broker-dealer registered pursuant to Section 15(b) of the Exchange Act and a member of the NASD. The selling unitholder has represented that (i) it purchased the securities for the selling unitholder's own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing such securities in any transaction in violation of securities laws and (ii) at the time of purchase, the selling unitholder did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the purchased securities.
(10): As of March 28, 2006. The general partner of the selling unitholder is RCH Energy MLP Fund GP, L.P. ("RCH MLP"). Robert J. Raymond, as member of RR Advisors, LLC, the general partner of RCH MLP, exercises voting and dispositive power with respect to the units held by the selling unitholder.
(11): As of March 28, 2006. The general partner of the selling unitholder is RCH Energy Opportunity Fund I GP, L.P. ("RCH Opportunity"). Robert J. Raymond, as member of RR Advisors, LLC, the general partner of RCH Opportunity, exercises voting and dispositive power with respect to the units held by the selling unitholder.
(12): As of March 23, 2006. Fort Mason Capital, LLC serves as the general partner and/or investment advisor to the selling unitholder and, in such capacity, exercises sole voting and investment authority with respect to such units, Daniel German serves as the sole managing member of Fort Mason Capital, LLC. Fort Mason Capital, LLC and Mr. German each disclaim beneficial ownership of such units, except to the extent of its or his pecuniary interest therein, if any.
(13): As of March 22, 2006. Swank Energy Income Advisors, L.P. ("Swank Advisors") holds voting and dispositive power with respect to the units held by the selling unitholder. Jerry V. Swank, as controlling shareholder of Swank Group, LLC, the general partner of Swank Advisors, may be deemed to have voting and dispositive power with respect to the units held by the selling unitholder.
(14): As of March 22, 2006. Eagle Global Advisors, LLC holds voting and dispositive power with respect to the units held by the selling unitholder. The shareholders of Eagle Global Advisors, LLC are Edward R. Allen, III, Thomas N. Hunt, III, Steven Russo, John Gualy and Malcom Day.
(15): As of April 4, 2006. The selling unitholder, a publicly-traded banking corporation, exercises voting and dispositive power with respect to the units held by the selling unitholder. The selling unitholder serves as administrative agent and lead arranger for our credit facility and MarkWest

Hydrocarbon's revolving credit facility and receives customary fees for such services in the ordinary course of business. RBC Capital Markets Corporation ("RBC Capital Markets"), an affiliate of the selling unitholder, in the ordinary course of business, provides us with financial advisory and investment banking services in exchange for customary fees and expenses. In connection with these services, RBC Capital Markets served as an underwriter in our January 2004 and September 2004 common unit offerings and as an initial purchaser in our November 2004 private placement of senior notes. RBC Capital Markets is a broker-dealer registered pursuant to Section 15(b) of the Exchange Act and a member of the NASD. The selling unitholder has represented that (i) it purchased the securities for the selling unitholder's own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing such securities in any transaction in violation of securities laws and (ii) at the time of purchase, the selling unitholder did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the purchased securities.

(16): As of March 28, 2006. Mark R. Truitt and Linda A Truitt exercise joint voting and dispositive power of the units held by the selling unitholder.
(17): As of March 29, 2006.
(18): As of March 28, 2006.
(19): As of March 30, 2006.
(20): As of March 25, 2006.
(21): As of March 27, 2006.
(22): As of April 4, 2006.
(23): As of March 31, 2006. Kenneth P. Malvey exercises voting and dispositive power with respect to the shares held by the selling unitholder.
(24): As of March 31, 2006.
(25): As of March 31, 2006. Terry Matlack, Timothy Matlack, Rex Matlack and Cindy Matlack Manley exercise joint voting and dispositive power with respect to the units held by the selling unitholder.
(26): As of April 4, 2006. Mr. Semple serves as President and Chief Executive Officer of MarkWest Hydrocarbon and our general partner and as a director of our general partner. The common units being offered by Mr. Semple were acquired upon the conversion of subordinated units acquired pursuant to the MarkWest Hydrocarbon Participation Plan.
(27): As of April 4, 2006. Mr. Fox serves as Chairman of the Board of MarkWest Hydrocarbon and our general partner. The common units being offered by Mr. Fox were acquired upon the conversion of subordinated units acquired pursuant to the MarkWest Hydrocarbon Participation Plan.
(28): As of April 4, 2006. Mr. Mollenkopf serves as Senior Vice President, Southwest Business Unit, of MarkWest Hydrocarbon and our general partner. The common units being offered by Mr. Mollenkopf were acquired upon the conversion of subordinated units acquired pursuant to the MarkWest Hydrocarbon Participation Plan.
(29): As of April 4, 2006. Mr. Nickerson serves as Senior Vice President, Corporate Development, of MarkWest Hydrocarbon and our general partner. The common units being offered by Mr. Nickerson were acquired upon the conversion of subordinated units acquired pursuant to the MarkWest Hydrocarbon Participation Plan.

(30): As of April 4, 2006. Mr. Denney served as Senior Vice President and Chief Operating Officer of MarkWest Hydrocarbon and our general partner until February 2004. The common units being offered by Mr. Denney were acquired upon the conversion of subordinated units acquired pursuant to the MarkWest Hydrocarbon Participation Plan.
(31): As of April 4, 2006. Mr. Heppermann served as Executive Vice President, Chief Financial Officer and Secretary of MarkWest Hydrocarbon and our general partner until his retirement in March 2004. The common units being offered by Mr. Hepperman were acquired upon the conversion of subordinated units acquired pursuant to the MarkWest Hydrocarbon Participation Plan.
(32): As of April 4, 2006. Mr. Schroeder serves as Vice President, Finance and Treasurer of MarkWest Hydrocarbon and our general partner. The common units being offered by Mr. Schroeder were acquired upon the conversion of subordinated units acquired pursuant to the MarkWest Hydrocarbon Participation Plan.
(33): As of April 4, 2006. Mr. Smith previously served as Controller and Chief Accounting Officer of MarkWest Hydrocarbon and our general partner. The common units being offered by Mr. Smith were acquired upon the conversion of subordinated units acquired pursuant to the MarkWest Hydrocarbon Participation Plan.
(34): As of March 27, 2006. The common units attributed to the selling unitholder represent common units underlying subordinated units held by the selling unitholder. The subordinated units held by the selling unitholder will convert into common units on a one-for-one basis as described in "Cash Distribution Policy—Subordination Period." The subordinated units were acquired by the selling unitholder in connection with the private placement of our subordinated units by Markwest Hydrocarbon in November 2002. The common units underlying the subordinated units held by the selling unitholder are being registered pursuant to a registration rights agreement among us, MarkWest Hydrocarbon and the selling unitholder. Tortoise Capital General Partner, L.C., the general partner of the selling unitholder, is a limited liability company whose sole member is Tortoise Capital Advisors, L.L.C. The investment committee of Tortoise Capital Advisors L.L.C. is comprised of H. Kevin Birzer, Zachary A. Hamel, Kenneth P. Malvey, Terry C. Matlack and David J. Schulte. Tortoise Capital General Partner, L.C. exercises voting and dispositive power with respect to the subordinated units held by the selling unitholder.

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including MarkWest Hydrocarbon), on the one hand, and us, and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage MarkWest Energy Partners, L.P., in a manner beneficial to us and our unitholders. In addition, officers of our general partner and officers and key employees of MarkWest Hydrocarbon also own 10.3% of the membership interests in our general partner, a significant equity stake in MarkWest Hydrocarbon and own approximately 1.0% of the limited partner interests in us.

The partnership agreement contains provisions that allow our general partner to take into account the interests of parties in addition to our interests when resolving conflicts of interest. In effect, these provisions limit our general partner's fiduciary duties to the unitholders. The partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty. Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us. or any other partner, on the other, our general partner will resolve that conflict. At the request of our general partner, a conflicts committee of the board of directors of our general partner will review conflicts of interest. Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or the unitholders if the resolution of the conflict is considered fair and reasonable to us. Any resolution is considered fair and reasonable to us if that resolution is:

•: approved by the conflicts committee, although no party is obligated to seek the approval of the Conflicts Committee and our general partner may adopt a resolution or course of action that has not received approval;
•: on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•: fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Unless the resolution is specifically provided for in the partnership agreement, when resolving a conflict, our general partner may consider:

•: the relative interests of the parties involved in the conflict or affected by the action;
•: any customary or accepted industry practices or historical dealings with a particular person or entity; and
•: generally accepted accounting practices or principles and other factors it considers relevant, if applicable.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•: amount and timing of asset purchases and sales;
•: cash expenditures;
•: borrowings;

•: issuance of additional units; and
•: the creation, reduction or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•: enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or
•: hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, the partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "Cash Distribution Policy—Subordination Period."

The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, the operating company or the subsidiaries.

We do not have any officers or employees and rely solely on officers of our general partner and employees of MarkWest Hydrocarbon and its affiliates.

We do not have any officers or employees and rely solely on officers and employees of MarkWest Hydrocarbon and its affiliates. MarkWest Hydrocarbon and its affiliates conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of our general partner are not required to work full time on our affairs. These officers are required to devote significant time to the affairs of MarkWest Hydrocarbon or its affiliates and are compensated by them for the services rendered to them.

We reimburse our general partner, MarkWest Hydrocarbon and its affiliates for expenses.

We reimburse our general partner, MarkWest Hydrocarbon and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. See Item 13. "Certain Relationships and Related Transactions—Omnibus Agreement—Services" incorporated by reference to our Annual Report on Form 10-K for the year ended December 31, 2005, as amended.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets or any affiliate of the general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its or our liability is not a breach of our general partner's fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.

The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered, provided these services are rendered on terms that are fair and reasonable to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. However, all of these transactions are to be on terms that are fair and reasonable to us.

Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Common units are subject to our general partner's limited call right.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."

We may not choose to retain separate counsel for ourselves or for the holders of common units.

Attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner's affiliates may compete with us.

The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in the partnership agreement and the omnibus agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement.

Our general partner is accountable to us and our unitholders as a fiduciary. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides

that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by our general partner to limited partners and us.

Our partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner's board of directors have fiduciary duties to manage our general partner in a manner beneficial both to its owners, MarkWest Hydrocarbon, as well as to you. Without these modifications, the general partner's ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards benefit the general partner by enabling it to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us as described above. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to the common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State-law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for us in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement permits our general partner to make a number of decisions in its "sole discretion." This entitles our general partner to consider only the interests and factors that it desires and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Other provisions of the partnership agreement provide that our general partner's actions must be made in its reasonable discretion. These standards reduce the obligations to which our general partner would otherwise be held. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be "fair and reasonable" to us under the factors previously set forth. In determining whether a transaction or resolution is "fair and reasonable," our general partner may consider interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty. These standards reduce the obligations to which our general partner would otherwise be held.

		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, the limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith.
Rights and Remedies of unitholders		The Delaware Act generally provides that a limited partner may institute legal action on behalf of us to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions could include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification if our general partner or these persons acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than our general partner) not opposed to, our best interests. We also must provide this indemnification for criminal proceedings if our general partner or these other persons had no reasonable cause to believe their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met these requirements concerning good faith and our best interests. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the Securities and Exchange Commission, such indemnification is contrary to public policy and therefore unenforceable. If you have questions regarding the fiduciary duties of our general partner, you should consult with your own counsel. Please read "The Partnership Agreement—Indemnification."

THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. Our partnership agreement and the limited liability company agreement governing our operating company are included as exhibits to the registration statement of which this prospectus constitutes a part. We will provide prospective investors with a copy of these agreements upon request at no charge.

We summarize the following provisions of the partnership agreement elsewhere in this prospectus:

•: with regard to distributions of available cash, please read "Cash Distribution Policy."
•: with regard to the transfer of common units, please read "Description of the Common Units—Transfer of Common Units."
•: with regard to allocations of taxable income and taxable loss, please read "Material Tax Consequences."

Organization and Duration

We were organized on January 25, 2002 and will have a perpetual existence.

Purpose

Our purpose under the partnership agreement is limited to serving as a member of the operating company and engaging in any business activities that may be engaged in by the operating company or that are approved by our general partner. All of our operations are conducted through our operating company, MarkWest Energy Operating Company, L.L.C., and its subsidiaries. We own 100% of the outstanding membership interest of the operating company. The limited liability company agreement of the operating company provides that the operating company may, directly or indirectly, engage in:

•: its operations as conducted immediately before our initial public offering;
•: any other activity approved by our general partner but only to the extent that our general partner reasonably determines that, as of the date of the acquisition or commencement of the activity, the activity generates "qualifying income" as this term is defined in Section 7704 of the Internal Revenue Code; or
•: any activity that enhances the operations of an activity that is described in either of the two preceding clauses or any other activity provided such activity does not affect our treatment as a partnership for Federal income tax purposes.

Our general partner is authorized in general to perform all acts deemed necessary to carry out our purposes and to conduct our business.

Power of Attorney

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

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

•: to remove or replace our general partner;
•: to approve some amendments to the partnership agreement; or
•: to take other action under the partnership agreement;

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the Partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to us, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in multiple states. Maintenance of our limited liability as a member of the operating company may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of members for the obligations of a limited liability company have not been clearly established in many jurisdictions. If, by virtue of our membership interest in the operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Voting Rights

The following matters require the unitholder vote specified below. Matters requiring the approval of a "unit majority" require:

•: during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and
•: after the subordination period, the approval of a majority of the common units.

Issuance of additional common units or units of equal rank with the common units during the subordination period		Unit majority, with certain exceptions described under "—Issuance of Additional Securities."
Issuance of units senior to the common units during the subordination period		Unit majority.
Issuance of units junior to the common units during the subordination period		No approval right.
Issuance of additional units after the subordination period		No approval rights.
Amendment of the partnership agreement		Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. See "—Amendment of the Partnership Agreement."
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority. See "—Merger, Sale or Other Disposition of Assets."
Amendment of the limited liability company agreement and other action taken by us as sole member of the operating company		Unit majority if such amendment or other action would adversely affect our limited partners (or any particular class of limited partners) in any material respect. See "—Action Relating to the Operating Company."
Dissolution of our partnership		Unit majority. See "—Termination and Dissolution."
Reconstitution of our partnership upon dissolution		Unit majority. See "—Termination and Dissolution."

Withdrawal of the general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required for the withdrawal of the general partner prior to June 30, 2012 in a manner which would cause a dissolution of our partnership. See "—Withdrawal or Removal of our General Partner."
Removal of the general partner		Not less than 66²/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. See "—Withdrawal or Removal of our General Partner."
Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to June 30, 2012. See "—Transfer of General Partner Interests."
Transfer of incentive distribution rights		Except for transfers to an affiliate or another person as part of the general partner's merger or consolidation with or into, or sale of all or substantially all of its assets to or sale of all or substantially all its equity interests to such person, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, voting separately as a class, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to June 30, 2012. See "—Transfer of Incentive Distribution Rights."
Transfer of ownership interests in the general partner		No approval required at any time. See "—Transfer of Ownership Interests in the General Partner."

Issuance of Additional Securities

The partnership agreement authorizes us to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the consideration and on the terms and conditions established by our general partner in its sole discretion without the approval of the unitholders. During the subordination period, however, except as we discuss in the following paragraph, we may not issue equity securities ranking senior to the common units or an aggregate of more than 1,207,500 additional common units or units on a parity with the common units, in each case, without the approval of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes.

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

•: upon exercise of an underwriters' over-allotment option;
•: upon conversion of the subordinated units;
•: under employee benefit plans;

•: upon conversion of the general partner interest and incentive distribution rights as a result of a withdrawal of our general partner;
•: in the event of a combination or subdivision of common units;
•: in connection with an acquisition or a capital improvement that increases cash flow from operations per unit on a pro forma basis; or
•: if the proceeds of the issuance are used exclusively to repay indebtedness the cost of which to service is greater than the distribution obligations associated with the units issued in connection with its retirement.

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

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

Upon issuance of additional partnership securities, our general partner will be required to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain its percentage interest, including its interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General. Amendments to the partnership agreement may be proposed only by or with the consent of our general partner, which consent may be given or withheld in its sole discretion, except as discussed below. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as we describe below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would:

•: enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected;
•: enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld in its sole discretion;
•: change the term of our partnership;
•: provide that our partnership is not dissolved upon an election to dissolve our partnership by our general partner that is approved by a unit majority; or

•: give any person the right to dissolve our partnership other than our general partner's right to dissolve our partnership with the approval of a unit majority.

The provision of the partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class.

No Unitholder Approval. Our general partner may generally make amendments to the partnership agreement without the approval of any limited partner or assignee to reflect:

•: a change in our name, the location of our principal place of business, our registered agent or our registered office;
•: the admission, substitution, withdrawal, or removal of partners in accordance with the partnership agreement;
•: a change that, in the sole discretion of our general partner, is necessary or advisable for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, the operating company nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
•: an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or plan asset regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed;
•: subject to the limitations on the issuance of additional partnership securities described above, an amendment that in the discretion of our general partner is necessary or advisable for the authorization of additional partnership securities or rights to acquire partnership securities;
•: any amendment expressly permitted in the partnership agreement to be made by our general partner acting alone;
•: an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the partnership agreement;
•: any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by the partnership agreement;
•: a change in our fiscal year or taxable year and related changes; or
•: any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to the partnership agreement without the approval of any limited partner or assignee if those amendments, in the discretion of our general partner:

•: do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;
•: are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
•: are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited

partner interests are or will be listed for trading, compliance with any of which our general partner deems to be in our best interest and the best interest of the limited partners;

•: are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of the partnership agreement; or
•: are required to effect the intent expressed in this prospectus or the intent of the provisions of the partnership agreement or are otherwise contemplated by the partnership agreement.

Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under "—No Unitholder Approval" should occur. No other amendments to the partnership agreement will become effective without the approval of holders of at least 90% of the units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners or cause us, the operating company or its subsidiaries to be taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously taxed as such).

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

Action Relating to the Operating Company

Without the approval of the holders of units representing a unit majority, our general partner is prohibited from consenting on our behalf, as the sole member of the operating company, to any amendment to the limited liability company agreement of the operating company or taking any action on our behalf permitted to be taken by a member of the operating company in each case that would adversely affect our limited partners (or any particular class of limited partners) in any material respect.

Merger, Sale or Other Disposition of Assets

The partnership agreement generally prohibits our general partner, without the prior approval of the holders of units representing a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries as a whole. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.

If conditions specified in the partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to change our legal form into another limited liability entity. The unitholders are not entitled to dissenters' rights of appraisal under the partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event for such purpose.

Termination and Dissolution

We will continue as a limited partnership until terminated under the partnership agreement. We will dissolve upon:

•: the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
•: the sale, exchange or other disposition of all or substantially all of our assets and properties and our subsidiaries;
•: the entry of a decree of judicial dissolution of the Partnership; or
•: the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with the partnership agreement or withdrawal or removal of the general partner following approval and admission of a successor.

Upon a dissolution under the last clause, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may also elect, within specific time limitations, to reconstitute us and continue our business on the same terms and conditions described in the partnership agreement by forming a new limited partnership on terms identical to those in the partnership agreement and having as general partner an entity approved by the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, subject to our receipt of an opinion of counsel to the effect that:

•: the action would not result in the loss of limited liability of any limited partner; and
•: neither we, the reconstituted limited partnership nor the operating company would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in "Cash Distribution Policy—Distributions of Cash upon Liquidation." The liquidator may defer liquidation of our assets for a reasonable period or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2012 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2012, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of the partnership agreement. Notwithstanding the foregoing, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interests."

Upon the withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates would give it the practical ability to prevent its removal. As of March 31, 2006, affiliates of our general partner owned approximately 19.2% of the outstanding units.

The partnership agreement also provides that if our general partner is removed under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

•: the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
•: any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
•: our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates the partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for the fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including

severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interests

Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:

•: an affiliate of our general partner (other than an individual); or
•: another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner interest in us to another person prior to June 30, 2012 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in General Partner

At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner without the approval of the unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder of the incentive distribution rights may transfer its incentive distribution rights to an affiliate or another person as part of its merger or consolidation with or into, or sale of all or substantially all of its assets to, or a sale of all or substantially all of its equity interests to, that person without the prior approval of the unitholders; but, in each case, the transferee must agree to be bound by the provisions of the partnership agreement. Prior to June 30, 2012, other transfers of the incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by the general partner and its affiliates. On or after June 30, 2012, the incentive distribution rights will be freely transferable.

