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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

FORM 10-K

Commission File Number 1-11566

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

Securities registered pursuant to Section 12(b) of the Act: Common Units, $0.01 par value

Securities registered pursuant to Section 12(g) of the Act: None

        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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

        Indicate by check mark whether the registrant is an accelerated filter (as defined in Rule 126-2 of the Act). Yes o    No ý

        The aggregate market value of Common Units held by non-affiliates of the registrant on June 30, 2002 was approximately $51,269,438.

        The number of the registrant's Common Units as of February 28, 2003, was 2,384,625.

DOCUMENTS INCORPORATED BY REFERENCE

        None.

MarkWest Energy Partners, L.P.
Form 10-K
Table of Contents

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PART I

        Throughout this document we make statements that are classified as "forward-looking". Please refer to the "Forward-Looking Information" included later in this section for an explanation of these types of assertions. Also, in this document, unless the context requires otherwise, references to "we"," us"," our", "MarkWest Energy" or the "Partnership" are intended to mean MarkWest Energy Partners, L.P., and its consolidated subsidiaries.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

        MarkWest Energy Partners, L.P., a publicly traded Delaware limited partnership, was formed on January 25, 2002, but did not conduct operations until the May 24, 2002 closing of our initial public offering (the IPO). We are engaged in the gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquids (NGLs). We are the largest processor of natural gas in the northeastern United States, processing gas from the Appalachian basin, one of the country's oldest natural gas producing regions, and from Michigan.

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

        We focus on providing fee-based services to customers, limiting commodity price risks and taking advantage of the tax benefits of a limited partnership structure. Our assets are grouped into one reportable business segment—midstream services. You should read the following discussion and analysis in conjunction with our Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K.

        We were formed by MarkWest Hydrocarbon, Inc. (MarkWest Hydrocarbon) to acquire most of its natural gas gathering and processing and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon formed us as a publicly traded limited partnership primarily to reduce our cost of capital thereby enhancing our ability to more efficiently grow our operations. The limited partnership structure provides us with access to capital markets as a source of financing in addition to that provided by our credit facility, as well as the ability to use common units in connection with acquisitions.

        Discussions of our business and properties include time periods in which our assets were held by MarkWest Hydrocarbon. MarkWest Hydrocarbon controls our operations through its ownership of our general partner. Additionally, MarkWest Hydrocarbon has a significant limited partner ownership interest in us through its ownership of a majority of our subordinated units. As of December 31, 2002, affiliates of MarkWest Hydrocarbon, in the aggregate, owned a 46.7% interest in the Partnership consisting of 2,479,762 subordinated units and a 2% general partner interest. MarkWest Hydrocarbon also is our largest customer, accounting for 79% of our revenues since the closing of our IPO. Further details on our relationship with MarkWest Hydrocarbon are discussed below.

Recent Developments

        On March 24, 2003, we entered into an agreement to merge with Pinnacle Natural Gas Company and certain affiliates for approximately $38 million. The acquired assets, primarily located in Texas, are comprised of (a) three lateral natural gas pipelines transporting up to 1.1 Bcf/day (one billion cubic feet) of natural gas under firm contracts to power plants and (b) eighteen gathering systems gathering more than 44,000 Mcf/d (thousand cubic feet per day). The acquisition complements and expands our core fee-based business, while providing geographic and customer diversification. The acquisition will

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be financed primarily through borrowings under our credit facility, which was recently expanded by $15 million.

Business Strategies

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

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Increasing utilization of our existing facilities. We seek to capture additional natural gas production from existing customers and to provide services to other natural gas producers in our areas of operation. With our recent Appalachian expansion (discussed below) and current excess capacity, we can increase throughput at our facilities with minimal incremental costs. We own and operate four natural gas processing plants in Appalachia with aggregate design throughput capacity of approximately 320,000 Mcf/d of natural gas. We also own a fifth plant, Kermit, which is operated by a third party. Our Appalachian plants, excluding our Kermit facility, processed an average of 266,000 Mcf/d of natural gas for the year ended December 31, 2002.