Change of Management Provisions

The partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove MarkWest Energy GP, L.L.C. as our general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors.

•: the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
•: any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
•: our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Limited Call Right

If at any time our general partner and its affiliates hold more than 80% of the then-issued and outstanding partnership securities of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining partnership securities of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:

•: the highest cash price paid by either of our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those partnership securities; and
•: the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner's right to purchase outstanding partnership securities, a holder of partnership securities may have his partnership securities purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Tax Consequences—Disposition of Common Units."

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will

constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as the partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under the partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner or Assignee

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

An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a substituted limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee that has not become a substitute limited partner at the written direction of the assignee. See "—Meetings; Voting." Transferees that do not execute and deliver a transfer application will not be treated as assignees nor as record holders of common units, and will not receive cash distributions, federal income tax allocations or reports furnished to holders of common units. Please read "Description of the Common Units—Transfer of Common Units."

Non-citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem the units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee that is not a substituted limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Indemnification

Under the partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•: our general partner;
•: any departing general partner;
•: any person who is or was an affiliate of a general partner or any departing general partner;
•: any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any departing general partner or any affiliate of a general partner or any departing general partner; or
•: any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of a general partner or any departing general partner as an officer, director, employee, member, partner, agent or trustee of another person.

Any indemnification under these provisions will only be out of our assets. Our general partner and its affiliates will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the partnership agreement.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect our Books and Records

The partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

•: a current list of the name and last known address of each partner;
•: a copy of our tax returns;
•: information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

•: copies of the partnership agreement, the certificate of limited partnership of the Partnership, related amendments and powers of attorney under which they have been executed;
•: information regarding the status of our business and financial condition; and
•: any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under the partnership agreement, we have agreed to register for resale under the Securities Act of 1933 and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates (including MarkWest Hydrocarbon, its officers and the officers, directors and owners of our general partner) or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of MarkWest Energy GP, L.L.C. as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."

MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based on current provisions of the Internal Revenue Code, existing and proposed regulations to the extent noted and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are to MarkWest Energy Partners and the operating partnership.

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

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.

No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne directly or indirectly by the unitholders and the general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

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

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

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

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

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, even if no cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of his adjusted basis in his partnership interest.

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

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

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

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

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

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

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated

earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

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

Limited Partner Status

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

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

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

will be treated as partners of MarkWest Energy Partners for federal income tax purposes.

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

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

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

Tax Consequences of Unit Ownership

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

Treatment of Distributions. Cash distributions made by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in

excess of his tax basis in his common units generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. To the extent that cash distributions made by us cause a unitholder's "at risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution of cash to that unitholder. A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, and/or substantially appreciated "inventory items," both as defined in Section 751 of the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

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

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

In general, a unitholder will be at risk to the extent of his tax basis in his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment, or any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement. A unitholder's at-risk amount will increase or decrease as the

tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder's investments in other publicly-traded partnerships, or salary or active business income. Similarly, a unitholder's share of our net income may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

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

•: interest on indebtedness properly allocable to property held for investment;
•: our interest expense attributable to portfolio income; and
•: the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

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

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

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in

accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or that incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of those distributions. If we have a net loss for the entire year, that amount of loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and then to our general partner.

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

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

•: his relative contributions to us;
•: the interests of all the partners in profits and losses;
•: the interest of all the partners in cash flow; and
•: the rights of all the partners to distributions of capital upon liquidation.

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

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

•: any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
•: any cash distributions received by the unitholder as to those units would be fully taxable; and
•: all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short

seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

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

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

Section 754 Election. We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us and it belongs only to the purchaser and not to other unitholders. Please also read, however, "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction." For purposes of this discussion, a unitholder's inside basis in our assets has two components: (1) his share of our tax basis in our assets ("common basis") and (2) his Section 743(b) adjustment to that basis.

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

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

in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Tax Treatment of Operations—Uniformity of Units."

A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

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

Tax Treatment of Operations

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

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

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

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

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

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

Disposition of Common Units

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

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

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

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

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

•: a short sale;
•: an offsetting notional principal contract; or
•: a futures or forward contract with respect to the partnership interest or substantially identical property.

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

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

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

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

Notification Requirements. A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of substantial penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

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

Uniformity of Units

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

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6) which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material

adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Tax-Exempt Organizations and Other Investors

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

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

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

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

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

Administrative Matters

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

contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

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

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

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

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

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

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

(b) whether the beneficial owner is

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

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

(3) a tax-exempt entity;

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

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed

by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

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

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

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

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

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

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

Reportable Transactions. If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read "—Information Returns and Audit Procedures."

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

•: accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at "—Accuracy-related Penalties,"
•: for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability and
•: in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any "reportable transactions."

Registration as a Tax Shelter. We registered as a "tax shelter" under the law in effect at the time of our initial public offering and were assigned tax shelter registration number 0218400024. Issuance of a tax shelter registration number to us does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS. The American Jobs Creation Act of 2004 (the "Jobs Act") repealed the tax shelter registration rules and replaced them with a new reporting regime. However, IRS Form 8271, as revised after the Jobs Act, nevertheless requires a unitholder to continue to report our tax shelter registration number on the unitholder's tax return for any year in which the unitholder claims any deduction, loss or other benefit, or reports any income, with respect to our common units. The IRS also appears to take the position that a unitholder who sells or transfers our common units after the Jobs Act must continue to provide our tax shelter registration number to the transferee. Unitholders are urged to consult their tax advisors regarding the application of the tax shelter registration rules.

State, Local and Other Tax Considerations

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

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

INVESTMENT IN MARKWEST ENERGY PARTNERS BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

(a) whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

(b) whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and

(c) whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be fiduciaries of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things,

(a) the equity interests acquired by employee benefit plans are publicly offered securities; i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws,

(b) the entity is an "operating company," that is, it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries, or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding some interests held by our general partner, its affiliates, and some other persons, is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units are urged to consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

DESCRIPTION OF COMMON UNITS

The Units

The common units and the subordinated units represent limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read "Cash Distribution Policy" and "Description of the Subordinated Units." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

Transfer Agent and Registrar

Duties

Computershare Trust Company, Inc. serves as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by unitholders:

•: surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
•: special charges for services requested by a holder of a common unit; and
•: other similar fees or charges.

There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a transfer application. By executing and delivering a transfer application, the transferee of common units:

•: becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;
•: automatically requests admission as a substituted limited partner in our partnership;
•: agrees to be bound by the terms and conditions of, and executes, our partnership agreement;
•: represents that the transferee has the capacity, power and authority to enter into the partnership agreement;

•: grants powers of attorney to officers of our general partner and any liquidator of us as specified in the partnership agreement; and
•: makes the consents and waivers contained in the partnership agreement.

An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. Our general partner may withhold its consent in its sole discretion.

A transferee's broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a transfer application obtains only:

•: the right to assign the common unit to a purchaser or other transferee; and
•: the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.

Thus, a purchaser or transferee of common units who does not execute and deliver a transfer application:

•: will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or "street name" account and the nominee or broker has executed and delivered a transfer application; and
•: may not receive some federal income tax information or reports furnished to record holders of common units.

The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to insure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application to the transfer agent. Please read "The Partnership Agreement—Status as Limited Partner or Assignee."

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or applicable stock exchange regulations.

PLAN OF DISTRIBUTION

We are registering the common units on behalf of the selling unitholders. As used in this prospectus, "selling unitholders" includes donees and pledgees selling common units received from a named selling unitholder after the date of this prospectus.

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

•: through one or more broker-dealers;
•: through underwriters; or
•: directly to investors.

The selling unitholders may price the common units offered from time to time:

•: at fixed prices;
•: at market prices prevailing at the time of any sale under this registration statement;
•: at prices related to prevailing market prices;
•: varying prices determined at the time of sale; or
•: at negotiated prices.

We will pay the costs and expenses of the registration and offering of the common units offered hereby. We will not pay any underwriting fees, discounts and selling commissions allocable to each selling unitholder's sale of its respective common units, which will be paid by the selling unitholders. Broker-dealers may act as agent or may purchase securities as principal and thereafter resell the securities from time to time:

•: in or through one or more transactions (which may involve crosses and block transactions) or distributions;
•: on the American Stock Exchange;
•: through the writing of options;
•: in the over-the-counter market; or
•: in private transactions.

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

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

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

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

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

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements as of and for the year ended December 31, 2005 and management's report on the effectiveness of internal control over financial reporting as of December 31, 2005 incorporated in this prospectus by reference from MarkWest Energy Partners, L.P.'s Amendment No. 2 to the Annual Report on Form 10-K/A for the year ended December 31, 2005 have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports (which reports (1) express an unqualified opinion on the financial statements, (2) express an unqualified opinion on management's assessment regarding the effectiveness of internal control over financial reporting, and (3) express an adverse opinion on the effectiveness of internal control over financial reporting), which are incorporated herein by reference, and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements of MarkWest Energy Partners, L.P. as of December 31, 2004 and for the year then ended have been incorporated by reference herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, incorporated by reference herein, and upon the authority of said firm as experts in accounting and auditing.

The consolidated statements of operations, of comprehensive income, of changes in capital and cash flows for the year ended December 31, 2003 incorporated in this Prospectus by reference to Amendment No. 2 to the Annual Report on Form 10-K/A for the year ended December 31, 2005 have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. We have also filed with the SEC under the Securities Act a registration statement on Form S-1 with respect to the common units offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules which are part of the registration statement, portions of which are omitted as permitted by the rules and regulations of the SEC. Statements made in this prospectus regarding the contents of any contract or other document are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. For further information pertaining to us and the common units offered by this prospectus, reference is made to the registration statement, including the exhibits and schedules thereto, copies of which may be inspected without charge at the public reference facilities of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any portion of the registration statement may be obtained from the SEC at prescribed rates. Information on the public reference facilities may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a web site that contains reports, proxy and information statements and other information that is filed through the SEC's EDGAR System. The web site can be accessed at http://www.sec.gov.

The SEC allows us to "incorporate by reference" the information we have filed with it, which means that we can disclose important information to you by referring you to those documents. The information we incorporate by reference is an important part of this prospectus. We incorporate by reference the documents listed below:

•: our Annual Report on Form 10-K for the year ended December 31, 2005, as filed with the SEC on March 16, 2006 as amended by Amendment No. 1 and Amendment No. 2 to our Annual Report on Form 10-K/A for the year ended December 31, 2005, as filed with the SEC on March 31, 2006 and June 20, 2006, respectively;
•: our Quarterly Report on Form 10-Q, for the three months ended March 31, 2006 filed with the SEC May 3, 2006 as amended by Amendment No. 1 and Amendment No. 2 to our Quarterly Report on Form 10-Q/A for the three months ended March 31, 2006, as filed with the SEC on May 4, 2006 and June 20, 2006, respectively; and
•: our current reports on Form 8-K as filed with the SEC on January 5, 2006, January 26, 2006, February 2, 2006, March 10, 2006 April 25, 2006, April 27, 2006, May 4, 2006, May 12, 2006, July 5, 2006 and July 7, 2006 and Amendment No. 1 to our current report on Form 8-K/A as filed with the SEC on December 22, 2005.

We will provide to each person, including any beneficial owner, to whom a prospectus is delivered a copy of these filings, other than an exhibit to these filings unless we have specifically incorporated that exhibit by reference into the filing, upon written or oral request and at no cost. Requests should be made by writing or telephoning us at the following address:

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

These documents may also be accessed at our website at http://www.markwestenergy.com. All other information contained in or accessible from our corporate website is not part of this prospectus.

FORWARD-LOOKING STATEMENTS

Statements included or incorporated by reference in this prospectus that are not historical facts are forward-looking statements. We use words such as "may," "believe," "estimate," "expect," "intend," "project," "anticipate," and similar expressions to identify forward-looking statements.

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

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

•: our ability to successfully integrate our recent or future acquisitions;
•: the availability of natural gas supply for our gathering and processing services;
•: the availability of crude oil refinery runs to feed our Javelina off-gas processing facility;
•: the availability of NGLs for our transportation, fractionation and storage services;
•: our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas, including MarkWest Hydrocarbon;
•: the risks that third-party oil and gas exploration and production activities will not occur or be successful;
•: prices of natural gas and NGL products, including the effectiveness of any hedging activities;
•: competition from other NGL processors, including major energy companies;
•: changes in general economic, market or business conditions in regions where our products are located;
•: our ability to identify and complete organic growth projects or acquisitions complementary to our business;
•: the success of our risk management policies;
•: continued creditworthiness of, and performance by, contract counterparties;
•: operational hazards and availability and cost of insurance on our assets and operations;
•: the impact of any failure of our information technology systems;
•: the impact of current and future laws and government regulations;
•: liability for environmental claims;
•: damage to facilities and interruption of service due to casualty, weather, mechanical failure or any extended or extraordinary maintenance or inspection that may be required;
•: the impact of the departure of any key executive officers; and
•: our ability to raise sufficient capital to execute our business plan through borrowing or issuing equity.

This list is not necessarily complete. Other unknown or unpredictable factors could also have material adverse effects on future results. We do not update publicly any forward-looking statement with new information or future events. Investors are cautioned not to put undue reliance on forward-looking statements as many of these factors are beyond our ability to control or predict. Please read "Risk Factors."

Appendix A

GLOSSARY OF TERMS

We have included below the definitions for certain terms used in this prospectus:

adjusted operating surplus: For any period, operating surplus generated during that period is adjusted to:

(a) decrease operating surplus by:

(1) any net increase in working capital borrowings during that period; and

(2) any net reduction in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period; and

(b) increase operating surplus by:

(1) any net decrease in working capital borrowings during that period; and

(2) any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus does not include that portion of operating surplus included in clause (a) (1) of the definition of operating surplus.

available cash: For any quarter ending prior to liquidation:

(a) the sum of:

(1) all cash and cash equivalents of MarkWest Energy Partners, L.P. and its subsidiaries on hand at the end of that quarter; and

(2) all additional cash and cash equivalents of MarkWest Energy Partners, L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;

(b) less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of our general partner to:

(1) provide for the proper conduct of the business of MarkWest Energy Partners, L.P. and its subsidiaries (including reserves for future capital expenditures and for future credit needs of MarkWest Energy Partners, L.P. and its subsidiaries) after that quarter;

(2) comply with applicable law or any debt instrument or other agreement or obligation to which MarkWest Energy Partners, L.P. or any of its subsidiaries is a party or its assets are subject; and

(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;

provided, however, that our general partner may not establish cash reserves for distributions to the subordinated units unless our general partner has determined that in its judgment the establishment of reserves will not prevent MarkWest Energy Partners, L.P. from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for the next four quarters; and provided, further, that disbursements made by MarkWest Energy Partners, L.P. or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been

A-1

made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.

barrel: One barrel of petroleum products equals 42 U.S. gallons.

Bcf: One billion cubic feet of natural gas.

bpd: Barrels per day.

btu: British Thermal Units.

capital account: The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in MarkWest Energy Partners, L.P. held by a partner.

capital surplus: All available cash distributed by us from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus as of the end of the quarter before that distribution. Any excess available cash will be deemed to be capital surplus.

closing price: The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way. In either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the Nasdaq Stock Market or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by our general partner. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our general partner.

common unit arrearage: The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.

current market price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

incentive distribution right: A non-voting limited partner partnership interest issued to our general partner in connection with the formation of the Partnership. The partnership interest will confer upon its holder only the rights and obligations specifically provided in the partnership agreement for incentive distribution rights.

incentive distributions: The distributions of available cash from operating surplus initially made to our general partner that are in excess of our general partner's aggregate 2% general partner interest.

interim capital transactions: The following transactions if they occur prior to liquidation:

A-2

(a) borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for working capital borrowings and other than for items purchased on open account in the ordinary course of business) by MarkWest Energy Partners, L.P. or any of its subsidiaries;

(b) sales of equity interests by MarkWest Energy Partners, L.P. or any of its subsidiaries;

(c) sales or other voluntary or involuntary dispositions of any assets of MarkWest Energy Partners, L.P. or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements).

Mcf: One thousand cubic feet.

Mcfe: One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas.

Mcf/d: One thousand cubic feet per day.

Mcfe/d: One thousand cubic feet equivalent per day.

MMBtu/d: One million British Thermal Units per day.

NGLs: natural gas liquids, including propane, butane, isobutane, normal butane and natural gasoline.

operating expenditures: All expenditures of MarkWest Energy Partners, L.P. and our subsidiaries, including, but not limited to, facility operating costs, taxes, reimbursements of our general partner, repayment of working capital borrowings, debt service payments and capital expenditures, subject to the following:

(a) Payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings will not constitute operating expenditures.

(b) Operating expenditures will not include:

(1) capital expenditures made for acquisitions or for capital improvements;

(2) payment of transaction expenses relating to interim capital transactions; or

(3) distributions to partners.

operating surplus: For any period prior to liquidation, on a cumulative basis and without duplication:

(a) the sum of

(1) $6.3 million plus all the cash of MarkWest Energy Partners, L.P. and its subsidiaries on hand as of the closing date of our initial public offering;

(2) all cash receipts of MarkWest Energy Partners, L.P. and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions; and

(3) all cash receipts of MarkWest Energy Partners, L.P. and our subsidiaries after the end of that period but on or before the date of determination of operating surplus for the period resulting from working capital borrowings; less

A-3

(b) the sum of:

(1) operating expenditures for the period beginning on the closing date of our initial public offering and ending with the last day of that period; and

(2) the amount of cash reserves that is necessary or advisable in the reasonable discretion of our general partner to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to a member of MarkWest Energy Partners, L.P. and our subsidiaries or disbursements on behalf of a member of MarkWest Energy Partners, L.P. and our subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines.

subordination period: The subordination period will generally extend from the closing of the initial public offering until the first to occur of:

(a) the first day of any quarter beginning after June 30, 2009, for which:

(1) distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distribution on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

(2) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distribution on all of the common units and subordinated units that were outstanding during those periods on a fully-diluted basis, and the related distribution on our general partner interest in MarkWest Energy Partners, L.P.; and

(3)there are no outstanding cumulative common units arrearages.

(b) the date on which our general partner is removed as general partner of MarkWest Energy Partners, L.P. upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.

provided, however, subordinated units may convert into common units as described in "Cash Distribution Policy—Subordination Period—Early Conversion of Subordinated Units."

throughput: The volume of gas transported or passing through a pipeline, plant or other facility.

working capital borrowings: Borrowings exclusively for working capital purposes made pursuant to a credit facility or other arrangement requiring all borrowings thereunder to be reduced to a relatively small amount each year for an economically meaningful period of time.

A-4

Appendix B

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2006
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 001-31239

MARKWEST ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

Delaware		27-0005456
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

1515 Arapahoe Street, Tower 2, Suite 700, in Denver, Colorado 80202
(Address of principal executive offices)

Registrant's telephone number, including area code: 303-925-9200

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer ý

Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2 of the Exchange Act) Yes o No ý

The number of the registrant's Common and Subordinated Units outstanding at July 19, 2006, were 14,379,219 and 1,800,000 respectively.

B-1

PART I—FINANCIAL INFORMATION
Item 1.		Financial Statements
		Condensed Consolidated Balance Sheets at June 30, 2006 and December 31, 2005
		Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2006 and 2005
		Condensed Consolidated Statements of Other Comprehensive Income for the three and six months ended June 30, 2006 and 2005
		Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2006 and 2005
		Notes to the Condensed Consolidated Financial Statements
Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3.		Quantitative and Qualitative Disclosures about Market Risk
Item 4.		Controls and Procedures
PART II—OTHER INFORMATION
Item 1.		Legal Proceedings
Item 6.		Exhibits
SIGNATURES

Glossary of Terms

Bbl/d		barrels of oil per day
Btu		one British thermal unit, an energy measurement
MmGal		million gallons
Gal/d		gallons per day
Net operating margin (non-GAAP measure)		revenues less purchased product costs
Mcf		thousand cubic feet of natural gas
Mcf/d		thousand cubic feet of natural gas per day
MMcf/d		one million cubic feet of natural gas per day
NGL		natural gas liquids, such as propane, butanes and natural gasoline

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands)

				June 30, 2006			December 31, 2005
ASSETS
Current assets:
	Cash and cash equivalents			$	21,093		$	20,105
	Receivables, net of allowances of $150 and $151, respectively				71,479			110,038
	Receivables from affiliate				4,074			7,940
	Inventories				12,087			3,554
	Fair value of derivative instruments				1,131			—
	Other assets				10,100			6,861

		Total current assets			119,964			148,498

Property, plant and equipment					591,909			567,094
Less: Accumulated depreciation					(88,638	)		(74,133	)

		Total property, plant and equipment, net			503,271			492,961

Other assets:
	Investment in Starfish				57,211			39,167
	Investment in and advances to equity investee				183			182
	Intangibles and other assets, net of accumulated amortization of $21,076 and $7,648 respectively				339,440			346,496
	Deferred financing costs, net of accumulated amortization of $6,076 and $4,424, respectively				16,971			18,463
	Other				2,001			326

		Total other assets			415,806			404,634

		Total assets		$	1,039,041		$	1,046,093

LIABILITIES AND CAPITAL
Current liabilities:
	Accounts payable			$	85,962		$	102,175
	Payables to affiliate				6,100			3,421
	Accrued liabilities				30,274			27,492
	Fair value of derivative instruments				7,924			728
	Current portion of long-term debt				460			2,738

		Total current liabilities			130,720			136,554
Long-term debt, net of current portion					593,628			601,262
Deferred taxes					679			—
Fair value of derivative instruments					658			—
Other liabilities					1,220			1,102

		Total liabilities			726,905			738,918

Commitments and contingencies (Note 13)
Capital:
		General partner			6,985			6,788
		Limited partners:
		Common unitholders (11,080 and 11,070 units issued and outstanding at June 30, 2006 and December 31, 2005, respectively)			305,009			300,882
		Subordinated unitholders (1,800 outstanding at June 30, 2006 and December 31, 2005, respectively)			142			(495	)

			Total capital		312,136			307,175

			Total liabilities and capital	$	1,039,041		$	1,046,093

The accompanying notes are an integral part of these condensed consolidated financial statements.

B-3

MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands, except per unit amounts)

			Three months ended June 30,						Six months ended June 30,
			2006			2005			2006			2005
Revenues:
	Unaffiliated parties		$	124,401		$	88,494		$	263,189		$	162,233
	Affiliates			17,879			14,706			35,594			30,511
	Derivatives			(6,901	)		(240	)		(6,661	)		(147	)

		Total revenues		135,379			102,960			292,122			192,597

Operating expenses:
	Purchased product costs			76,178			73,862			176,975			134,647
	Facility expenses			15,465			11,360			29,459			20,691
	Selling, general and administrative expenses			8,988			6,311			17,326			10,950
	Depreciation			7,384			4,576			14,557			8,902
	Amortization of intangible assets			4,027			2,095			8,043			4,190
	Accretion of asset retirement obligations			26			9			51			19

		Total operating expenses		112,068			98,213			246,411			179,399

		Income from operations		23,311			4,747			45,711			13,198
Other income (expense):
	Earnings in unconsolidated affiliates			1,228			990			2,173			990
	Interest income			259			63			479			130
	Interest expense			(10,714	)		(4,558	)		(21,690	)		(8,232	)
	Amortization of deferred financing costs (a component of interest expense)			(826	)		(497	)		(1,634	)		(972	)
	Miscellaneous income (expense)			1,515			(74	)		3,607			(178	)

		Income before Texas margin tax		14,773			671			28,646			4,936
	Texas margin tax (Note 9)			(679	)		—			(679	)		—

		Net income	$	14,094		$	671		$	27,967		$	4,936

Interest in net income:
	General partner		$	818		$	286		$	1,646		$	205
	Limited partners		$	13,276		$	385		$	26,321		$	4,731
Net income per limited partner unit:
	Basic		$	1.03		$	0.04		$	2.04		$	0.44
	Diluted		$	1.03		$	0.04		$	2.04		$	0.44
Weighted average units outstanding:
	Basic			12,879			10,643			12,876			10,643
	Diluted			12,938			10,677			12,930			10,675

The accompanying notes are an integral part of these condensed consolidated financial statements.

B-4

MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME
(Unaudited, in thousands)

		Three months ended June 30,				Six months ended June 30,
		2006		2005		2006		2005
Net income		$	14,094	$	671	$	27,967	$	4,936
	Other comprehensive income—unrealized gains on commodity derivative instruments accounted for as hedges		—		216		—		67

Comprehensive income		$	14,094	$	887	$	27,967	$	5,003

The accompanying notes are an integral part of these condensed consolidated financial statements.

B-5

MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)

			Six months ended June 30,
			2006			2005
Cash flows from operating activities:
Net income			$	27,967		$	4,936
Adjustments to reconcile net income to net cash provided by operating activities (net of acquisitions):
	Depreciation			14,557			8,902
	Amortization of intangible assets			8,043			4,190
	Amortization of deferred financing costs			1,634			972
	Accretion of asset retirement obligation			51			19
	Restricted unit compensation expense			571			665
	Participation Plan compensation expense			2,575			1,769
	Equity in earnings of unconsolidated affiliates			(2,173	)		(351	)
	Unrealized (gain) loss on derivative instruments			6,723			(62	)
	Gain on sale of property, plant and equipment			(296	)		(24	)
	Deferred taxes			679			—
Changes in operating assets and liabilities, net of working capital acquired:
	Receivables			33,559			7,836
	Receivables from affiliates			3,866			3,430
	Inventories			(8,533	)		221
	Other assets			(3,239	)		(24	)
	Accounts payable and accrued liabilities			(9,783	)		(15,676	)
	Payables to affiliates			2,679			(1,049	)

		Net cash provided by operating activities		78,880			15,754

Cash flows from investing activities:
	Additional Javelina acquisition costs			(6,582	)		—
	Investment in Starfish			(15,872	)		(41,688	)
	Capital expenditures			(24,780	)		(31,386	)
	Proceeds from sale of property, plant and equipment			375			24

		Net cash flows used in investing activities		(46,859	)		(73,050	)

Cash flows from financing activities:
	Proceeds from long-term debt			53,300			65,000
	Payments of long-term debt			(63,212	)		—
	Payments for deferred financing costs and registration costs			(338	)		(95	)
	Proceeds from private placements, net			5,000			—
	Capital contribution from MarkWest Energy GP, LLC			125			405
	Distributions to unitholders			(25,908	)		(19,074	)

		Net cash flows provided by (used in) financing activities		(31,033	)		46,236

Net increase (decrease) in cash				988			(11,060	)
Cash and cash equivalents at beginning of year				20,105			24,263

Cash and cash equivalents at end of period			$	21,093		$	13,203

The accompanying notes are an integral part of these condensed consolidated financial statements.

B-6

MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(Unaudited, in thousands)

	Six months ended June 30,
	2006		2005
	(in thousands)
Supplemental disclosures of cash flow information:
Cash paid during the year for interest, net of amounts capitalized	$	19,698	$	8,013
Supplemental schedule of non-cash investing and financing activities:
Construction projects in progress	$	554	$	3,003
Accrued financing costs	$	1,580	$	—

The accompanying notes are an integral part of these condensed consolidated financial statements.

B-7

MARKWEST ENERGY PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

MarkWest Energy Partners, L.P. (the "Partnership") is a publicly traded Delaware limited partnership formed by MarkWest Hydrocarbon, Inc. (the "Company" or "MarkWest Hydrocarbon") on January 25, 2002, to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon Midstream Business. The Partnership is a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation and storage of NGLs; and the gathering and transportation of crude oil. The Partnership is the largest processor of natural gas in the Appalachia region. The Partnership also has a large natural gas gathering, processing and transmission business in the southwestern and Gulf Coast regions of the United States, obtained primarily through acquisitions and investments. These include Pinnacle Natural Gas, the Lubbock transmission pipeline and the Foss Lake gathering system, all obtained in 2003; the Carthage gathering system in East Texas, in July 2004; and the Javelina gas processing and fractionation facility in Corpus Christi, Texas, and a non-controlling, 50% interest in Starfish Pipeline Company, LLC in southern Louisiana and the Gulf of Mexico, in 2005.

2. Basis of Presentation

The Partnership's unaudited condensed consolidated financial statements include the accounts of all majority-owned or controlled subsidiaries. Equity investments in which we exercise significant influence but do not control, and are not the primary beneficiary, are accounted for using the equity method. These condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial reporting. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. In management's opinion, we have made all adjustments necessary for a fair presentation of the Partnership's results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. In addition to reviewing these condensed consolidated financial statements and accompanying notes, you should also consult the audited financial statements and accompanying notes included in the Partnership's December 31, 2005, Annual Report on Form 10-K. Finally, consider that results for the six months ended June 30, 2006, are not necessarily indicative of results for the full year 2006, or any other future period.

Stock and Incentive Compensation Plans

The Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 123R, Accounting for Stock-Based Compensation on January 1, 2006, using the modified prospective method. Prior to adopting SFAS No. 123R, the Partnership elected to measure compensation expense for equity-based employee compensation plans as prescribed by Accounting Principles Board ("APB") No. 25, Accounting for Stock Issued to Employees.

Under SFAS No. 123R, compensation expense is based on the fair value of the award. SFAS No. 123R classifies stock-based compensation as either equity or liability awards. The fair value on the date of grant for an award classified as equity is recognized over the requisite service period, with a corresponding credit to equity. The requisite service period is the period during which an individual is required to provide service in exchange for an award, which often is the vesting period. The requisite service period is estimated based on an analysis of the terms of the share-based payment award. Compensation expense for a liability award is based on the award's fair value, remeasured at each reporting date until the date of settlement. Additionally, compensation expense is reduced by 4.6% for an estimate of expected award forfeitures.

B-8

Under APB No. 25, compensation expense is based on the intrinsic value (typically the difference between the equity-based instrument to be received and the cost to acquire that equity-based instrument). APB No. 25 classified stock-based compensation as either fixed or variable awards. The intrinsic value on the date of grant for an award classified as fixed is recognized over the requisite service period. Compensation expense for variable awards is based on the award's intrinsic value, remeasured at each reporting date until the date of settlement.

Compensation expense under each plan is included in selling, general and administrative expenses.

MarkWest Energy Partners

Restricted Units

The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon its vesting or, at the discretion of the Compensation Committee, the cash equivalent to the value of a common unit. The restricted units are treated as liability awards under SFAS No. 123R, and were treated as variable awards under APB No. 25.

To satisfy common unit awards, the Partnership will issue new common units, acquire common units in the open market or directly from us or any other person, or use common units already owned by the general partner. Thus, the cost of the unit awards will be borne by us. If the Partnership issues new common units to satisfy common unit awards, the general partner will pay us the proceeds it received from the optionee upon exercise of the unit option.

MarkWest Hydrocarbon

Participation Plan

MarkWest Hydrocarbon has entered into arrangements with certain directors and employees under what is referred to as the Participation Plan. Under this plan, MarkWest Hydrocarbon sells subordinated partnership units of the Partnership or interests in the Partnership's general partner under a purchase and sale agreement. Because the formula used to determine the sale and buy-back price is not based on independent third-party valuation of the underlying equity instrument, coupled with the attributes of the put-and-call provisions, these transactions are considered compensatory arrangements. The general partner interests have no definite term, but historically have been settled for cash when the employee leaves the Company. The subordinated units converted to common units after a holding period; however, management historically has settled some subordinated units for cash when individuals left the Company. Under SFAS 123R, general partner interests are classified as liability awards, while under APB No. 25, they were classified as variable awards.

Under Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses And Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity, compensation expense related to services provided by MarkWest Hydrocarbon's employees and directors recognized under the Participation Plan should be allocated to the Partnership. The allocation is based on the percent of time that each employee devotes to the Company. Compensation expense attributable to interests that were sold to individuals who serve on both the board of MarkWest Hydrocarbon and the Partnership's board of directors is allocated equally.

3. Recent Accounting Pronouncements

In February 2006 the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140 ("SFAS 155"). This statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"), and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities and

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resolves issues addressed in SFAS 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interest in Securitized Financial Assets." This Statement: (a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation; (b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133; (c) establishes a requirement to evaluate beneficial interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation; (d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and, (e) eliminates restrictions on a qualifying special-purpose entity's ability to hold passive derivative financial instruments that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires presentation within the financial statements that identifies those hybrid financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value of those instruments. The Partnership is required to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although early adoption is permitted as of the beginning of an entity's fiscal year. The adoption of SFAS 155 is not expected to have a material impact on the condensed consolidated financial statements of the Partnership.

In March 2006 the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140. FAS No. 156 establishes, among other things, the accounting for all separately recognized servicing assets and servicing liabilities by requiring that they be initially measured at fair value, if practicable. SFAS No. 156 is effective as of the beginning of an entity's first fiscal year that begins after September 15, 2006. The adoption of SFAS No. 156 will have no impact on the Partnership's condensed consolidated financial statements of operations or financial position.

In June 2006 the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of this pronouncement is not expected to have a material impact on the condensed consolidated financial statements.

4. Acquisitions

Javelina Acquisition

On November 1, 2005, the Partnership acquired equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were 40%, 40% and 20%, respectively, owned by subsidiaries of El Paso Corporation, Kerr-McGee Corporation and Valero Energy Corporation. The Partnership paid consideration of $357.0 million, plus $41.8 million for net working capital that included approximately $35.5 million in cash. The Corpus Christi, Texas, gas-processing facility treats and processes off-gas from six local refineries, two of which are owned by Valero Energy Corporation, two by Koch Industries, Inc. and two by Citgo Petroleum Corporation. Constructed in 1989 to recover up to 28,000 Bbl/d of NGLs, the facility currently processes approximately 125 to 130 MMcf/d of inlet gas and produces approximately 25,400 Bbl/d of NGLs. The Partnership and the seller negotiated a final settlement of the acquired working capital of $41.8 million, and the final payment of $5.9 million was paid to the sellers in May of 2006 and was included in the final purchase price allocation, completed in the second quarter of 2006.

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Starfish Joint Venture

On March 31, 2005, the Partnership acquired a 50% non-operating membership interest in Starfish Pipeline Company, LLC, ("Starfish") from an affiliate of Enterprise Products Partners L.P. for $41.7 million. The Partnership financed the acquisition by borrowing $40.0 million from its credit facility during the first quarter of 2005. Starfish is a joint venture with Enbridge Offshore Pipelines LLC, which the Partnership accounts for using the equity method. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas gathering system and West Cameron dehydration facility. All of the assets are located in the Gulf of Mexico and southwestern Louisiana.

The Partnership applies the equity method of accounting for its interests in Starfish. Summarized financial information for 100 percent of Starfish is as follows (in thousands):

	Three months ended June 30,				Six months ended June 30,
	2006		2005		2006		2005
Revenues	$	7,482	$	5,012	$	12,579	$	11,544
Operating income		1,675		1,963		3,104		3,876
Net income		2,632		2,064		4,632		4,025

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the three and six months ended June 30, 2005, as though the Starfish acquisition and the Javelina acquisition had occurred on January 1, 2005. The actual results for the three and six months ended June 30, 2006, are included in the accompanying condensed consolidated statement of operations. The pro forma amounts include certain adjustments, including recognition of depreciation based on the allocated purchase price of property and equipment, amortization of customer contracts, amortization of the excess Starfish purchase price over net book value, amortization of deferred financing costs and interest expense.

The unaudited pro forma results do not necessarily reflect the actual results that would have occurred had the entities been combined during the period presented, nor does it necessarily indicate the future results of the combined entities.

		Three months ended June 30, 2005			Six months ended June 30, 2005
		(in thousands)
Revenue		$	170,999		$	302,564
Net loss		$	(6,356	)	$	(9,322	)
Net loss—limited partners		$	(6,502	)	$	(9,242	)
Net loss per share—limited partners:
	Basic	$	(0.61	)	$	(0.87	)
	Diluted	$	(0.61	)	$	(0.87	)
Weighted average number of outstanding shares of common stock:
	Basic		10,643			10,643
	Diluted		10,677			10,675

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5. Other Long-Term Assets

	June 30, 2006		December 31, 2005
	(in thousands)
Accrued financing costs	$	1,675	$	—
Other		326		326

	$	2,001	$	326

Accrued Financing Costs

Accrued financing costs at June 30, 2006, of $1.7 million relate to both a public offering of 3,000,000 common units and a private placement of $200 million aggregate principal amount of the 2016 Senior Notes that closed on July 6, 2006 (See Note 15).

6. Long-Term Debt

	June 30, 2006			December 31, 2005
	(in thousands)
Term loan, 8.75% interest at December 31, 2005, due December 2010	$	364,088		$	365,000
Revolver facility, 8.75% interest at December 31, 2005, due December 2010		5,000			14,000
Senior Notes, 6.875% interest, due November 2014		225,000			225,000

		594,088			604,000
Less: obligations due in one year(1)		(460	)		(2,738	)

Total long-term debt	$	593,628		$	601,262

(1): The balance sheet classification of debt, between current and long-term, reflects the repayment of $318.6 million of the Partnership Credit Facility term loan, using proceeds from the debt and equity transactions, as further described in Note 12.

Partnership Credit Facility

On December 29, 2005, MarkWest Energy Operating Company, L.L.C. (the "Operating Company"), a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended and restated credit agreement ("Partnership Credit Facility"), which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a revolving facility of $250.0 million and a $365.0 million term loan. The credit facility is guaranteed by the Partnership and all of the Partnership's subsidiaries and is collateralized by substantially all of the Partnership's assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The variable interest rate is typically based on the London Inter Bank Offering Rate ("LIBOR"); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5 to 1.0%, and b) a rate set by the Facility's administrative agent, based on the U.S. prime rate. The basis points vary based on the ratio of the Partnership's Consolidated Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in excess of $50.0 million ("Acquisition Adjustment Period"). For the three and six months ended June 30, 2006, the weighted average interest rate on the Partnership Credit Facility was 7.32% and 7.16%.

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Under the provisions of the Partnership Credit Facility, the Partnership is subject to a number of restrictions on its business, including restrictions on its ability to grant liens on 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 (other than subordinated indebtedness); make distributions on equity investments; and declare or make, directly or indirectly, any restricted payments.

The Partnership Credit Facility also contains covenants requiring the Partnership to maintain:

•: a ratio of not less than 2.00 to 1.00 of Consolidated EBITDA to consolidated interest expense for any fiscal quarter-end increasing to 3.00 to 1.00 upon the first to occur of September 30, 2006, or the first fiscal quarter-end following the Partnership raising at least $175.0 million in aggregate proceeds from equity offerings;
•: a ratio of not more than 6.50 to 1.00 of total consolidated debt to Consolidated EBITDA for any fiscal quarter-end decreasing to 5.25 to 1.00 upon the first to occur of September 30, 2006, or the first fiscal quarter-end following the Partnership raising at least $175.0 million in aggregate proceeds from equity offerings;
•: a ratio of not more than 4.75 to 1.00 of consolidated senior debt to Consolidated EBITDA for any fiscal quarter-end decreasing to 3.75 to 1.00 upon the first to occur of September 30, 2006, or the first fiscal quarter-end following the Partnership raising at least $175.0 million in aggregate proceeds from equity offerings; and
•: both the total debt and senior debt ratios contain adjustment clauses during any Acquisition Adjustment Period.

These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Partnership incurs a commitment fee on the unused portion of the credit facility at a rate between 30.0 and 50.0 basis points based upon the ratio of Consolidated Senior Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility). The term loan portion of the facility is paid in quarterly installments on the last business day of March, June, September and December, with the remaining balance payable on December 29, 2010. The revolver portion of the facility matures on December 29, 2010. The Partnership's Credit Facility also contains provisions requiring prepayments from certain Net Cash Proceeds (as defined in the Partnership Credit Facility) received from certain triggering sales that have not been reinvested within one hundred eighty days, Equity Offerings (as defined in the Partnership Credit Facility) and loan proceeds in excess of $15.0 million from a Senior Debt Offering as defined in the Partnership Credit Facility. In addition, commencing with the fiscal year ending December 31, 2006, and annually thereafter, the Partnership is required to make a mandatory prepayment equal to fifty percent of Excess Cash Flow within ninety days of each fiscal year end. Excess Cash Flow means quarterly, the amount, not less than zero, equal to consolidated cash flow from operations for such quarter, minus the sum of (i) capital expenditures for such quarter, (ii) principal and interest payments on indebtedness actually made during such quarter and (iii) the Partnership's distributions made during such quarter.