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Expanding operations through new construction. By leveraging our existing infrastructure and customer relationships, we intend to continue expanding our asset base in Appalachia to meet the anticipated need for additional natural gas processing and NGL transportation, fractionation and storage facilities as the production of natural gas in the region continues to grow. As an example, during 2000 and 2001, we completed the construction of two new processing plants, the expansion of another processing plant and the near doubling in capacity of our fractionator in Appalachia. These activities increased our aggregate design throughput capacity by 127,000 Mcf/d or 56%. Our expansion also increased the volume of NGLs we fractionated at our Siloam facility from 310,000 gallons per day in 1999 to 423,000 gallons per day in 2001. We expect to further expand in the future by both constructing new facilities and increasing the capacity of our existing facilities, although no expansion took place in 2002.



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Expanding operations through acquisitions. We intend to pursue strategic acquisitions of midstream assets and businesses in our existing areas of operation in order to leverage our current asset base, personnel and customer relationships. In addition, we seek to acquire assets outside of our existing areas of operation with a view towards creating new core operating areas and to provide geographic and customer diversification. Our March 2003 acquisition of the Pinnacle companies is an example of the execution of this strategy.



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Capitalizing on our relationship with MarkWest Hydrocarbon. We believe that our relationship with MarkWest Hydrocarbon will provide us with opportunities to expand our operations as MarkWest Hydrocarbon continues to expand its exploration and production operations. This growth opportunity may include additional throughput in our existing areas of operation, as well as the opportunity to build or acquire additional midstream assets. In addition, under the terms of the omnibus agreement (discussed below) that we entered into with MarkWest Hydrocarbon, we have certain rights to purchase natural gas processing and NGL transportation, fractionation and storage assets developed by MarkWest Hydrocarbon to service its expanding exploration and production operations.

Overview of our Business and Industry

        The midstream natural gas industry in North America includes approximately 525 processing plants that process approximately 50 billion cubic feet, or Bcf, per day of raw natural gas and produce approximately 80 million gallons per day of NGLs. The industry is characterized by regional competition based on the proximity of gathering systems and processing plants to producing natural gas wells.

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        Natural gas has a widely varying composition, depending on the field, the formation, or the reservoir from which it is produced. The principal constituents of natural gas are methane and ethane, but most natural gas also contains varying amounts of heavier components, such as propane, butane and natural gasoline that may be removed by any number of processing methods.

        Most raw natural gas produced at the wellhead is not suitable for long-haul pipeline transportation or commercial use and must be compressed, transported via pipeline to a central processing facility, and then processed to remove the heavier hydrocarbon components and other contaminants that would interfere with pipeline transportation or the end use of the gas. Our business is providing all of these necessary services for either a cash fee or a percentage of the NGLs removed or gas units processed.

Natural Gas Processing

        Natural gas processing involves the separation of raw natural gas into pipeline quality natural gas, principally methane, and NGLs, as well as the removal of contaminants. In this process, raw natural gas from the wellhead is gathered at a processing plant, typically located near the production area, where it is dehydrated and treated, then sent through a cryogenic or other process from which a mixed NGL stream is recovered.

        The removal and separation of individual hydrocarbons by processing is possible because of differences in physical properties, as each component has a distinctive weight, boiling point, vapor pressure and other physical characteristics. Natural gas may also contain water, sulfur compounds, carbon dioxide, nitrogen, helium, or other components that may be diluents and contaminants. Natural gas containing sulfur is referred to in the industry as "sour gas."

NGL Fractionation

        After being separated from natural gas at the processing plant, the mixed NGL stream is typically transported to a centralized facility for fractionation. Crude oil and condensate production also contain varying amounts of NGLs, which are removed during the refining process and, in the case of propane, are either marketed directly out of the refinery, or, in the case of butanes, blended by refiners or delivered to NGL fractionation facilities for further processing. In 2000, NGLs produced from domestic gas processing operations accounted for approximately 68% of the NGLs produced in the United States, compared with 25% from crude oil refining and 7% from imports.

        Fractionation is the process by which NGLs are further separated into individual, more valuable components. Fractionation systems typically exist either as an integral part of a gas processing plant, or as a "central fractionator," often located many miles from the primary production and processing facility. A central fractionator may receive mixed streams of NGLs from many processing plants.

        NGLs are fractionated by varying the temperature and pressure of mixed NGL streams and passing them through a series of distillation towers that take advantage of the differing boiling points of the various NGL products. Through this process the NGL stream is separated into its components: ethane, propane, normal butane, isobutane and natural gasoline.