The Javelina Acquisition (see Note 4) was funded through the fourth amended and restated credit agreement, which provided for a maximum lending limit of $500.0 million for a term of one year, and comprised of a revolving facility of $100.0 million and a $400.0 million term loan. The fourth amended and restated credit agreement had terms similar to the new credit facility. In the fourth quarter of 2005 the Partnership completed two private placement offerings to repay a portion of the borrowed funds.

In October 2004 the Operating Company, coincident with the issuance of the 2014 Senior Notes discussed below, entered into the third amended and restated credit agreement ("Old Credit Facility"), which provided for a maximum lending limit of $200.0 million for a term of five years. The Old Credit Facility included a revolving facility of $200.0 million. The borrowings under the Old Credit Facility carried interest at a variable rate based on one of two indices that included either (i) LIBOR plus an

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applicable margin, which was fixed at a rate of 2.75% for the first two quarters following the closing of the credit facility, or (ii) Base Rate (as defined for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus ¹/2 of 1% or (b) the rate of interest in effect for such day as publicly announced from time to time by the administrative agent of the debt as its "prime rate") plus an applicable margin, which margin is fixed at a rate of 2.00% for the first two quarters following the closing of the credit facility. After that period the applicable margin adjusted quarterly based on the ratio of funded debt to EBITDA (as defined in the credit agreement).

2014 Senior Notes

In October 2004 the Partnership and its subsidiary, MarkWest Energy Finance Corporation, issued $225.0 million in senior notes at a fixed rate of 6.875%, payable semi-annually in arrears on May 1 and November 1, and commencing on May 1, 2005. The senior notes mature on November 2, 2014. The Partnership may redeem some or all of the notes at any time on or after November 1, 2009, at certain redemption prices together with accrued and unpaid interest to the date of redemption. The Partnership may redeem all of the notes at any time prior to November 1, 2009, at a make-whole redemption price. In addition, prior to November 1, 2007, the Partnership may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a stated redemption price. The Partnership must offer to repurchase the notes at a specified price if it a) sells certain assets and does not reinvest the proceeds or repay senior indebtedness, or b) the Partnership experiences specific kinds of changes in control. Each of the Partnership's existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and severally, and fully and unconditionally. The notes are senior unsecured obligations equal in right of payment with all of the Partnership's existing and future senior debt. The senior notes are senior in right of payment to all of the Partnership's future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership's obligations in respect of its Partnership Credit Facility. The proceeds from these notes were used to pay down the Partnership's outstanding debt under its credit facility.

The indenture governing the senior notes limits the activity of the Partnership and its restricted subsidiaries. Limitations under the indenture include the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions, or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership's affiliates; sell assets, including equity interests of the Partnership's subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.

The Partnership agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2014 senior notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (April 26, 2005) and, as a consequence, was incurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer was completed. The registration statement was filed on January 17, 2006, the exchange offer was completed on March 7, 2006, and the interest penalty ceased.

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7. Derivative Financial Instruments

Commodity Instruments

The Partnership utilizes a combination of fixed-price forward contracts, fixed-for-floating price swaps and options available in the over-the-counter ("OTC") market, and futures contracts traded on the New York Mercantile Exchange ("NYMEX"). The Partnership enters into OTC swaps with financial institutions and other energy company counterparties. Management conducts a standard credit review on counterparties and has agreements containing collateral requirements where deemed necessary. The Partnership uses standardized agreements that allow for offset of positive and negative exposures. Some of the agreements may require margin deposit.

The use of derivative instruments may create exposure to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected, requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that the Partnership engages in derivative activities, it may be prevented from realizing the benefits of favorable price changes in the physical market; however, is similarly insulated against unfavorable changes in such prices.

The Partnership has a committee, which is comprised of the senior management team that oversees all of the derivative activity.

Fair value is based on available market information for the particular derivative instrument, and incorporates the commodity, period, volume and pricing. Positive (negative) amounts represent unrealized gains (losses).

The Partnership's primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of natural gas, NGLs and crude oil. Swaps and futures contracts may allow the Partnership to reduce volatility in its margins as losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership's physical positions.

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The following table includes information on MarkWest Energy's specific derivative positions at June 30, 2006:

Costless collars:	Period	Floor		Cap		Fair value at June 30, 2006
						(in thousands)
Crude Oil—500 Bbl/d	2006	$	57.00	$	67.00	$	(849	)
Crude Oil—250 Bbl/d	2006	$	57.00	$	67.00		(424	)
Crude Oil—205 Bbl/d	2006	$	57.00	$	65.10		(409	)
Crude Oil—78 Bbl/d	2006	$	67.50	$	77.30		(27	)
Crude Oil—155 Bbl/d	2007	$	67.50	$	78.55		(121	)
Crude Oil—250 Bbl/d	2007	$	67.50	$	79.15		(175	)
Crude Oil—200 Bbl/d	2007	$	70.00	$	75.95		(175	)
Propane—20,000 Gal/d	2006	$	0.90	$	0.99		(737	)
Propane—10,000 Gal/d	2006	$	0.97	$	1.15		(132	)
Ethane—22,950 Gal/d	2006	$	0.65	$	0.80		(198	)
Natural Gas—1,575 Mmbtu/d	2006	$	8.67	$	10.86		803
Natural Gas—1,575 Mmbtu/d	Jan-Mar 2007	$	9.00	$	12.50		128
Natural Gas—400 Mmbtu/d	2007	$	8.25	$	10.03		36
Natural Gas—1,500 Mmbtu/d	Apr-Dec 2007	$	7.25	$	10.25		147
Natural Gas—1,500 Mmbtu/d	Jan-Mar 2008	$	8.00	$	11.29		(42	)

						$	(2,175	)

Swaps:	Period	Fixed price		Fair value at June 30, 2006
				(in thousands)
Crude Oil—250 Bbl/d	2006	$	62.00	$	(614	)
Crude Oil—185 Bbl/d	2006	$	61.00		(487	)
Crude Oil—250 Bbl/d	2007	$	65.30		(926	)
Crude Oil—140 Bbl/d	2007	$	74.10		(94	)
Propane—5,000 Gal/d	2006	$	1.08		(104	)
Natural gas	Jun-Oct 2006				18

				$	(2,207	)

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Future purchase / sale contracts:	Period	Average Fixed price		Fair value at June 30, 2006
				(in thousands)
Natural Gas—1.7 million Mmbtu (purchase)	Jul-Oct 2006	$	6.07	$	(1,349	)
Ethane—10.8 million Gallons (sale)	Jul-Oct 2006	$	0.61		(910	)
Propane—4.9 million Gallons (sale)	Jul-Oct 2006	$	1.07		(596	)
Other NGLs—4.2 million Gallons (sale)	Jul-Oct 2006	$	1.40		(214	)

				$	(3,069	)

				$	(7,451	)

The impact of MarkWest Energy's commodity derivative instruments on results of operations and financial position are summarized below (in thousands):

	Three months ended June 30,						Six months ended June 30,
	2006			2005			2006			2005
Realized gains (losses)—revenue	$	(476	)	$	(251	)	$	63		$	(209	)
Unrealized gains (losses)—revenue		(6,425	)		11			(6,724	)		62
Other comprehensive income—changes in fair value		—			438			—			247
Other comprehensive income—settlement		—			(222	)		—			(180	)

	June 30, 2006			December 31, 2005
	(in thousands)
Unrealized gains—current asset	$	1,131		$	—
Unrealized losses—current liability		(7,924	)		(728	)
Unrealized losses—non-current liability		(658	)		—

8. Incentive Compensation Plans

Total compensation cost for equity-based pay arrangements was as follows (in thousands):

	Three months ended June 30,					Six months ended June 30,
	2006		2005			2006		2005
MarkWest Energy
Restricted units	$	113	$	435		$	571	$	665
MarkWest Hydrocarbon
General partner interests		1,590		808			2,550		1,791
Participation Plan subordinated units		14		(59	)		25		(36	)

Total compensation cost	$	1,717	$	1,184		$	3,146	$	2,420

The total compensation expense not yet recognized as of June 30, 2006, related to non-vested restricted units is $1.3 million, with a weighted-average remaining vesting period of 2.1 years. The actual compensation expense recognized may differ as expense under liability awards is affected by changes in the fair value.

MarkWest Energy Partners, L.P. Long-Term Incentive Plan

The general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of the general partner, as well as employees of its affiliates who perform

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services for us. The plan consists of restricted units and unit options. It currently permits the grant of awards covering an aggregate of 500,000 common units, comprised of 200,000 restricted units and 300,000 unit options. The Compensation Committee of the general partner's Board of Directors administers the plan.

Restricted Units. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted units vest over a service period of three to four years, although vesting for certain awards accelerates if specific annualized distribution goals are met. During the vesting period, these restricted units are entitled to receive distribution equivalents, which represent cash equal to the amount of distributions made on common units.

The following is a summary of restricted units issued under the Partnership's Long-Term Incentive Plan:

	Number of units		Weighted-average grant-date fair value
Non-vested at January 1, 2006	38,864		$	45.60
Granted	30,293			46.64
Vested	(9,643	)		46.44
Forfeited	(895	)		45.85

Non-vested at June 30, 2006	58,619			46.00

	Three months ended June 30,				Six months ended June 30,
	2006		2005		2006		2005
Weighted-average grant-date fair value of restricted units granted during the period	$	—	$	322,605	$	1,412,933	$	708,599
Total fair value of restricted units vested during the period/total intrinsic value of restricted units settled during the period		—		101,995		447,841		69,025

During the quarters ended June 30, 2006 and 2005, the Partnership received no proceeds for issuing restricted units, and there were no cash settlements.

Of the total number of restricted units that vested in the second quarter of 2006 and 2005, the Partnership did not redeem any restricted units for cash. It issued 9,643 common units in 2006. In 2005 the Partnership issued 8,850 common units and acquired 250 more common units in the open market.

Unit Options. The Compensation Committee has the authority to make grants of common units under the plan to employees and directors containing such terms as the committee shall determine. Unit options are exercisable over a period determined by the Compensation Committee. Unit options also are exercisable upon a change in control of us, the general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.

As of June 30, 2006, the Partnership had not granted common unit options.

MarkWest Hydrocarbon Participation Plan

MarkWest Hydrocarbon has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under it, the Company sells subordinated units of the Partnership or interests in the Partnership's general partner under a purchase and sale

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agreement. There is no vesting period or maximum contractual term under the Participation Plan. The Company's capacity to grant further general partner interests is limited by its ownership in the general partner. At June 30, 2006, there were no subordinated units available under this Participation Plan.

The subordinated units are sold without any restrictions on transfer. Compensation expense is based on changes in the market value of the subordinated units. No subordinated units were sold to employees or directors in 2006 or 2005. MarkWest Hydrocarbon reacquired no subordinated units in 2006 or 2005.

The interest in the Partnership's general partner is sold with certain put-and-call provisions that allow the individuals to require MarkWest Hydrocarbon to buy back, or require the individuals to sell back their interest in the general partner to MarkWest Hydrocarbon. Specifically, the employees and directors can exercise their put if (1) MarkWest Hydrocarbon or the Partnership's general partner undergoes a change of control; (2) additional membership interests are issued that, on a pro forma basis, decrease the distributions to all the then-existing members; (3) any amendment, alteration or repeal of the provisions of the general partner agreement materially and adversely affects the then-existing rights, duties, obligations or restrictions of the employees and directors; or (4) the employee or director (i) becomes totally disabled while a director, officer or employee of the general partner of MarkWest Hydrocarbon or of any of their affiliates, or (ii) dies, or (iii) retires as a director, officer or employee of the general partner of MarkWest Hydrocarbon or of any of their affiliates after reaching the age of 60 years. The employee or his estate has 120 days after the put event to exercise the put under (4) and 30 days after notice to exercise under (1) through (3). MarkWest Hydrocarbon can exercise its call option if the employee or director ceases to be a director or employee of MarkWest Hydrocarbon or any of its affiliates, or if there is a change of control. MarkWest Hydrocarbon can exercise its call option if (i) the employee or director ceases to be a director or employee of MarkWest Hydrocarbon or any of its affiliates, or (ii) if there is a change of control of MarkWest or of the Partnership's general partner. For the call option based upon a termination of employment or directorship, MarkWest Hydrocarbon has 12 months following the termination date to exercise its call option. MarkWest Hydrocarbon has agreed to exempt the general partner interests of three present or former directors from the call option based upon a termination of employment or directorship. Additionally, pursuant to the terms of Mr. Semple's employment agreement with MarkWest Hydrocarbon, 66% of his general partner interest has become exempt from the call option based upon a termination of employment or directorship for reasons other than cause, and the remaining 34% will likewise become exempt after November 1, 2006. For the call option based upon a change of control of MarkWest or of the Partnership's general partner, MarkWest Hydrocarbon has 30 days following the change of control to exercise its call option.

As the formula used to determine the sale and buy-back price is not based on an independent third-party valuation, coupled with the attributes of the put-and-call provisions, these transactions are considered compensatory arrangements, similar to a stock appreciation right. Compensation expense related to general partner interests is calculated as the difference in the formula value and the amount paid by those individuals. The formula value is the amount MarkWest Hydrocarbon would have to pay the employees and directors to repurchase the general partner interests, and is based on the current market value of the Partnership's common units and the current quarterly distributions paid. During the quarters ended June 30, 2006 and 2005, the Company did not receive or distribute any monies for the issuance or repurchase of general partner interests.

9. Texas Margin Tax

The Texas legislature recently passed House Bill 3, 79th Leg., 3d C.S. (2006) ("H.B.3") that was signed into law on May 18, 2006. H.B. 3 significantly reforms the Texas franchise tax system and replaces it with a new Texas margin tax system. The margin tax expands the type of entities subject to tax to generally include all active business entities. The new margin tax also will apply to common

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entity types that are not currently subject to tax, including general and limited partnerships. The effective date of the margin tax is January 1, 2008, but the tax generally will be imposed on gross margin generated in 2007 and thereafter.

The Texas margin tax law causes the Partnership to be subject to an entity-level tax on the portion of our income that is generated in Texas beginning in our tax year ending in 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 1.0% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas, reduces the cash available for distribution to unitholders. Consistent with the principles of accounting for income taxes, the Partnership recorded a deferred tax liability and expense of $679,000, related to the Partnership's temporary differences that are expected to reverse in future periods when the tax will apply.

10. Earnings Per Unit

Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is calculated by dividing net income, after deducting the amount allocated to the general partner's interest, by the weighted-average number of limited partner common and subordinated units outstanding during the period.

Emerging Issues Task Force Issue No. 03-6 ("EITF 03-6") Participating Securities and the Two-Class Method under FASB Statement No. 128 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity. EITF 03-6 provides that the general partner's interest in net income is to be calculated based on the amount that would be allocated to the general partner if all the net income for the period were distributed, and not on the basis of actual cash distributions for the period. The application of EITF 03-6 may have an impact on earnings per limited partner unit in future periods if there are material differences between net income and actual cash distributions or if other participating securities are issued.

The following tables set forth the computation of basic and diluted earnings per limited partner unit. The net income available to limited partners and the weighted average to those used to compute

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diluted net income per limited partner unit for the three and six months ended June 30, 2006 and 2005 (in thousands, except per share data):

		Three months ended June 30,						Six months ended June 30,
		2006			2005			2006			2005
Numerator for basic and diluted earnings per limited partner unit:
Net income		$	14,094		$	671		$	27,967		$	4,936
Less:
	Allocated depreciation expense attributable to the general partners contribution for construction of the Cobb Gas Extraction Plant		(26	)		—			(53	)		—
	General partner's incentive distribution paid		(2,125	)		(1,041	)		(3,631	)		(1,877	)

Sub-total			11,943			(370	)		24,283			3,059
Plus:
	Participation plan allocation		1,604			763			2,575			1,769

Net income to limited partners			13,547			393			26,858			4,828
Less:
	General Partner's 2% interest		(271	)		(8	)		(537	)		(97	)

	Net income available to limited partners under EITF 03-6	$	13,276		$	385		$	26,321		$	4,731

Denominator:
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units			12,879			10,643			12,876			10,643
Effect of dilative securities:
Weighted-average of restricted units outstanding			59			34			54			32

Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units			12,938			10,677			12,930			10,675

Basic net income per limited partner unit		$	1.03		$	0.04		$	2.04		$	0.44

Diluted net income per limited partner unit		$	1.03		$	0.04		$	2.04		$	0.44

11. Related Party Transactions

Affiliated revenues in the condensed consolidated statements of operations consist of service fees and NGL product sales. Concurrent with the closing of its initial public offering in 2002, the Partnership entered into several contracts with MarkWest Hydrocarbon. Specifically, the Partnership entered into:

•: A gas-processing agreement in which MarkWest Hydrocarbon delivers to us for processing all natural gas it receives from third-party producers. MarkWest Hydrocarbon pays us a monthly fee based on volumes delivered.
•: A transportation agreement in which MarkWest Hydrocarbon delivers most of its NGLs to us for transportation through the pipeline to the Partnership's Siloam fractionator. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us.
•: A fractionation agreement in which MarkWest Hydrocarbon delivers all of its NGLs to us for unloading, fractionation, loading and storage at the Partnership's Siloam facility. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for

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fractionation, an annual storage fee and a monthly fee based on the number of gallons of NGLs unloaded.

•: A natural gas liquids purchase agreement in which MarkWest Hydrocarbon receives and purchases, and the Partnership delivers and sells, all of the NGL products the Partnership produces pursuant to the Partnership's gas- processing agreement with a third party. Under the terms of this agreement, MarkWest Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale of the NGL products to third parties. This contract also applies to any other NGL products the Partnership acquires. The Partnership retains a percentage of the proceeds from the sale of the NGL products it produces pursuant to its agreement with a third party, and remits the balance of the proceeds to this third party.

Under the Services Agreement with MarkWest Hydrocarbon, MarkWest Hydrocarbon continues to provide centralized corporate functions such as accounting, treasury, engineering, information technology, insurance and other services. The Partnership reimburses MarkWest Hydrocarbon monthly for the selling, general and administrative expenses. The Partnership reimbursed MarkWest Hydrocarbon approximately $4.1 million and $2.4 million for the three months ended June 30, 2006 and 2005; and $8.3 million and $4.9 million for the six months ended June 30, 2006 and 2005, respectively.

The Partnership also reimburses MarkWest Hydrocarbon for the salaries and employee benefits, such as 401(k) and health insurance, of plant operating personnel as well as other direct operating expenses. These expenses totaled $5.6 million and $2.7 million for the three months ended June 30, 2006 and 2005; and $9.9 million and $5.3 million for the six months ended June 30, 2006 and 2005, respectively. The Partnership has no employees.

12. Distribution to Unitholders

On January 25, 2006, the Partnership declared a cash distribution of $0.82 per common and subordinated unit for the quarter ended December 31, 2005. The $12.3 million distribution included $1.8 million distributed to the general partner, of which $1.5 million related to the general partner incentive distribution rights. It was paid on February 14, 2006, to unitholders of record as of February 8, 2006.

On April 21, 2006, the Partnership declared a cash distribution of $0.87 per common and subordinated unit for the quarter ended March 31, 2006. The $13.6 million distribution included $2.4 million to be distributed to the general partner, of which $2.1 million related to the general partner incentive distribution rights. It was paid on May 15, 2006, to unitholders of record as of May 5, 2006.

On July 26, 2006, the Partnership declared a cash distribution of $0.92 per common and subordinated unit for the quarter ended June 30, 2006. The $18.7 million distribution included $3.8 million to be distributed to the general partner, of which $3.4 million related to the general partner incentive distribution rights. It will be paid on August 14, 2006, to unitholders of record as of August 7, 2006.

13. Commitments and Contingencies

In the ordinary course of its business MarkWest Energy Partners is subject to a variety of risks and disputes normal to its business and as a party to various legal proceedings. We maintain insurance policies in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure either that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to future claims for property loss or business interruption to the Partnership; or for

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third-party claims of personal and property damage; or that the coverages or levels of insurance it currently has will be available in the future at economical prices.

In early 2005 MarkWest Hydrocarbon, Inc., the Partnership and several of its affiliates were served with two lawsuits, Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al. (filed February 2, 2005), and Charles C. Reid, et al. v. MarkWest Hydrocarbon, Inc. et al., (filed February 8, 2005). in Floyd Circuit Court, Commonwealth of Kentucky Civil Action No. 05-CI-00137 and Civil Action No. 05-CI-00156, which actions on February 24, 2005, were removed to the jurisdiction of the U.S. District Court for the Eastern District of Kentucky, Pikeville Division. The Partnership was served with an additional lawsuit, Community Trust and Investment Co., et al. v. MarkWest Hydrocarbon, Inc. et al., filed November 7, 2005 in Floyd County Circuit Court, Kentucky, that added five new claimants but essentially alleged the same facts and claims as the earlier two suits. On March 27, 2006, the U.S. District Court remanded the cases back to Floyd County Circuit Court, Kentucky, and the cases were consolidated into Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al., Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00137.

These actions are for third-party claims of property and personal injury damages sustained as a consequence of an NGL pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004. The pipeline was owned by an unrelated business entity and leased and operated by the Partnership's subsidiary, MarkWest Energy Appalachia, LLC. It transports NGLs from the Maytown gas processing plant to the Partnership's Siloam fractionator. The explosion and fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The pipeline owner, the U.S. Department of Transportation, Office of Pipeline Safety ("OPS"), and the Partnership continue to investigate the incident. Discovery in the action is underway following the remand back to state court. The trial is scheduled to begin February 5, 2007.

The Partnership notified its general liability insurance carriers of the incident and the lawsuits in a timely manner and is coordinating its legal defense with the insurers. At this time, the Partnership believes that it has adequate general liability insurance coverage for third-party property damage and personal injury liability resulting from the incident. The Partnership has settled with several of the claimants for property damage claims (damage to residences and personal property), and reached settlements for some of the personal injury claims. These have been paid for or reimbursed under the Partnership's general liability insurance. As a result, the Partnership has not provided for a loss contingency.

Pursuant to OPS regulation mandates and to a Corrective Action Order issued by the OPS on November 18, 2004, pipeline and valve integrity evaluation, testing and repairs were conducted on the affected pipeline segment before service could be resumed. OPS authorized a partial return to service of the affected pipeline in October 2005. MarkWest is in the process of applying for return to full service.

In late June 2006 a Notice of Probable Violation and Proposed Civil Penalty (NOPV) was issued by OPS to both MarkWest Hydrocarbon and the unaffiliated owner of the pipeline, with a proposed penalty in the aggregate amount of $1,070,000. Initial response to the NOPV is not due until at least September 1, 2006, and MarkWest Hydrocarbon is likely going to request an administrative hearing and settlement conference with respect to the NOPV.

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and costs incurred for damage to, and loss of use of the pipeline, equipment and products; the extra transportation costs incurred for transporting the liquids while the pipeline was out of service; the reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as "other income" if and when it is received. The Partnership has not provided for a receivable for these claims because of the uncertainty as to whether and how much the Partnership will ultimately recover under the policies. The Partnership has also asserted that the cost of pipeline testing, replacement and repair are subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement. Discovery in the action is continuing.

On September 27, 2005, a lawsuit captioned C.F. Qualia Operating, Inc. v. MarkWest Pinnacle, L.P., (District Court of Midland, Texas, 385^th Judicial District, Case No. CV-45188), was served on a Partnership subsidiary, MarkWest Pinnacle, L.P., with respect to a dispute on volumes of gas purchased by the Partnership. This dispute was fully settled in May 2006 and the action dismissed with prejudice in June 2006.

The Partnership acquired the Javelina gas processing, transportation and fractionation business located in Corpus Christi, Texas, (the "Javelina Business") on November 1, 2005. Javelina was a party with numerous other defendants to three lawsuits brought by plaintiffs who had residences or businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations. These suits, Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause No. 98-1055-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28^TH Judicial District, severed May 18, 2005, from the Gonzales case cited above); and Jesus Villarreal v. Koch Refining Co. et al., (Cause No. 05-01977-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed April 27, 2005), set forth claims for personal injury or property damage, harm to business operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area. The Gonzales action has been settled pursuant to a mediation held December 9, 2005. The other actions have been and are being vigorously defended and, based on initial evaluation and consultations, it appears at this time that these actions should not have a material adverse impact on the Partnership.

In the ordinary course of business, the Partnership is a party to various other legal actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership's financial condition, liquidity or results of operations.

Office Lease Obligation

The Partnership entered into a ten-year office lease and relocated its and MarkWest Hydrocarbon, Inc.'s corporate headquarters to the Park Central Building, located in downtown Denver, Colorado in July 2006. The lease provides for a tenant improvement allowance of up to approximately

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$1.8 million through December 31, 2006. A security deposit of $1.0 million was provided in the form of an irrevocable letter of credit. The future minimum lease payments of the new lease are as follows:


2006		$	—
2007			927,442
2008			972,138
2009			1,016,834
2010			1,044,769
2011 and thereafter			5,983,677

	Total	$	9,944,860

The Partnership's old principal executive office was located in a building leased by MarkWest Hydrocarbon. A portion of the lease cost for that building historically had been allocated to the Partnership. In accordance with SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, MarkWest Hydrocarbon incurred a liability associated with the cancelled lease of $1.25 million, of which $0.8 million was allocated to the Partnership in the second quarter of 2006.

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14. Segment Information

The Partnership is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids and refinery off-gas; and the gathering and transportation of crude oil. The Partnership processes natural gas in the northeastern and southwestern United States, which it collects from the Appalachian Basin, one of the country's oldest natural gas producing regions, as well as from East Texas, the Gulf Coast and Michigan. Our chief operating decision-maker is our chief executive officer ("CEO"). The CEO reviews the Partnership's discrete financial information on a geographic and operational basis, as the products and services are closely related within each geographic region and business operation. Accordingly, the CEO makes operating decisions, assesses financial performance and allocates resources on a segment basis. The Partnership's segments are as follows:

Segment	Related Legal Entity	Products and services
Southwest
East Texas	MarkWest Energy East Texas Gas Company, L.P. MarkWest Pipeline Company, L.P.	Gathering, processing, pipeline, fractionation and storage
Oklahoma	MarkWest Western Oklahoma Gas Company, L.L.C.	Gathering and processing
Other Southwest	MarkWest Power Tex L.P. MarkWest Pinnacle L.P. MarkWest PNG Utility L.P. MarkWest Texas PNG Utility L.P. MarkWest Blackhawk L.P. MarkWest New Mexico L.P.	Gathering and pipeline
Gulf Coast
Gulf Coast	MarkWest Javelina Company MarkWest Javelina Pipeline Company MarkWest Javelina Pipeline Holding Company, L.P. MarkWest Javelina Holding Company, L.P.	Processing, fractionation and pipeline
Northeast
Appalachia	MarkWest Energy Appalachia, L.L.C.	Processing, pipelines, fractionation and storage
Michigan	Basin Pipeline, L.L.C. West Shore Processing Company, L.L.C. MarkWest Michigan Pipeline Company, L.L.C.	Gathering, processing and crude oil transportation

The Partnership prepares business segment information in accordance with GAAP (see Note 2), except that certain items below the "Operating Income" line are not allocated to business segments as management does not consider them in its evaluation of business unit performance. In addition, selling, general and administrative expenses and derivative are not allocated to individual business segments. Management evaluates business segment performance based on operating income before selling, general and administrative expenses. Revenues from MarkWest Hydrocarbon are reflected as revenue from Affiliates.

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The tables below present information about operating income for the reported segments for the three and six months ended June 30, 2006 and 2005 (unaudited, in thousands):

Three months ended June 30, 2006 (in thousands):

		East Texas		Oklahoma		Other Southwest		Appalachia			Michigan			Gulf Coast		Total
Revenues:
	Unaffiliated parties	$	31,591	$	47,926	$	22,270	$	430		$	3,288		$	18,896	$	124,401
	Affiliated parties		—		—		—		17,879			—			—		17,879

Total Revenues			31,591		47,926		22,270		18,309			3,288			18,896		142,280
Purchased product costs			10,156		37,022		17,815		10,347			838			—		76,178
Facility expenses			4,278		1,466		1,601		3,474			1,480			3,166		15,465
Depreciation			1,907		739		1,040		898			1,180			1,620		7,384
Amortization			2,074		—		—		—			—			1,953		4,027
Accretion			11		7		5		3			—			—		26

Operating income before selling, general and administrative expenses		$	13,165	$	8,692	$	1,809	$	3,587		$	(210	)	$	12,157	$	39,200

Capital expenditures		$	3,952	$	2,486	$	2,459	$	(207	)	$	52		$	2,056	$	10,798
Capital expenditures not allocated to segments																	822

Capital expenditures																$	11,620

Assets attributable to segments		$	323,109	$	70,927	$	56,882	$	51,307		$	48,152		$	428,880	$	979,257
Investment in Starfish																	57,211
Fair value of derivative instruments																	1,131
Leasehold Improvements(1)																	1,442

Total Assets																$	1,039,041

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Three months ended June 30, 2005 (in thousands):

		East Texas		Oklahoma		Other Southwest		Appalachia		Michigan			Gulf Coast		Total
Revenues:
	Unaffiliated parties	$	19,112	$	43,362	$	22,302	$	527	$	3,191		$	—	$	88,494
	Affiliated parties		—		—		—		14,706		—			—		14,706

Total Revenues			19,112		43,362		22,302		15,233		3,191			—		103,200
Purchased product costs			6,517		38,847		18,987		8,660		851			—		73,862
Facility expenses			2,731		1,146		955		5,113		1,415			—		11,360
Depreciation			1,145		556		878		828		1,169			—		4,576
Amortization			2,061		—		34		—		—			—		2,095
Accretion			7		—		2		—		—			—		9

Operating income before selling, general and administrative expenses		$	6,651	$	2,813	$	1,446	$	632	$	(244	)	$	—	$	11,298

Capital expenditures		$	9,080	$	3,012	$	1,821	$	605	$	14		$	—	$	14,532
Assets attributable to segments		$	306,586	$	60,134	$	58,719	$	48,468	$	53,397		$	—	$	527,304
Investment in Starfish																42,009

Total Assets															$	569,313

(1): Leasehold improvements not attributable to segments include tenant improvements for the Partnership's new office lease in downtown Denver, Colorado (Note 13).

Six months ended June 30, 2006 (in thousands):

		East Texas		Oklahoma		Other Southwest		Appalachia		Michigan			Gulf Coast		Total
Revenues:
	Unaffiliated parties	$	64,079	$	110,194	$	47,730	$	849	$	6,485		$	33,852	$	263,189
	Affiliated parties		—		—		—		35,594		—			—		35,594

Total Revenues			64,079		110,194		47,730		36,443		6,485			33,852		298,783
Purchased product costs			23,324		92,347		39,238		20,457		1,609			—		176,975
Facility expenses			7,952		3,545		2,952		6,815		3,083			5,112		29,459
Depreciation			3,718		1,451		2,059		1,738		2,354			3,237		14,557
Amortization			4,147		—		—		—		—			3,896		8,043
Accretion			22		13		10		6		—			—		51

Operating income before selling, general and administrative expenses		$	24,916	$	12,838	$	3,471	$	7,427	$	(561	)	$	21,607	$	69,698

Segment capital expenditures		$	11,648	$	4,861	$	4,354	$	751	$	123		$	2,221	$	23,958
Capital expenditures not allocated to segments(1)																822

Capital expenditures															$	24,780

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Six months ended June 30, 2005 (in thousands):

		East Texas		Oklahoma		Other Southwest		Appalachia		Michigan			Gulf Coast		Total
Revenues:
	Unaffiliated parties	$	33,914	$	80,651	$	40,457	$	865	$	6,346		$	—	$	162,233
	Affiliated parties		—		—		—		30,511		—			—		30,511

Total Revenues			33,914		80,651		40,457		31,376		6,346			—		192,744
Purchased product costs			10,114		71,322		33,714		17,913		1,584			—		134,647
Facility expenses			5,066		2,074		1,963		8,870		2,718			—		20,691
Depreciation			2,157		1,082		1,694		1,645		2,324			—		8,902
Amortization			4,122		—		68		—		—			—		4,190
Accretion			15		—		4		—		—			—		19

Operating income before selling, general and administrative expenses		$	12,440	$	6,173	$	3,014	$	2,948	$	(280	)	$	—	$	24,295

Capital expenditures		$	21,932	$	3,774	$	3,154	$	1,447	$	104		$	—	$	30,411

(1): Leasehold improvements not attributable to segments include tenant improvements for the Partnership's new office lease in downtown Denver, Colorado (Note 13).

Because derivative revenues are not allocated to segments, the following reconciles segment revenues to total revenues (in thousands):

		Three months ended June 30,						Six months ended June 30,
		2006			2005			2006			2005
Total segment revenue		$	142,280		$	103,200		$	298,783		$	192,744
Derivatives not allocated to segments			(6,901	)		(240	)		(6,661	)		(147	)

	Total revenue	$	135,379		$	102,960		$	292,122		$	192,597

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The following is a reconciliation of operating income before selling, general and administrative expenses to net income (in thousands):

		Three months ended June 30,						Six months ended June 30,
		2006			2005			2006			2005
Total segment operating income before derivatives, selling, general and administrative expenses		$	39,200		$	11,298		$	69,698		$	24,295
Derivatives not allocated to segments			(6,901	)		(240	)		(6,661	)		(147	)
Selling, general and administrative expenses not allocated to segments			(8,988	)		(6,311	)		(17,326	)		(10,950	)

	Income from operations		23,311			4,747			45,711			13,198
Earnings from unconsolidated affiliates			1,228			990			2,173			990
Interest income			259			63			479			130
Interest expense			(10,714	)		(4,558	)		(21,690	)		(8,232	)
Amortization of deferred financing costs			(826	)		(497	)		(1,634	)		(972	)
Miscellaneous income (expense)			1,515			(74	)		3,607			(178	)

	Income before Texas margin tax		14,773			671			28,646			4,936
	Texas margin tax		(679	)		—			(679	)		—

Net income		$	14,094		$	671		$	27,967		$	4,936

Miscellaneous income for the three and six months ended June 30, 2006, includes $1.3 and $3.1 million, respectively, for insurance recoveries related to charges incurred in 2005 from Hurricane Rita.

In the fourth quarter of 2004 the Partnership received a communication from a customer alleging a measurement or volume discrepancy with the Partnership. Based on the evidence available at that time, the Partnership recorded a contingent liability of approximately $1.9 million. In the first quarter of 2006, after a thorough investigation, management of the Partnership concluded that it was no longer probable that a liability existed with respect to the alleged measurement or volume discrepancy. Accordingly, the $1.9 million accrued liability was reversed to revenue in the first quarter of 2006.

15. Subsequent Events

Equity Offering

On July 6, 2006 the Partnership completed its underwritten public offering of 3.0 million common units (the "Common Unit Offering") at a public offering price of $39.75 per common unit. In addition, on July 12, 2006, the Partnership completed the sale of an additional 300,000 common units to cover over-allotments in connection with the Common Unit Offering. The sale of units resulted in total gross proceeds of $131.2 million, and net proceeds of $127.3 million, after the underwriters' commission and legal, accounting and other transaction expenses. The Partnership intends to use the net proceeds from the offering, which includes a capital contribution from its general partner to maintain its 2% general partner interest in the Partnership, to repay a portion of the term debt under the Partnership Credit Facility.

Debt Offering

On July 6, 2006, the Partnership and its subsidiary, MarkWest Energy Finance Corporation completed their private placement of $200 million in aggregate principal amount of 8¹/2% senior notes due 2016 (the "2016 Senior Notes") to qualified institutional buyers. The 2016 Senior Notes will mature on July 15, 2016, and interest is payable on each July 15 and January 15, commencing

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January 15, 2007. The net proceeds from the private placement were approximately $191.2 million, after deducting the initial purchasers' discounts and legal, accounting and other transaction expenses. The Partnership intends to use the net proceeds from the offering to repay a portion of the term debt under the Partnership Credit Facility. Affiliates of several of the initial purchasers, including RBC Capital Markets Corporation, J.P. Morgan Securities Inc., and Wachovia Capital Markets, LLC, are lenders under the Partnership Credit Facility.

Change in Address of Principal Executive Offices

In July 2006 we relocated our principal executive office to 1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado 80202. Our telephone number is 303-925-9200.

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

Statements included in this quarterly report on Form 10-Q that are not historical facts are forward-looking statements. We use words such as "may," "believe," "estimate," "expect," "intend," "project," "anticipate," and similar expressions to identify forward-looking statements.

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

•: our ability to successfully integrate our recent or future acquisitions;
•: the availability of natural gas supply for our gathering and processing services;
•: the availability of crude oil refinery runs to feed our Javelina off-gas processing facility;
•: the availability of NGLs for our transportation, fractionation and storage services;
•: our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas, including MarkWest Hydrocarbon;
•: the risks that third-party oil and gas exploration and production activities will not occur or be successful;
•: prices of natural gas and NGL products, including the effectiveness of any hedging activities;
•: competition from other NGL processors, including major energy companies;
•: changes in general economic, market or business conditions in regions where our products are located;
•: our ability to identify and complete organic growth projects or acquisitions complementary to our business;
•: the success of our risk management policies;
•: continued creditworthiness of, and performance by, contract counterparties;
•: operational hazards and availability and cost of insurance on our assets and operations;
•: the impact of any failure of our information technology systems;
•: the impact of current and future laws and government regulations;
•: liability for environmental claims;
•: damage to facilities and interruption of service due to casualty, weather, mechanical failure or any extended or extraordinary maintenance or inspection that may be required;
•: the impact of the departure of any key executive officers; and
•: our ability to raise sufficient capital to execute our business plan through borrowing or issuing equity.

This list is not necessarily complete. Other unknown or unpredictable factors could also have material adverse effects on future results. The Partnership does not publicly update any forward-looking

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statement with new information or future events. Investors are cautioned not to put undue reliance on forward-looking statements as many of these factors are beyond our ability to control or predict.

Overview

We reported net income of $14.1 million, or $1.03 per diluted limited partner unit, for the three months ended June 30, 2006, compared to net income of $0.7 million, or $0.04 per diluted limited partner unit, for the corresponding period of 2005. The Partnership also reported a net income of $28.0 million, or $2.04 per diluted limited partner unit, for the six months ended June 30, 2006, compared to net income of $4.9 million, or $0.44 per diluted limited partner unit, for the corresponding period of 2005.

Contributing factors to this increase in net income for the three months ended June 30, 2006, compared to the same period in 2005 were:

•: The Gulf Coast segment provided $12.2 million of operating income, from our Javelina acquisition on November 1, 2005.
•: Southwest Business Unit (East Texas, Oklahoma and Other Southwest segments) operating income increased by $12.8 million. This resulted from increased gathering volumes on our Carthage, Appleby and Western Oklahoma systems, coupled with higher NGL prices.
•: Northeast Business Unit (Appalachia and Michigan segments) operating income increased by $3.0 million, primarily due to increased prices for our Maytown NGLs and reduced trucking expenses, as we have been able to utilize our ALPS pipeline after repairs in 2005.
•: Selling, general and administrative expense increased by $2.7 million. 2006 includes a charge to terminate the old headquarters lease; higher non-cash, equity-based compensation expense, primarily due to the Partnership's increased market value; labor costs related to additional personnel to support our growth and strategic objectives; higher insurance premiums; offset in part by reduced professional fees.
•: We reported a $6.9 million loss for our 2006/2007 derivative instruments, consistent with our previous announcements that we would not be applying hedge accounting. $6.4 million of the loss was from mark-to-market, which is a non-cash charge that does not impact distributable cash flow. Our 2005 loss was $0.2 million.
•: Starfish operations partially restarted late in the fourth quarter of 2005, following Hurricane Rita. Our earnings in unconsolidated affiliate increased $0.2 million. We also recorded an insurance recovery of $1.3 million (included in miscellaneous income).
•: Interest expense (including amortization of deferred financing costs, a component of interest expense) was $6.5 million higher in the second quarter of 2006 compared to 2005, attributable to higher debt levels associated with the Javelina and Starfish acquisitions and related financing activities. In addition, we experienced an increase in interest rates during the first quarter.

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partner incentive distribution rights. It was paid on May 15, 2006, to unitholders of record as of May 5, 2006.