        Described below are the five basic NGL products and their typical uses:

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Ethane—Ethane is used primarily as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Ethane is not produced at our Siloam fractionator as there is little petrochemical demand for ethane in Appalachia and, therefore, it remains in the natural gas stream.



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Propane—Propane is used as a gas for heating fuel, engine fuel, industrial fuel and for agricultural burning and drying and as a petrochemical feedstock for production of ethylene and

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propylene. Propane is principally used as a fuel in our operating area and represents approximately 64% of our NGL throughput at our Siloam fractionator.

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Normal butane—Normal butane is principally used for gasoline blending, as a fuel gas, either alone or in a mixture with propane, and as a feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber. Normal butane represents approximately 18% of our NGL throughput at our Siloam fractionator.



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Isobutane—Isobutane is principally used by refiners to enhance the octane content of motor gasoline and in the production of MTBE, an additive in cleaner burning motor gasoline. Isobutane represents approximately 6% of our NGL throughput at our Siloam fractionator.



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Natural gasoline—Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock. Natural gasoline represents approximately 12% of our NGL throughput at our Siloam fractionator.

Our Gathering and Processing Facilities

        We are the largest gas processor in the northeastern United States and we have the right to process the gas or fractionate the NGLs delivered by substantially all of the producers who deliver gas into two of the three largest gathering systems in Appalachia. We own and operate four natural gas processing plants in Appalachia with aggregate design throughput capacity of approximately 320,000 Mcf/d of natural gas. We also own a 32,000 Mcf/d processing plant, Kermit, which is operated by a third party. Our Appalachian plants, excluding our Kermit facility, processed an average of 266,000 Mcf/d of natural gas for the year ended December 31, 2002.

        In addition, we own a pipeline and a natural gas processing plant in Michigan. We gathered an average of 13,800 Mcf/d of natural gas and extracted approximately 11 million gallons of NGLs in Michigan for the year ended December 31, 2002.

Appalachia

        The table below describes our processing assets in the Appalachian region:

(1)

A portion of the Boldman volumes and all of the Kermit volumes are included in Kenova's throughput, as these volumes require further processing at our Kenova facility.

(2)

Represents MarkWest Hydrocarbon until May 23, 2002, and MarkWest Energy Partners from May 24, 2002—the date our IPO closed.

(3)

Our processing plants were constructed to accommodate gas volumes somewhat in excess of their design throughput capacity.

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        We generate most of our processing revenues in Appalachia by charging fees for processing gas. We completed a multi-year expansion of our Appalachian infrastructure in mid-2001, increasing our total natural gas designed processing capacity by 127,000 Mcf/d. A new gas stream began flowing in January 2003 when a new gatherer completed its connection into the existing transmission system upstream of our Kenova NGL extraction plant. We have sufficient capacity to process the expected additional 10,000 Mcf/d of natural gas and the resulting 20,000 gallons per day of NGL products from this new gas stream.

Michigan

        The table below describes our Michigan assets:

(1)

MarkWest Hydrocarbon has retained a 70% net profit interest in all gathering and processing fees generated by quarterly throughput volumes in excess of 10,000 Mcf/d.

(2)

Represents MarkWest Hydrocarbon until May 23, 2002, and MarkWest Energy Partners from May 24, 2002—the date our IPO closed.

        Our Michigan assets include a 90-mile gas gathering pipeline and a 35,000 Mcf/d gas processing plant. Our pipeline is comprised of 4-inch to 10-inch pipe, all of which was constructed between 1994 and 1998. Our Michigan gathering pipeline gathers and transports sour gas produced by third parties in Oceana, Mason and Manistee Counties for sulfur removal at a treatment plant that is owned and operated by Shell Offshore, Inc. Our Fisk processing plant is located adjacent to Shell's treatment plant. Our gathering pipeline serves approximately 30 wells and 13 producers in this three county area. The Fisk plant processes all of the natural gas gathered by our gathering pipeline and produces propane and a butane-natural gasoline mix.

        We generate revenues from our Michigan operations primarily by charging a fee for the gathering and processing services we provide. Our contracts in Michigan also provide that we retain a portion of the proceeds from the sale of NGLs that are produced at our Michigan facility. Our propane and butane-natural gasoline production is usually sold at the plant. Our throughput is expected to remain between 10,000 and 15,000 Mcf/d in 2003. MarkWest Hydrocarbon has retained a 70% net profit interest in all gathering and processing fees generated by Michigan throughput volumes in excess of 10,000 Mcf/d.