Our Business

The Partnership is a Delaware limited partnership formed by MarkWest Hydrocarbon on January 25, 2002, to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon Midstream Business. We are engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquid products; and the gathering and transportation of crude oil. Our primary business strategy is to grow our business, increase distributable cash flow to our common unitholders, improve financial flexibility and increase our ability to access capital to fund our growth. Since our initial public offering in May 2002 we have expanded our operations significantly through a series of acquisitions.

To better understand our business and the results of operations discussed below, it is important to have an understanding of three factors:

•: The nature of the contracts from which we derive our revenues;
•: The difficulty in comparing our results of operations across periods because of our acquisition activity; and
•: The nature of our relationship with MarkWest Hydrocarbon, Inc.

Our Contracts

We generate the majority of our revenues and net operating margin (defined as revenues less purchased product costs) from natural gas gathering, processing and transmission; NGL transportation, fractionation and storage; and crude oil gathering and transportation. We have a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. While all of these services constitute midstream energy operations, we provide services under the following different types of arrangements:

•: Fee-based arrangements: Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, processing and transmission of natural gas; transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue we earn from these arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, our arrangements provide for minimum annual payments. If a sustained decline in commodity prices were to result in a decline in volumes, however, our revenues from these arrangements would be reduced.
•: Percent-of-proceeds arrangements: Under percent-of-proceeds arrangements, we gather and process natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and remit to producers an agreed-upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes we keep to third parties at market prices. Generally, under these types of arrangements our

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revenues and gross margins increase as natural gas, condensate prices and NGL prices increase, and our revenues and net operating margins decrease as natural gas and NGL prices decrease.

•: Percent-of-index arrangements: Under percent-of-index arrangements, we purchase natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. We then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price, or at a different percentage discount to the index price. With respect to (1) and (3) above, the net operating margins we realize under the arrangements decrease in periods of low natural gas prices because these net operating margins are based on a percentage of the index price. Conversely, our net operating margins increase during periods of high natural gas prices.
•: Keep-whole arrangements: Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Accordingly, under these arrangements our revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decrease as the price of natural gas increases relative to the price of condensate and NGLs.
•: Settlement margin: Typically, we are allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed-line losses. To the extent our gathering systems are operated more efficiently than specified per contract allowance, we are entitled to retain the difference for our own account.

In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common and other market factors. Any change in mix will influence our financial results.

As of June 30, 2006, our primary exposure to keep-whole contracts was limited to our Arapaho (Oklahoma) processing plant and our East Texas processing contracts. At the Arapaho plant inlet, the Btu content of the natural gas meets the downstream pipeline specification; however, we have the option of extracting NGLs when the processing margin environment is favorable. In addition, approximately 50%, as measured in volumes, of the related gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low-processing margin environment. Because of our ability to operate the Arapaho plant in several recovery modes, including turning it off, coupled with the additional fees provided for in the gas gathering contracts, our overall keep-whole contract exposure is limited to a small portion of the operating costs of the plant. For the three and six months ended June 30, 2006, approximately 7.6% of East Texas inlet volumes were processed pursuant to keep-whole contracts.

Management evaluates contract performance on the basis of net operating margin (a "non-GAAP" financial measure), which is defined as income (loss) from operations, excluding facility expense, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement. 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 does not have any standardized definition and therefore is

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unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for our financial results prepared in accordance with United States GAAP. Our usage of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

For the six months ended June 30, 2006, we generated the following percentages of our revenues and net operating margin from the following types of contracts:

		Fee-Based		Percent-of- Proceeds(1)		Percent-of- Index(2)		Keep-Whole(3)		Total
Revenues		13	%	36	%	17	%	34	%	100	%
Net operating margin		31	%	51	%	10	%	8	%	100	%

(1): Includes other types of arrangements tied to NGL prices.
(2): Includes settlement margin, condensate sales and other types of arrangements tied to natural gas prices.
(3): Includes settlement margin, condensate sales and other types of arrangements tied to both NGL and natural gas prices.

Management also uses "net operating margin" (a non-GAAP measure) as a unit of performance measurement. We calculate net operating margin by starting with net income from operations, plus facility costs, plus selling, general and administrative costs, plus depreciation, plus amortization, plus impairments, plus accretion of asset retirement obligation. The following is a reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

		Three months ended June 30,				Six months ended June 30,
		2006		2005		2006		2005
Revenues		$	135,379	$	102,960	$	292,122	$	192,597
Purchased product costs			76,178		73,862		176,975		134,647

Net operating margin			59,201		29,098		115,147		57,950
	Facility expenses		15,465		11,360		29,459		20,691
	Selling general and administrative		8,988		6,311		17,326		10,950
	Depreciation		7,384		4,576		14,557		8,902
	Amortization of intangible assets		4,027		2,095		8,043		4,190
	Accretion of asset retirement obligations		26		9		51		19

Income from operations		$	23,311	$	4,747	$	45,711	$	13,198

Impact of Recent Acquisitions on Comparability of Financial Results

In reading the discussion of our historical results of operations, you should be aware of the impact of our recent acquisitions, which fundamentally affect the comparability of our results of operations over the periods discussed.

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Since our initial public offering, we have completed eight acquisitions for an aggregate purchase price of approximately $795 million. The following table sets forth information regarding each of these acquisitions:

Name	Assets	Location	Consideration		Closing Date
			(in millions)
Javelina(1)	Gas processing and fractionation facility	Corpus Christi, TX	$	398.8	November 1, 2005
Starfish(2)	Natural gas pipeline, gathering system and dehydration facility	Gulf of Mexico/Southern Louisiana	$	41.7	March 31, 2005
East Texas	Gathering system and gas procession assets	East Texas	$	240.7	July 30, 2004
Hobbs	Natural gas pipeline	New Mexico	$	2.3	April 1, 2004
Michigan Crude Pipeline	Common carrier crude oil pipeline	Michigan	$	21.3	December 18, 2003
Western Oklahoma	Gathering system	Western Oklahoma	$	38.0	December 1, 2003
Lubbock Pipeline	Natural gas pipeline	West Texas	$	12.2	September 2, 2003
Pinnacle	Natural gas pipelines and gathering systems	East Texas	$	39.9	March 28, 2003

(1): Includes approximately $20.2 million in cash acquired.
(2): Represents a 50% non-controlling interest.

Our Relationship with MarkWest Hydrocarbon, Inc.

We were formed by MarkWest Hydrocarbon to acquire most of its natural gas gathering and processing assets and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon remains one of our largest customers. For the six months ended June 30, 2006, it accounted for 12% of our revenues and 13% of our net operating margin. This represents a decrease from the six months ended June 30, 2006, when MarkWest Hydrocarbon accounted for 16% of our revenues and 22% of our net operating margin. We expect to continue deriving a significant portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future; however, the percentage of our revenues and net operating margins will likely continue to decline as our other businesses grow. As of June 30, 2006, MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 21% interest in the Partnership, consisting of 1,633,334 subordinated units, 836,162 common units and a 2% interest in the Partnership.

Following our equity offering of 3.3 million new common units in July 2006 (see Note 15), MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 17% interest in the Partnership, consisting of 1,633,334 subordinated units, 836,162 common units and a 2% general partner interest in the Partnership.

Under a Services Agreement, MarkWest Hydrocarbon acts in a management capacity rendering day-to-day operational, business and asset management, accounting, personnel and related administrative services to the Partnership. In return, the Partnership reimburses MarkWest Hydrocarbon for all documented expenses incurred on behalf of the Partnership and which are expressly designated as reasonably necessary for the performance of the prescribed duties and specified functions.

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Results of Operations

Operating Data

		Three months ended June 30,				Six months ended June 30,
		2006	2005	% Change		2006	2005	% Change
*Southwest:*
East Texas
	Gathering systems throughput (Mcf/d)	375,000	323,000	16.1	%	360,000	305,000	18.0	%
	NGL product sales (gallons)	40,461,000	26,222,000	54.3	%	75,897,000	50,596,000	50.0	%
Oklahoma
	Foss Lake gathering systems throughput (Mcf/d)	84,500	70,000	20.7	%	86,100	69,000	24.8	%
	Arapaho NGL product sales (gallons)	19,615,000	16,457,000	19.2	%	38,032,000	31,674,000	20.1	%
Other Southwest
	Appleby gathering systems throughput (Mcf/d)	33,600	32,000	5.0	%	33,600	30,000	12.0	%
	Other gathering systems throughput (Mcf/d)	21,900	16,000	36.9	%	20,500	17,000	20.6	%
	Lateral throughput volumes (Mcf/d)	93,600	91,000	2.9	%	71,500	72,000	(0.7	)%
*Northeast:*
Appalachia(1)
	Natural gas processed for a fee (Mcf/d)	197,000	192,000	2.6	%	201,000	200,000	0.5	%
	NGLs fractionated for a fee (Gal/day)	450,000	421,000	6.9	%	450,000	441,000	2.0	%
	NGL product sales (gallons)	10,468,000	10,154,000	3.1	%	20,951,000	20,919,000	0.2	%
Michigan:
	Natural gas processed for a fee (Mcf/d)	5,800	6,800	(14.7	)%	5,200	6,900	(24.6	)%
	NGL product sales (Mcf/d)	1,394,000	1,493,000	(6.6	)%	2,843,000	3,056,000	(7.0	)%
	Crude oil transported for a fee (Bbl/d)	14,900	14,200	4.9	%	14,600	14,200	2.8	%
*Gulf Coast(2):*
	Natural gas processed for a fee (Mcf/d)	130,000	NA	NA		125,000	NA	NA
	NGLs fractionated for a fee (Gal/day)	1,128,000	NA	NA		1,086,000	NA	NA

(1): Includes throughput from our Kenova, Cobb, and Boldman processing plants.
(2): We acquired the Javelina system (Gulf Coast) on November 1, 2005.

Segment Reporting

Segments. We have six segments, based on geographic areas of operations, described below.

Southwest Business Unit

•: East Texas. We own the East Texas System, consisting of natural gas gathering system pipelines, centralized compressor stations, and a natural gas processing facility and NGL pipeline. The East Texas System is located in Panola, Harrison and Rusk Counties and services the Carthage Field, one of Texas' largest onshore natural gas fields. Producing formations in Panola County consist of the Cotton Valley, Pettit and Travis Peak formations, which together form one of the largest natural gas producing regions in the United States. The Carthage Field has an estimated 18 Tcf of remaining recoverable reserves and cumulative historical production in excess of 12 Tcf.
•: Oklahoma. We own the Foss Lake gathering system and the Arapaho gas processing plant, located in Roger Mills, Custer and Ellis counties of western Oklahoma. The gathering portion

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consists of a pipeline system that is connected to natural gas wells and associated compression facilities. All of the gathered gas ultimately is compressed and delivered to the processing plant. After processing, the residue gas is delivered to a third-party pipeline and natural gas liquids are sold to a single customer.

•: Other Southwest. We own 17 natural gas gathering systems located in Texas, Louisiana, Mississippi and New Mexico. These systems generally service long-lived natural gas basins that continue to experience drilling activity. We gather a significant portion of the gas produced from fields adjacent to our gathering systems. 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 Business Unit

•: 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 five natural gas processing plants, an NGL pipeline, an NGL fractionation plant and two caverns for storing propane.
•: Michigan. We own a common carrier crude oil gathering pipeline in Michigan. We refer to this system as the Michigan Crude Pipeline. We also own a natural gas gathering system and a natural gas processing plant in Michigan.

Gulf Coast Business Unit

•: Javelina. On November 1, 2005, we acquired 100% of the equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were owned 40%, 40% and 20%, respectively, by subsidiaries of El Paso Corporation, Kerr-McGee Corporation, and Valero Energy Corporation. The Javelina entities own and operate a natural gas processing facility in Corpus Christi, Texas, which treats and processes off-gas from six local refineries. The facility was constructed in 1989 to recover hydrogen and up to 28,000 barrels per day of NGLs, including olefins (ethylene and propylene), ethane, propane, mixed butane and pentanes. The facility processes approximately 125 to 130 MMcf/d of inlet gas and produces approximately 25,400 Bbl/d of NGLs.

On March 31, 2005, the Partnership acquired a 50% non-operating membership interest in Starfish Pipeline Company, LLC, ("Starfish"), whose assets are located in the Gulf of Mexico and southwestern Louisiana, from an affiliate of Enterprise Products Partners L.P. for $41.7 million. Because Starfish is a joint venture with Enbridge Offshore Pipelines LLC, which the Partnership accounts for using the equity method, the financial results for Starfish are included in equity from earnings from unconsolidated affiliates and are not included in the Gulf Coast Business Unit results.

The following summarizes the percentage of our revenue and net operating margin generated by our assets, by segment, for the six months ended June 30, 2006:

		E. Texas		Oklahoma		Other SW		Appalachia		Michigan		Gulf Coast		Total
Revenues		22	%	37	%	16	%	12	%	2	%	11	%	100	%
Net operating margin		33	%	15	%	7	%	13	%	4	%	28	%	100	%

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Three months ended June 30, 2006, Compared to three months ended June 30, 2005

East Texas

			Three months ended June 30,
			Three months ended June 30,						% Change
			2006		2005		$ Change		% Change
			(in thousands)
Revenues			$	31,591	$	19,112	$	12,479	65	%
Operating expenses:
	Purchased product costs			10,156		6,517		3,639	56	%
	Facility expenses			4,278		2,731		1,547	57	%
	Depreciation			1,907		1,145		762	67	%
	Amortization of intangible assets			2,074		2,061		13	1	%
	Accretion of asset retirement obligations			11		7		4	57	%

		Total operating expenses before selling, general and administrative expenses		18,426		12,461		5,965	48	%

Operating income before selling, general and administrative expenses			$	13,165	$	6,651	$	6,514	98	%

Revenues: Revenues increased $12.5 million, or 65%, during the three months ended June 30, 2006, relative to the comparable period in 2005. The increase was due to our Carthage gas plant beginning operations on January 1, 2006; the start-up of several new gathering expansions, the largest gathering expansion was placed in service on March 1, 2006; two new contracts being added in July 2005; and increased condensate volumes and prices over the same period a year ago.

Purchased Product Costs: Purchased product costs increased $3.6 million, or 56%, during the three months ended June 30, 2006, relative to the comparable period in 2005, primarily due to the start-up of the Carthage gas plant and the Blocker gathering system.

Facility Expenses: Facility expenses increased $1.5 million, or 57%, during the three months ended June 30, 2006, relative to the comparable period in 2005. These expenses were higher largely due to startup of the new Carthage gas plant and Blocker gathering system, including the related labor and property taxes.

Depreciation: Depreciation expense increased $0.8 million, or 67%, during the three months ended June 30, 2006, relative to the comparable period in 2005, mainly due to the new Carthage gas plant and Blocker gathering system.

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Oklahoma

			Three months ended June 30,
			Three months ended June 30,							% Change
			2006		2005		$ Change			% Change
			(in thousands)
Revenues			$	47,926	$	43,362	$	4,564		11	%
Operating expenses:
	Purchased product costs			37,022		38,847		(1,825	)	(5	)%
	Facility expenses			1,466		1,146		320		28	%
	Depreciation			739		556		183		33	%
	Accretion of asset retirement obligations			7		—		7		NA

		Total operating expenses before selling, general and administrative expenses		39,234		40,549		(1,315	)	(3	)%

Operating income before selling, general and administrative expenses			$	8,692	$	2,813	$	5,879		209	%

Revenues: Revenues increased $4.6 million, or 11%, during the three months ended June 30, 2006, relative to the comparable period in 2005. The increase is mostly attributed to an increase in condensate sales ($6.0 million), driven by a significant increase in condensate prices, and increased gathering fees ($0.4 million). This was offset by a decrease in processing volumes ($1.8 million).

Purchased Product Cost: Purchased product costs decreased $1.8 million, or 5%, during the three months ended June 30, 2006, relative to the comparable period in 2005, primarily due to a decrease in natural gas volumes and price.

Facility Expenses: Facility expenses increased $0.3 million, or 28%, during the three months ended June 30, 2006, relative to the comparable period in 2005, mostly due to additional compression expenses.

Depreciation: Depreciation expense increased $0.2 million, or 33%, during the three months ended June 30, 2006, relative to the comparable period in 2005, due to capital placed in service to accommodate growing gathering systems and new well connects.

Other Southwest

			Three months ended June 30,
			Three months ended June 30,							% Change
			2006		2005		$ Change			% Change
			(in thousands)
Revenues			$	22,270	$	22,302	$	(32	)	0	%
Operating expenses:
	Purchased product costs			17,815		18,987		(1,172	)	(6	)%
	Facility expenses			1,601		955		646		68	%
	Depreciation			1,040		878		162		18	%
	Amortization of intangible assets			—		34		(34	)	(100	)%
	Accretion of asset retirement obligations			5		2		3		NA

		Total operating expenses before selling, general and administrative expenses		20,461		20,856		(395	)	(2	)%

Operating income before selling, general and administrative expenses			$	1,809	$	1,446	$	363		25	%

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Revenues: Revenues decreased less than 1% during the three months ended June 30, 2006, relative to the comparable period in 2005. Favorable condensate sales and gathering fees, as compared to the prior period, were offset by a decrease in natural gas sales resulting from contractual changes.

Purchased Product Costs: Purchased product costs decreased $1.2 million, or 6%, during the three months ended June 30, 2006, relative to the comparable period in 2005, primarily due to contractual changes, the shut-in of a gathering system, and the sale of two gathering systems in early 2006, which were included in 2005 but not in 2006.

Facility Expenses: Facility expenses increased $0.6 million, or 68%, during the three months ended June 30, 2006, relative to the comparable period in 2005. The increase is primarily a result of additional compressor maintenance and an increase in system operating expenses, primarily at Appleby.

Depreciation: Depreciation expense increased $0.2 million, or 18%, during the three months ended June 30, 2006, relative to the same period in 2005, primarily due to new compressor assets placed in service in 2006.

Appalachia

			Three months ended June 30,
			Three months ended June 30,							% Change
			2006		2005		$ Change			% Change
			(in thousands)
Revenues:
	Unaffiliated		$	430	$	527	$	(97	)	(18	)%
	Affiliated			17,879		14,706		3,173		22	%

Total revenues				18,309		15,233		3,076		20	%

Operating expenses:
	Purchased product costs			10,347		8,660		1,687		19	%
	Facility expenses			3,474		5,113		(1,639	)	(32	)%
	Depreciation			898		828		70		8	%
	Accretion of asset retirement obligations			3		—		3		NA

		Total operating expenses before selling, general and administrative expenses		14,722		14,601		121		1	%

Operating income before selling, general and administrative expenses			$	3,587	$	632	$	2,955		468	%

Revenues: Revenues increased $3.1 million, or 20%, during the three months ended June 30, 2006, relative to the comparable period in 2005. The increase was due to higher prices and production volumes at our Maytown facility. Revenues also benefited from increased gas volumes at Kenova and Cobb, and increased liquid volumes at Kenova, Cobb, and Boldman.

Purchased Product Costs: Purchased product costs increased $1.7 million, or 19%, during the three months ended June 30, 2006, relative to the comparable period in 2005. The rise in costs is attributed to increases in both prices and volumes at Maytown, as mentioned above. Reduced trucking expenses offset the increase as we have been able to utilize our ALPS pipeline after repairs incurred in 2005.

Facility Expenses: Facility expenses decreased $1.6 million, or 32%, during the three months ended June 30, 2006, relative to the comparable period in 2005. These expenses were higher in 2005 due to costs incurred to repair the ALPS pipeline.

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Depreciation: Depreciation expense increased 8% during the three months ended June 30, 2006, relative to the comparable period in 2005, primarily due to increased capitalized leasehold improvements associated with repairs to the ALPS pipeline.

Michigan

			Three months ended June 30,
			Three months ended June 30,									% Change
			2006			2005			$ Change			% Change
			(in thousands)
Revenues			$	3,288		$	3,191		$	97		3	%
Operating expenses:
	Purchased product costs			838			851			(13	)	(2	)%
	Facility expenses			1,480			1,415			65		5	%
	Depreciation			1,180			1,169			11		1	%

		Total operating expenses before selling, general and administrative expenses		3,498			3,435			63		2	%

Operating loss before selling, general and administrative expenses			$	(210	)	$	(244	)	$	34		(14	)%

Revenues: Revenues increased 3% during the three months ended June 30, 2006, relative to the comparable period in 2005, principally due to an increase in product prices at our processing facility.

Purchased Product Costs: Purchased product costs decreased 2% during the three months ended June 30, 2006, relative to the comparable period in 2005, mostly due to reduced processing volumes.

Facility Expenses: Facility expenses increased 5% during the three months ended June 30, 2006, relative to the comparable period in 2005, primarily due to higher processing and treating fees at our processing facility.

Depreciation. Depreciation expense increased 1% during the three months ended June 30, 2006, relative to the comparable period in 2005, mostly due to additional vehicles purchased during the period.

Given the continuing losses and moderately positive cash flows relating to the Michigan assets, management continues to consider alternatives for these assets. As a result, we are evaluating different options and potential impairments.

Gulf Coast

			Three months ended June 30,
			Three months ended June 30,				$ Change	% Change
			2006		2005		$ Change	% Change
			(in thousands)
Revenues			$	18,896	$	—	NA	NA
Operating expenses:
	Facility expenses			3,166		—	NA	NA
	Depreciation			1,620		—	NA	NA
	Amortization of intangible assets			1,953		—	NA	NA

		Total operating expenses before selling, general and administrative expenses		6,739		—	NA	NA

Operating income before selling, general and administrative expenses			$	12,157	$	—	NA	NA

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The increase in the above categories is the result of our acquisition of Javelina in November 2005.

Consolidated Financial Information

			Three months ended June 30,
			Three months ended June 30,									% Change
			2006			2005			$ Change			% Change
			(in thousands)
Total segment operating income			$	39,200		$	11,298		$	27,902		247	%
	Derivatives not allocated to segments			(6,901	)		(240	)		(6,661	)	2,775	%
	Selling, general and administrative			(8,988	)		(6,311	)		(2,677	)	42	%

		Income from operations		23,311			4,747			18,564		391	%
Equity in earnings from unconsolidated affiliates				1,228			990			238		24	%
Interest income				259			63			196		311	%
Interest expense				(10,714	)		(4,558	)		(6,156	)	135	%
Amortization of deferred finance costs				(826	)		(497	)		(329	)	66	%
Miscellaneous income (expense)				1,515			(74	)		1,589		2,147	%

Income before Texas margin tax			$	14,773		$	671		$	14,102		2,102	%
	Texas margin tax (Note 14)			(679	)		—			(679	)	NA

Net income			$	14,094		$	671		$	13,423		2,000	%

Derivatives: Loss from derivatives, a component of revenue not allocated to segments, increased $6.7 million, or 2,775%, due to increased use of derivative instruments for which, consistent with previous announcements, we have not elected to adopt hedge accounting treatment. $6.4 million of the 2006 loss was from mark-to-market, which is a non-cash charge that does not impact distributable cash flow.

Selling, General and Administrative Expense: Selling, general and administrative expenses increased $2.7 million, or 42%, during the three months ended June 30, 2006, relative to the comparable period in 2005. The increase is due to a one-time charge to terminate the old headquarters lease of $0.9 million; higher non-cash, equity-based compensation expense of $0.6 million, primarily due to the Partnership's increased market value; labor costs related to additional personnel to support our growth and strategic objectives of $1.5 million; and higher insurance premiums of $0.7 million. These increases were offset in part by a decrease in professional fees of $0.9 million, due primarily to the majority of our audit work being completed in the first quarter of 2006, compared to extended timing in 2005.

Equity in Earnings from Unconsolidated Affiliates: Equity in earnings from unconsolidated affiliates is primarily related to our investment in Starfish, a joint venture with Enbridge Offshore Pipelines LLC. The Partnership accounts for using the equity method, and the financial results for Starfish are included as earnings from unconsolidated affiliates. For internal reporting purposes, our equity investment in Starfish is managed within our Gulf Coast Business Unit. During the three months ended June 30, 2006, our equity in earnings from unconsolidated affiliates increased $0.2 million, or 24%, due to Starfish adding a lateral pipeline during the quarter, but offset by Hurricane Rita repairs.

Interest Income: Interest income increased $0.2 million during the three months ended June 30, 2006, relative to the comparable period in 2005, primarily due to an increase in interest earned on marketable securities.

Interest Expense and Amortization of Deferred Financing Costs (a component of interest expense): Interest and amortization expense increased $6.5 million, or 128%, during the three months ended June 30, 2006, relative to the comparable period in 2005, primarily due to increased debt levels resulting from the financing of our November 2005 Javelina acquisition and higher interest rates. The

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increase in the amortization relative to the comparable period in 2005 is attributable to deferred financing costs associated with our debt refinancing completed in the fourth quarter of 2005. Deferred financing costs are being amortized over the terms of the related obligations, which approximates the effective interest method.

Miscellaneous Income (Expense): The Partnership recognized a $1.3 million gain in the second quarter of 2006 from insurance proceeds recovered from damages that occurred as a result of Hurricane Rita.

Texas Margin Tax: Texas passed a Texas margin tax law that causes the Partnership to be subject to an entity-level tax on the portion of our income that is generated in Texas. We recorded a deferred tax liability of $0.7 million, related to the Partnership's temporary differences that are expected to reverse in future periods.

Six months ended June 30, 2006, compared to six months ended June 30, 2005

East Texas

			Six months ended June 30,
			Six months ended June 30,						% Change
			2006		2005		$ Change		% Change
			(in thousands)
Revenues			$	64,079	$	33,914	$	30,165	89	%
Operating expenses:
	Purchased product costs			23,324		10,114		13,210	131	%
	Facility expenses			7,952		5,066		2,886	57	%
	Depreciation			3,718		2,157		1,561	72	%
	Amortization of intangible assets			4,147		4,122		25	1	%
	Accretion of asset retirement obligations			22		15		7	47	%

		Total operating expenses before selling, general and administrative expenses		39,163		21,474		17,689	82	%

Operating income before selling, general and administrative expenses			$	24,916	$	12,440	$	12,476	100	%

Revenues: Revenues increased $30.2 million, or 89%, during the six months ended June 30, 2006, relative to the comparable period in 2005. The increase was due to our Carthage gas plant beginning operations on January 1, 2006; the start-up of the Blocker gathering system on March 1, 2006; two new contracts being added in July 2005; and increased condensate volumes and prices over the same period a year ago. Additionally, a $1.9 million accrued liability was reversed to revenue in the first quarter of 2006. Revenues also increased due to a contract converting from a gathering agreement to a gas purchase agreement in May 2005. Under such agreements, we purchase gas from a customer and then turn around and sell that gas at essentially the same gas price. These transactions cause an increase in both revenues and purchases.

Purchased Product Costs: Purchased product costs increased $13.2 million, or131%, during the six months ended June 30, 2006, relative to the comparable period in 2005, primarily due to the start-up of the Carthage gas plant and the Blocker gathering system. Additionally, the conversion in May 2005 of a contract from a gathering agreement to a gas purchase agreement increased purchase product costs.

Facility Expenses: Facility expenses increased $2.9 million, or 57%, during the six months ended June 30, 2006, relative to the comparable period in 2005. These expenses were higher largely due to startup of the new Carthage gas plant and Blocker gathering system, including the related labor and property taxes.

Depreciation: Depreciation expense increased $1.6 million, or 72%, during the six months ended June 30, 2006, relative to the comparable period in 2005, mainly due to the new Carthage Gas Plant and Blocker gathering system.

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Oklahoma

			Six months ended June 30,
			Six months ended June 30,						% Change
			2006		2005		$ Change		% Change
			(in thousands)
Revenues			$	110,194	$	80,651	$	29,543	37	%
Operating expenses:
	Purchased product costs			92,347		71,322		21,025	29	%
	Facility expenses			3,545		2,074		1,471	71	%
	Depreciation			1,451		1,082		369	34	%
	Accretion of asset retirement obligations			13		—		13	NA

		Total operating expenses before selling, general and administrative expenses		97,356		74,478		22,878	31	%

Operating income before selling, general and administrative expenses			$	12,838	$	6,173	$	6,665	108	%

Revenues: Revenues increased $29.5 million, or 37%, during the six months ended June 30, 2006, relative to the comparable period in 2005. The increase was due primarily to higher volumes, from 30 new well connects in 2006, and higher prices for all products.

Purchased Product Cost: Purchased product costs increased $21.0 million, or 29%, during the six months ended June 30, 2006, relative to the comparable period in 2005, primarily as a result of higher inlet volumes and higher natural gas prices.

Facility Expenses: Facility expenses increased $1.5 million, or 71%, during the six months ended June 30, 2006, relative to the comparable period in 2005. The increase is primarily due to additional compression costs, rising facilities expenses, and higher operating taxes.

Depreciation: Depreciation expense increased $0.4 million, or 34%, during the six months ended June 30, 2006, relative to the comparable period in 2005, related to additional capital placed in service to accommodate a growing gathering system and new well connects.

Other Southwest

			Six months ended June 30,
			Six months ended June 30,							% Change
			2006		2005		$ Change			% Change
			(in thousands)
Revenues			$	47,730	$	40,457	$	7,273		18	%
Operating expenses:
	Purchased product costs			39,238		33,714		5,524		16	%
	Facility expenses			2,952		1,963		989		50	%
	Depreciation			2,059		1,694		365		22	%
	Amortization of intangible assets			—		68		(68	)	(100	)%
	Accretion of asset retirement obligations			10		4		6		NA

		Total operating expenses before selling, general and administrative expenses		44,259		37,443		6,816		18	%

Operating income before selling, general and administrative expenses			$	3,471	$	3,014	$	457		15	%

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Revenues: Revenues increased $7.3 million, or 18%, during the six months ended June 30, 2006, relative to the comparable period in 2005. The increase was primarily due to higher volumes on the gathering systems.

Purchased Product Costs: Purchased product costs increased $5.5 million, or 16%, during the six months ended June 30, 2006, relative to the comparable period in 2005, primarily due to increased volumes and higher prices on the majority of our gathering systems.

Facility Expenses: Facility expenses increased $1.0 million, or 50%, during the six months ended June 30, 2006, relative to the comparable period in 2005. The increase was primarily a result of additional compressor maintenance and rent expense.

Depreciation: Depreciation expense increased $0.4 million, or 22%, during the six months ended June 30, 2006, relative to the same period in 2005, due to the addition of new compressors in 2006 and late 2005.

Appalachia

			Six months ended June 30,
			Six months ended June 30,							% Change
			2006		2005		$ Change			% Change
			(in thousands)
Revenue
	Unaffiliated		$	849	$	865	$	(16	)	(2	)%
	Affiliated			35,594		30,511		5,083		17	%

Total revenues				36,443		31,376		5,067		16	%

Operating expenses:
	Purchased product costs			20,457		17,913		2,544		14	%
	Facility expenses			6,815		8,870		(2,055	)	(23	)%
	Depreciation			1,738		1,645		93		6	%
	Accretion of asset retirement obligations			6		—		6		NA

		Total operating expenses before selling, general and administrative expenses		29,016		28,428		588		2	%

Operating income before selling, general and administrative expenses			$	7,427	$	2,948	$	4,479		152	%

Revenues: Total revenues increased $5.1 million, or 16%, during the six months ended June 30, 2006, relative to the comparable period in 2005. The increase was primarily a result of higher sales prices for our Maytown natural gas liquids in 2006. Higher gas and liquid volumes at the Cobb Plant and higher liquids volumes at the Boldman plant also contributed to the increase, however, such results are offset slightly by lower liquid volumes at Kenova and lower gas volumes at Boldman.

Purchased Product Costs: Purchased product costs increased $2.5 million, or 14%, during the six months ended June 30, 2006, relative to the comparable period in 2005. The rise in costs is primarily a result of higher product prices. The increase was partially offset by reduced trucking expenses, as we have been able to utilize our ALPS pipeline after repairs in 2005.

Facility Expenses: Facility expenses decreased $2.1 million, or 23%, during the six months ended June 30, 2006, relative to the comparable period in 2005. These expenses were higher in 2005 due to costs incurred to repair the ALPS pipeline.

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Depreciation: Depreciation expense increased $0.1 million, or 6%, during the six months ended June 30, 2006, relative to the comparable period in 2005, due to increased capitalized leasehold improvements associated with the ALPS pipeline.

Michigan

			Six months ended June 30,
			Six months ended June 30,									% Change
			2006			2005			$ Change			% Change
			(in thousands)
Revenues			$	6,485		$	6,346		$	139		2	%
Operating expenses:				—
	Purchased product costs			1,609			1,584			25		2	%
	Facility expenses			3,083			2,718			365		13	%
	Depreciation			2,354			2,324			30		1	%

		Total operating expenses before selling, general and administrative expenses		7,046			6,626			420		6	%

Operating loss before selling, general and administrative expenses			$	(561	)	$	(280	)	$	(281	)	100	%

Revenues: Revenues increased $0.1 million, or 2%, during the six months ended June 30, 2006, relative to the comparable period in 2005, principally due an increase in product prices at our processing facility.

Purchased Product Costs: Purchased product costs increased 2% during the six months ended June 30, 2006, relative to the comparable period in 2005, which was a result of higher product prices at our processing facility.

Facility Expenses: Facility expenses increased $0.4 million, or 13%, during the six months ended June 30, 2006, relative to the comparable period in 2005, primarily due to increased processing and treating fees at our processing facility.

Depreciation: Depreciation expense increased 1% during the six months ended June 30, 2006, relative to the comparable period in 2005, mostly due to additional vehicles purchased during the period.

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Gulf Coast

			Six months ended June 30,
			Six months ended June 30,						% Change
			2006		2005		$ Change		% Change
			(in thousands)
Revenues			$	33,852	$	—		NA	NA
Operating expenses:
	Facility expenses			5,112		—		NA	NA
	Depreciation			3,237		—		NA	NA
	Amortization of intangible assets			3,896		—		NA	NA

		Total operating expenses before selling, general and administrative expenses		12,245		—		—	NA

Operating income before selling, general and administrative expenses			$	21,607	$	—	$	—	NA

The increase in the above categories is the result of our acquisition of Javelina in November 2005.

Consolidated Financial Information

				Six months ended June 30,
				Six months ended June 30,									% Change
				2006			2005			$ Change			% Change
				(in thousands)
Total segment operating income				$	69,698		$	24,295		$	45,403		187	%
	Derivatives not allocated to segments				(6,661	)		(147	)		(6,514	)	4,431	%
	Selling, general and administrative				(17,326	)		(10,950	)		(6,376	)	58	%

		Income from operations			45,711			13,198			32,513		246	%
Equity in earnings from unconsolidated affiliates					2,173			990			1,183		119	%
Interest income					479			130			349		268	%
Interest expense					(21,690	)		(8,232	)		(13,458	)	163	%
Amortization of deferred finance costs					(1,634	)		(972	)		(662	)	68	%
Miscellaneous income (expense)					3,607			(178	)		3,785		2,126	%

			Income before Texas margin tax	$	28,646		$	4,936		$	23,710		480	%
	Texas margin tax:				(679	)		—			NA

Net income				$	27,967		$	4,936		$	23,031		467	%

Derivatives: Loss from derivatives, a component of revenue not allocated to segments, increased $6.5 million, or 4,431%, due to increased use of derivative instruments for which, consistent with previous announcements, we have not elected to adopt hedge accounting treatment. $6.7 million of the 2006 loss was from mark-to-market, which is a non-cash charge that does not impact distributable cash flow.

Selling, General and Administrative Expense: Selling, general and administrative expenses increased $6.4 million, or 58%, during the six months ended June 30, 2006, relative to the comparable period in 2005. The increase is due to a one-time charge to terminate the old headquarters lease of $0.9 million; higher non-cash, equity-based compensation expense of $0.9 million, primarily due to the Partnership's increased market value; labor costs related to additional personnel to support our growth and strategic objectives of $1.2 million; higher insurance premiums of $2.2 million; and professional services of $0.4 million.

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Equity in earnings from unconsolidated affiliates: Equity in earnings from unconsolidated affiliates is primarily related to our investment in Starfish, a joint venture with Enbridge Offshore Pipelines LLC. The Partnership accounts for using the equity method, and the financial results for Starfish are included as earnings from unconsolidated affiliates. For internal reporting purposes, our equity investment in Starfish is managed within our Gulf Coast Business Unit. During the six months ended June 30, 2006, our equity in earnings from unconsolidated affiliates increased $1.2 million, or 119%, relative to the comparable period in 2005. The increase was primarily because our 2006 results included Starfish for six months, compared to just three months in 2005 ($0.9 million).

Interest Income: Interest income increased $0.3 million, or 268%, during the six months ended June 30, 2006, relative to the comparable period in 2005, primarily due to an increase in interest earned on marketable securities.

Interest Expense and Amortization of Deferred Financing Costs (a component of interest expense): Interest and amortization expense increased $14.1 million, or 100%, during the six months ended June 30, 2006, relative to the comparable period in 2005, primarily due to increased debt levels resulting from the financing of our 2005 acquisitions and higher interest rates. The increase in the amortization of deferred financing costs in 2006, relative to the comparable period in 2005, is attributable to costs associated with our debt refinancing completed in the fourth quarter of 2005. Deferred financing costs are being amortized over the terms of the related obligations, which approximates the effective interest method.

Miscellaneous Income (Expense): The Partnership recognized a $3.1 million gain from insurance proceeds recovered from damages that occurred as a result of Hurricane Rita.

Liquidity and Capital Resources

Our primary sources of liquidity to meet operating expenses and fund capital expenditures (other than for certain acquisitions), are cash flows generated by our operations and our access to equity and debt markets. The equity and debt markets, public and private, retail and institutional, have been our principal source of capital used to finance a significant amount of our growth, including acquisitions.

On December 29, 2005, MarkWest Energy Operating Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended and restated credit agreement ("Partnership Credit Facility"). It provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a revolving facility of $250.0 million and a $365.0 million term loan, which can be repaid at any time without penalty. Under certain circumstances, the Partnership Credit Facility can be increased from $250 million up to $450 million. The credit facility is guaranteed by the Partnership and all of the Partnership's subsidiaries and is collateralized by substantially all of the Partnership's assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the London Inter Bank Offering Rate ("LIBOR"); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Facility's administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Partnership's Consolidated Senior Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in

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excess of $50.0 million ("Acquisition Adjustment Period"). Borrowings under the Partnership Credit Facility were used to finance, in part, the Javelina acquisition discussed above. On June 30, 2006, the available borrowing capacity under the Partnership Credit Facility was $243.7 million.

Cash generated from operations, borrowings under the Partnership Credit Facility and funds from our private and public equity offerings are our primary sources of liquidity. The timing of our efforts to raise equity in the future, however, will be influenced by our failure to file in a timely manner our Annual Report on Form 10-K for the year ended December 31, 2004, and our quarterly report on Form 10-Q for the quarter ending March 31, 2005. In order to raise capital through a public offering with the SEC, we will not have the ability to incorporate by reference information from our future filings into a new registration statement until October 11, 2006. To raise additional capital through public debt or equity offerings, we are required to file a Form S-1, which is a long-form type of registration statement.

At June 30, 2006, the Partnership and its subsidiary, MarkWest Energy Finance Corporation, also have $225.0 million in senior notes outstanding, at a fixed rate of 6.875%. The notes mature on November 2, 2014. The proceeds from these notes were used to pay down our outstanding debt under our credit facility in October 2004. Subject to compliance with certain covenants, we may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.

The indenture governing the senior notes due 2014 limits the activity of the Partnership and its restricted subsidiaries. The provisions of such indenture place limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership's affiliates; sell assets, including equity interests of the Partnership's subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.

On July 6, 2006, the Partnership completed its underwritten public offering of 3.0 million common units (the "Common Unit Offering") at a public offering price of $39.75 per common unit. In addition, on July 12, 2006, the Partnership completed the sale of an additional 300,000 common units to cover over-allotments in connection with the Common Unit Offering. The sale of units resulted in total gross proceeds of $131.2 million, and net proceeds of $127.3 million, after the underwriters' commission and legal, accounting and other transaction expenses. The Partnership intends to use the net proceeds from the offering, which includes a capital contribution from its general partner to maintain its 2% general partner interest in the Partnership, to repay a portion of the term debt under the Partnership Credit Facility.

On July 6, 2006, the "Partnership and its subsidiary, MarkWest Energy Finance Corporation issued $200,000,000 in aggregate principal amount of 8¹/2% senior notes due 2016 (the "2016 Senior Notes").