Natural Gas Liquids Transportation, Fractionation and Storage

Our NGL Pipelines

        We earn fees for transporting NGLs through our pipelines to our Siloam fractionation plant. All of the NGLs we recover at our Kenova, Boldman and Maytown plants are transported to Siloam via pipeline (NGLs from Boldman are first transported to our Maytown facility via tanker trucks). NGLs from our Cobb and Kermit plants are transported to Siloam via tanker trucks.

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        Our Appalachia liquids pipeline includes the following segments:

(1)

Includes 40 miles of currently unused pipeline extending from Ranger to Institute.

(2)

NGLs transported through the Ranger to Kenova pipeline are included in the Kenova to Siloam volumes.

        Our 40-mile Ranger to Kenova NGL pipeline and the Maytown to Ranger segment of our leased Maytown to Institute pipeline, together with our existing Kenova to Siloam pipeline, form 136 miles of NGL pipeline running through the southern portion of the Appalachia basin. We acquired our Ranger to Kenova pipeline and leased the 100-mile Maytown to Institute pipeline in 2000 as part of our Appalachian expansion. We acquired our Kenova to Siloam pipeline in 1988. We lease the Maytown to Institute pipeline from Equitable Production Company (Equitable). Our lease expires in 2015. Prior to leasing the Maytown to Institute pipeline, Boldman NGLs were required to be transported by truck to Siloam, at significantly greater expense than trucking to an injection point. We generate transportation revenues by charging fees for transporting NGLs to our Siloam fractionator on our pipeline.

Our Fractionation Facility

        Our Siloam fractionation plant receives substantially all of its extracted NGLs via pipeline or tanker truck from our five Appalachia processing plants, with the balance received from tanker truck and rail car deliveries from other third-party NGL sources. The extracted NGLs are then separated into NGL products, including propane, isobutane, normal butane and natural gasoline. The typical composition of the NGL throughput in our Appalachian operations has been approximately 64% propane, 18% normal butane, 6% isobutane, and 12% natural gasoline. We do not currently produce and sell any ethane. The following table provides additional detail regarding our Siloam fractionation plant:

        We generate revenues by charging fees for fractionating NGLs that we receive from our processing plants and third parties.

Our Storage Facilities

        Our Siloam facility has both above ground pressurized storage facilities, with capacity of three million gallons, and underground storage facilities, with capacity of 11 million gallons. Product can be

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received by truck, pipeline or rail car and can be transported from the facility by truck, rail car or barge. There are eight automated 24-hour-a-day truck loading and unloading slots, a modern rail loading/unloading rack with 12 unloading slots, and a river barge facility capable of loading barges with a capacity of up to 840,000 gallons. We generate revenues from our underground storage facilities by charging a fee based on annual gallons of storage contracted.

Customers and Contracts

Appalachia

        In Appalachia, our primary sources of revenues are our processing, transportation, fractionation and storage agreements with MarkWest Hydrocarbon, which are described below, and our agreement with Equitable Production Company (Equitable; a subsidiary of Equitable Resources, Inc.) relating to processing services at our Maytown facility. Under the terms of this Gas Processing Agreement, Equitable agrees to deliver to us all gas now or subsequently produced from specified wells, plus gas attributable to the interests of third parties that is currently being delivered into Equitable's gathering system (to the extent Equitable has the right to process such third party gas). Equitable also grants us the exclusive right to process all of this natural gas for liquid extraction and conveys to us the title to the NGLs and NGL products we extract from the gas.

        We are responsible for processing all gas delivered to our Maytown plant by Equitable and must deliver residue gas to Equitable at a specified gas delivery point. The parties have agreed that Equitable will act as our operator for the Maytown facility.

        As compensation for our services, we earn both a fee for our transportation and fractionation services as well as receive a percentage of the proceeds from the sale of NGLs produced on Equitable's behalf. A portion of the transportation and fractionation fee will be subject to annual adjustment in proportion to the annual average percentage change in the Producer Price Index for Oil and Gas Field Services. MarkWest Hydrocarbon, in a separate agreement, has agreed to buy the NGLs from us and pay us a purchase price equal to the proceeds it receives from the resale of such NGLs to third parties. The Gas Processing Agreement with Equitable also contains cross-indemnification provisions. The initial term of our the Gas Processing Agreement with Equitable runs through February 2015.