The Senior Notes will mature on July 15, 2016, and interest is payable each July 15 and January 15, commencing January 15, 2007. The Partnership closed this private placement on July 6, 2006. The net proceeds from the private placement were approximately $191.2 million, after deducting the initial purchasers' discounts and legal, accounting and other transaction expenses. The Partnership intends to use the net proceeds from the offering to repay a portion of the term debt under the Partnership Credit Facility. Affiliates of several of the initial purchasers, including RBC Capital Markets Corporation, J.P. Morgan Securities Inc., and Wachovia Capital Markets, LLC, are lenders under the Partnership Credit Facility.

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The indenture governing the senior notes due 2016 restricts the Partnership's ability and the ability of certain of its subsidiaries to borrow money, pay distributions or dividends on equity or purchase, redeem or otherwise acquire equity, make investments, use assets as collateral in other transactions, enter into sale and leaseback transactions, sell certain assets or merge with or into other companies, enter into transactions with affiliates, and engage in unrelated businesses. These covenants are subject to a number of important exceptions and qualifications. If at any time when the senior notes are rated investment grade by both Moody's Investors Service, Inc. and Standard & Poor's Rating Services, and no Default (as defined in the Indenture) has occurred and is continuing, many of the covenants will terminate and the Partnership and its subsidiaries will cease be subject to them.

Our ability to pay distributions to our unitholders and to fund planned capital expenditures and make acquisitions will depend upon our future operating performance. That, in turn, will be affected by prevailing economic conditions in our industry, as well as financial, business and other factors, some of which are beyond our control.

The Partnership revised its budget as of June 30, 2006 to $95.2 million for capital expenditures in 2006, exclusive of any acquisitions. As of June 30, 2006, we have $69.8 million remaining in our budget consisting of $68.1 million for expansion capital and $1.7 million for sustaining capital. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets, or facilitate an increase in volumes within our operations, whether through construction or acquisition. Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.

Cash Flow

	Six months ended June 30,
	2006			2005
	(in thousands)
Net cash provided by operating activities	$	78,880		$	15,754
Net cash used in investing activities		(46,859	)		(73,050	)
Net cash provided by (used in) financing activities		(31,033	)		46,236

Net cash provided by operating activities increased $63.1 million during the six months ended June 30, 2006, compared to the six months ended June 30, 2005. The increase was influenced by an increase in net income, offset by an increase in certain non-cash operating expenses, primarily depreciation and amortization for a full year from our East Texas acquisition, and two months from our November acquisition of Javelina. As anticipated, overall our 2006 volumes have been higher than in 2005, and the cash provided by operating activities in 2006 continues to exceed 2005 levels.

Net cash used in investing activities was lower during the six months ended June 30, 2006, than during the six months ended June 30, 2005, primarily due to our 2005 investment in a 50% non-operating interest in Starfish for $41.7 million, in March of 2005. The Partnership used cash of $24.8 million and $31.4 million for capital expenditures during the six months ended June 30, 2006 and 2005, respectively. In the first half of 2006 we increased our investment in Starfish by $15.9 million. The majority of the investment financed 50% of the purchase of a lateral pipeline acquired by Starfish in May 2006.

Net cash provided by (used in) financing activities decreased $77.3 million during the six months ended June 30, 2006, compared to the six months ended June 30, 2005. The decrease was due primarily to net paydowns from additional long-term debt offset partially by private placement proceeds to fund our acquisitions in 2005. Distributions to unitholders increased to $25.9 million in the first half of 2006, from $19.1 million in the same period of 2005.

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Matters Impacting Future Results

During August and September 2005 Hurricanes Katrina and Rita caused severe and widespread damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions. Operations of our unconsolidated affiliate, Starfish Pipeline Company were nominally impacted by Hurricane Katrina but were significantly impacted by Hurricane Rita. While Starfish has substantially returned to normal operations, several sections of the system have not been fully repaired and returned to operation. We are submitting insurance claims on an on-going basis relating to both business interruption and property damage. We have recorded a $3.1 million in insurance recoveries with respect to our property loss claims, and anticipate continued recovery for expenses and losses incurred as repairs proceed.

The loss to both offshore and onshore assets resulting from Hurricane Rita has led to substantial insurance claims within the oil and gas industry. Along with other industry participants, we have seen our insurance costs increase substantially within this region as a result of these developments. We have renewed our insurance coverage relating to Starfish during the second quarter and mitigated a portion of the cost increase by reducing our coverage and adding a more broad self-insurance element to our overall coverage.

Critical Accounting Policies

Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Preparation of these statements requires management to make significant judgments and estimates. Some accounting policies have a significant impact on amounts reported in these financial statements. A summary of significant accounting policies and a description of accounting policies that are considered critical may be found in our Annual Report on Form 10-K for the period ending December 31, 2005, in Note 2 of the Notes to the Consolidated Financial Statements, and in the Critical Accounting Policies section of Management's Discussion and Analysis of Financial Condition and Results of Operations.

Recent Accounting Pronouncements

In February 2006 the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140 ("SFAS 155"). This statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"), and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities and resolves issues addressed in SFAS 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interest in Securitized Financial Assets." This Statement: (a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation; (b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133; (c) establishes a requirement to evaluate beneficial interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation; (d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and, (e) eliminates restrictions on a qualifying special-purpose entity's ability to hold passive derivative financial instruments that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires presentation within the financial statements that identifies those hybrid financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value of those instruments. The Partnership is required to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although early adoption is permitted as of the beginning of an entity's fiscal year. The provisions of SFAS 155 are not expected to have an impact.

B-53

In March 2006 the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140. FAS No. 156 establishes, among other things, the accounting for all separately recognized servicing assets and servicing liabilities by requiring that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, if practicable. SFAS No. 156 is effective as of the beginning of an entity's first fiscal year that begins after September 15, 2006. The adoption of SFAS No. 156 will have no impact on our results of operations or our financial position.

In June 2006 the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. the Partnership is evaluating the impact of this new pronouncement on its consolidated financial statements.

B-54

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price changes and, to a lesser extent, interest rate changes.

Commodity Price Risk

Our primary risk management objective is to manage volatility in our cash flows. A committee, comprised of the senior management team of our general partner, oversees all of our derivative activity.

We may utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps and options on the over-the-counter ("OTC") market. The Partnership may also enter into futures contracts traded on the New York Mercantile Exchange ("NYMEX"). Swaps and futures contracts allow us to manage volatility in our margins because corresponding losses or gains on the financial instruments are generally offset by gains or losses in our physical positions.

We enter into OTC swaps with financial institutions and other energy company counterparties. We conduct a standard credit review on counterparties and have agreements containing collateral requirements where deemed necessary. We use standardized swap agreements that allow for offset of positive and negative exposures. We may be subject to margin deposit requirements under OTC agreements (with non-bank counterparties) and NYMEX positions.

The use of derivative instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected, requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that we enter into derivative instruments, we may be prevented from realizing the benefits of favorable price changes in the physical market. We are similarly insulated, however, against unfavorable changes in such prices.

The Partnership's primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of natural gas, NGLs and crude oil. Swaps and futures contracts may allow the Partnership to reduce volatility in its margins because losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership's physical positions.

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The following table includes information on MarkWest Energy's specific derivative positions at June 30, 2006:

Costless collars:	Period	Floor		Cap		Fair value at June 30, 2006
						(in thousands)
Crude Oil—500 Bbl/d	2006	$	57.00	$	67.00	$	(849	)
Crude Oil—250 Bbl/d	2006	$	57.00	$	67.00		(424	)
Crude Oil—205 Bbl/d	2006	$	57.00	$	65.10		(409	)
Crude Oil—78 Bbl/d	2006	$	67.50	$	77.30		(27	)
Crude Oil—155 Bbl/d	2007	$	67.50	$	78.55		(121	)
Crude Oil—250 Bbl/d	2007	$	67.50	$	79.15		(175	)
Crude Oil—200 Bbl/d	2007	$	70.00	$	75.95		(175	)
Propane—20,000 Gal/d	2006	$	0.90	$	0.99		(737	)
Propane—10,000 Gal/d	2006	$	0.97	$	1.15		(132	)
Ethane—22,950 Gal/d	2006	$	0.65	$	0.80		(198	)
Natural Gas—1,575 Mmbtu/d	2006	$	8.67	$	10.86		803
Natural Gas—1,575 Mmbtu/d	Jan-Mar 2007	$	9.00	$	12.50		128
Natural Gas—400 Mmbtu/d	2007	$	8.25	$	10.03		36
Natural Gas—1,500 Mmbtu/d	Apr-Dec 2007	$	7.25	$	10.25		147
Natural Gas—1,500 Mmbtu/d	Jan-Mar 2008	$	8.00	$	11.29		(42	)

						$	(2,175	)

Swaps:	Period	Fixed price		Fair value at June 30, 2006
				(in thousands)
Crude Oil—250 Bbl/d	2006	$	62.00	$	(614	)
Crude Oil—185 Bbl/d	2006	$	61.00		(487	)
Crude Oil—250 Bbl/d	2007	$	65.30		(926	)
Crude Oil—140 Bbl/d	2007	$	74.10		(94	)
Propane—5,000 Gal/d	2006	$	1.08		(104	)
Natural gas	Jun-Oct 2006				18

					(2,207	)

Future purchase / sale contracts:	Period	Average Fixed price		Fair value at June 30, 2006
				(in thousands)
Natural Gas—1.7 million Mmbtu (purchase)	Jul-Oct 2006	$	6.07	$	(1,349	)
Ethane—10.8 million Gallons (sale)	Jul-Oct 2006	$	0.61		(910	)
Propane—4.9 million Gallons (sale)	Jul-Oct 2006	$	1.07		(596	)
Other NGLs—4.2 million Gallons (sale)	Jul-Oct 2006	$	1.40		(214	)

					(3,069	)

				$	(7,451	)

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The impact of MarkWest Energy's commodity derivative instruments on results of operations and financial position are summarized below (in thousands):

	Three months ended June 30,						Six months ended June 30,
	2006			2005			2006			2005
Realized gains—revenue	$	(476	)	$	(251	)	$	63		$	(209	)
Unrealized gains (losses)—revenue		(6,425	)		11			(6,724	)		62
Other comprehensive income—changes in fair value		—			438			—			247
Other comprehensive income—settlement		—			(222	)		—			(180	)

	June 30, 2006			December 31, 2005
Unrealized gains—current asset	$	1,131		$	—
Unrealized losses—current liability		(7,924	)		(728	)
Unrealized losses—non-current liability		(658	)		—

The Partnership entered into the following derivative positions subsequent to June 30, 2006:

Costless Collars	Period	Floor		Cap
Propane—23,000 Gal/d	Jan-Mar 2007	$	1.05	$	1.28
Propane—30,000 Gal/d	Apr-Dec 2007	$	0.96	$	1.16
Propane—30,000 Gal/d	Jul-Dec 2007	$	0.97	$	1.16
Propane—30,000 Gal/d	Oct-Dec 2007	$	0.98	$	1.18
Crude oil—130 Bbl/d	2007	$	70.00	$	88.50
Crude oil—120 Bbl/d	2007	$	70.00	$	86.40
Crude oil—250 Bbl/d	2007	$	70.00	$	88.25

Swaps		Period		Weighted Average Price
Ethane—50,000 Gal/d (swap)		Jan-Mar 2007		$	0.78
Ethane—50,000 Gal/d (put)		Apr-Dec 2007		$	0.65

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Item 4. Controls and Procedures

In connection with the preparation of this quarterly report on Form 10-Q, our senior management, with participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2006, pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the "Act"). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of June 30, 2006, as a result of the material weaknesses in our internal control over financial reporting, our disclosure controls and procedures were ineffective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms; and to ensure that information required to be disclosed by us in the reports that we file under the Act is accumulated and communicated to management, including our certifying officers, as appropriate, to allow timely decisions regarding required disclosures.

Throughout the first and second quarters of 2006, we have adopted remedial measures to address the deficiencies in our internal controls that were identified on December 31, 2005 and remained in effect on June 30, 2006.

Internal Control Environment. In connection with management's assessment of the effectiveness of internal control over financial reporting for the year ended December 31, 2005, we identified and Deloitte & Touche LLP confirmed, as of December 31, 2005, the presence of an ongoing material weakness related to our internal control environment. Specifically, our control environment did not sufficiently promote effective internal control over financial reporting through the management structure to prevent a material misstatement.

In order to remediate this material weakness, we are in the process of fully implementing and standardizing the following processes and procedures, which were initiated in the last two quarters of 2005:

•: We formalized the monthly account reconciliation process for all balance sheet accounts and have implemented a formal review of reconciliations by our business unit accounting management.
•: We established a compliance office focused on control deficiency identification and remediation, i.e., purchasing controls, revenue recognition controls and application and spreadsheet change controls that performs ongoing internal control evaluation and assessment and works actively with the process owners in developing appropriate remediation of control deficiencies.
•: We conducted an entity-level risk assessment, established an internal audit plan and began to execute that internal audit plan. Results are reported directly to our general partner's audit committee.
•: We enhanced entity level controls through the implementation of significant new controls.
•: We strengthened our disclosure review committee charter to solicit and review input from management personnel throughout the Partnership regarding possible instances of fraud or significant events requiring disclosure.
•: We implemented a technical accounting issues forum to address non-routine transactions and the use of critical estimates and judgment.

In addition, we are enhancing employee awareness of our Code of Conduct, ethics and anti-fraud policies, including a revised training program that we began to deliver to all employees in the second quarter of 2006. This includes heightened awareness of the ethics hotline availability and access options. We are also conducting a detailed review and re-documentation of all of our internal control

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processes and will undertake significant internal control design changes to ensure that all internal control objectives are met.

Risk management and accounting for derivative financial instruments. In connection with management's assessment of the effectiveness of internal control over financial reporting for the year ended December 31, 2005, we identified and Deloitte & Touche LLP confirmed, as of December 31, 2005, the presence of an additional material weakness related to our risk management and accounting for derivative financial instruments. We did not have adequate internal controls and processes in place to support our management's assertions with respect to the completeness, accuracy and validity of commodity transactions. The design of internal controls over commodity transactions did not support the independent validation of data or control and review of transaction activity,

In particular, personnel responsible for executing and entering transactions into commodity accounting systems also had duties that were not compatible with transaction execution and entry. In order to remediate this material weakness, we added the following personnel in July 2005, January and June 2006, respectively:

•: Vice President of Risk and Compliance, to oversee and ensure improvements in our commodity transaction verification and monitoring capabilities; and
•: Director of Risk Management and staff to establish appropriate verification and monitoring activities associated with our commodity transactions.
•: Credit Manager, to establish more robust monitoring and reporting processes around our credit concentrations and risk.

At the end of the second quarter of 2006, we also segregated our front-office (the transaction personnel), mid-office (the controllers), and back-office (the accountants) processes related to our financial commodity transactions and a portion of our physical trading to ensure that proper segregation of duties exists and that control procedures are carried out by the appropriate groups. We are focused on attaining proper segregation for our remaining physical transaction over the coming months. We are enhancing our risk management policies and procedures related to the review and approval of material purchase or sale contracts that may meet the definition of derivatives. Additionally, we are enhancing our financial analysis around commodity transactions and our reporting to executive management and the board of directors. Finally, we moved the responsibility for credit risk management to the mid-office in the second quarter of 2006.

In addition, we have applied compensating procedures and processes as necessary to ensure the reliability of our financial reporting. Such additional procedures included detail management review of our account reconciliations for all accounts in all business units and multiple-level management review of account reconciliations for all accounts in all business. Accordingly, management believes, based on its knowledge, that (i) this report does not contain any untrue statement of a material fact that would make the statements misleading; (ii) this report does not omit any material fact, the omission of which would make the statements misleading, in light of the circumstance under which they were made with respect to the period covered by this report and (iii) the financial statements, and other financial information included in this report, fairly present in all material respects our financial condition, results of operations and cash flows as of, and for, the periods presented in this report.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

In the ordinary course of its business MarkWest Energy Partners is subject to a variety of risks and disputes normally incident to its business and as a party to various legal proceedings. We maintain insurance policies in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure either that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to future claims for property loss or business interruption to the Partnership or for third- party claims of personal and property damage, or that the coverages or levels of insurance it currently has will be available in the future at economical prices.

In early 2005 MarkWest Hydrocarbon, Inc., the Partnership and several of its affiliates were served with two lawsuits, Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al.(filed February 2, 2005), and Charles C. Reid, et al. v. MarkWest Hydrocarbon, Inc. et al., (filed February 8, 2005)., in Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00137 and Civil Action No. 05-CI-00156, which actions on February 24, 2005, were removed to the jurisdiction of the U.S. District Court for the Eastern District of Kentucky, Pikeville Division. The Partnership was served with an additional lawsuit, Community Trust and Investment Co., et al. v. MarkWest Hydrocarbon, Inc. et al., filed November 7, 2005, in Floyd County Circuit Court, Kentucky, that added five new claimants but essentially alleged the same facts and claims as the earlier two suits. On March 27, 2006, the U.S. District Court remanded the cases back to Floyd County Circuit Court, Kentucky, and the cases were consolidated into Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al., Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00137.

In late June 2006 a Notice of Probable Violation and Proposed Civil Penalty (NOPV) was issued by OPS to both MarkWest Hydrocarbon and the unaffiliated owner of the pipeline, with a proposed

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penalty of $1,070,000. Initial response to the NOPV is not due until at least September 1, 2006, and MarkWest Hydrocarbon will probably request an administrative hearing and settlement conference.

Related to the above referenced pipeline incident, MarkWest Hydrocarbon and the Partnership have filed an independent action captioned MarkWest Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al. (District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005), as removed to the U.S. District Court for the District of Colorado, Civil Action No. 1:05-CV-1948, on October 7, 2005) against its All-Risks Property and Business Interruption insurance carriers as a result of the insurance companies' refusal to honor their insurance coverage obligation to pay the Partnership for certain expenses. These include the Partnership's internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment, products, the extra transportation costs incurred for transporting the liquids while the pipeline was out of service, the reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as "other income" if and when it is received. The Partnership has not provided for a receivable for these claims because of the uncertainty as to whether and how much the Partnership will ultimately recover under the policies. The Partnership has also asserted that the cost of pipeline testing, replacement and repair are subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement. Discovery in the action is continuing.

On September 27, 2005, a lawsuit captioned C.F. Qualia Operating, Inc. v. MarkWest Pinnacle, L.P., (District Court of Midland, Texas, 385^th Judicial District, Case No. CV-45188), was served on a Partnership subsidiary, MarkWest Pinnacle, L.P., with respect to a dispute on volumes of gas purchased by the Partnership under a gas purchase agreement. This dispute was fully settled in May 2006 and the action dismissed with prejudice in June 2006.

The Partnership acquired the Javelina gas processing, transportation and fractionation business located in Corpus Christi, Texas (the "Javelina Business") on November 1, 2005. The Javelina Business was a party with numerous other defendants to three lawsuits brought by plaintiffs who had residences or businesses located near the Corpus Christi industrial area that included the Javelina gas processing plant, as well as several petroleum, petrochemical and metal processing and refining operations. These suits, styled Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause No. 98-1055-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28^TH Judicial District, severed May 18, 2005, from the Gonzales case cited above); and Jesus Villarreal v. Koch Refining Co. et al., (Cause No. 05-01977-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed April 27, 2005), set forth claims for personal injury or property damage, harm to business operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area. The Gonzales action has been settled pursuant to a mediation held December 9, 2005. The other actions have been and are being vigorously defended and, based on initial evaluation and consultations, it appears at this time that these actions should not have a material adverse impact on the Partnership.

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Item 6. Exhibits

10.1	(1)	Lease Agreement dated as of April 19, 2006, between MarkWest Energy Partners, L.P. and Park Central Property, L.L.C.
10.2	+	Gas Processing Agreement dated as of May 10, 2006, between MarkWest Pinnacle, L.P. and Chesapeake Exploration, L.P.
31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on April 25, 2006.
+: Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested has been filed separately with the Securities and Exchange Commission.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	MarkWest Energy Partners, L.P. (Registrant)
	By:	MarkWest Energy GP, L.L.C., Its General Partner
Date: August 4, 2006	/s/ FRANK M. SEMPLE Frank M. Semple Chief Executive Officer
Date: August 4, 2006	/s/ NANCY K. MASTEN Nancy K. Masten Senior Vice President and Chief Accounting Officer

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