        The operating revenues we earn under the percent-of-proceeds component of the Gas Processing Agreement will fluctuate with the sales price for the NGLs produced. The natural gas covered by the Gas Processing Agreement accounts for approximately 20% of the natural gas that we process in Appalachia.

Michigan

        In western Michigan, we process natural gas under a number of third-party agreements containing both fee and percent-of-proceeds components. Under these agreements, production from all of the acreage adjacent to our pipeline and processing facility is dedicated to our gathering and processing facilities. Under the fee component of these agreements, which represent approximately two-thirds of our gross margin in Michigan, producers pay us a fee to transport and treat their gas. Under the percent-of-proceeds component, we retain a portion of the proceeds from the sale of the NGLs as compensation for the processing services provided.

        We receive 100% of all fee and percent-of-proceeds consideration for the first 10,000 Mcf/d that we gather and process in Michigan. MarkWest Hydrocarbon retains a 70% net profits interest in the gathering and processing income we earn on quarterly pipeline throughput in excess of 10,000 Mcf/d. Throughput averaged 13,800 Mcf/d for the year ended December 31, 2002. Throughput is expected to remain between 10,000 to 15,000 Mcf/d in 2003.

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Our Contracts with MarkWest Hydrocarbon

        At the closing of our IPO, we entered into a number of contracts with MarkWest Hydrocarbon pursuant to which we provide processing, transportation, fractionation and storage services on its behalf, including:

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A Gas Processing Agreement pursuant to which MarkWest Hydrocarbon agreed to deliver all gas gathered by Columbia Gas and delivered to MarkWest Hydrocarbon upstream of our facilities for processing at our Kenova, Boldman and Cobb plants. Under the terms of this agreement, we agreed to accept and process all gas that MarkWest Hydrocarbon delivers to us up to the then-existing capacity of the applicable processing plant. In exchange for these services, we receive a monthly processing fee based on the natural gas volumes delivered to us, a portion of which will be adjusted on each anniversary of the Gas Processing Agreement's effective date to reflect changes in the Producers Price Index for Oil and Gas Field Services. MarkWest Hydrocarbon is responsible for providing all natural gas used as fuel in these processing facilities. This agreement's initial term runs through 2012, with automatic annual renewals thereafter. All NGLs extracted pursuant to this Gas Processing Agreement are delivered to MarkWest Hydrocarbon for transportation to our Siloam fractionator, while all residue gas is redelivered, for MarkWest Hydrocarbon's account, to Columbia Gas' transmission facilities. Since the closing of our IPO, we have generated 22% of our revenues and 34% of our gross margin from processing fees generated pursuant to the Gas Processing Agreement.



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A Pipeline Liquids Transportation Agreement and a Fractionation, Storage and Loading Agreement pursuant to which:



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MarkWest Hydrocarbon agreed to deliver all NGLs we extract for MarkWest Hydrocarbon's account at our Kenova and Maytown processing facilities to us for transportation through our pipeline to our Siloam fractionator. MarkWest Hydrocarbon may, but is not obligated to, deliver NGLs from our Boldman facility or other sources in the Appalachian region for transportation on our pipeline to our Siloam fractionator. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for transportation. Under the terms of these agreements, we receive a monthly fee based on the number of gallons delivered to us by MarkWest Hydrocarbon for transportation, a portion of which will be adjusted on each anniversary of the effective date of each agreement to reflect changes in the Producers Price Index for Oil and Gas Field Services.



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MarkWest Hydrocarbon agreed to deliver all NGLs extracted at any of our processing facilities to us for fractionation at our Siloam facility, as well as for such loading and storage services as MarkWest Hydrocarbon may direct. MarkWest Hydrocarbon pays us a monthly fee, a portion of which will be adjusted annually to reflect changes in the Producers Price Index for Oil and Gas Field Services, based on the number of gallons delivered to us for fractionation. In addition, these agreements provide that we receive an annual storage fee based on the volume of underground storage available for use by MarkWest Hydrocarbon during such annual period. Finally, to the extent MarkWest Hydrocarbon delivers third-party NGLs by rail car for fractionation, we are entitled to an additional per gallon unloading fee. Our storage and loading fees are subject to similar Producers Price Index adjustments.



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These agreements' initial terms run through 2012, with automatic annual renewals thereafter.



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Since May 24, 2002, the date on which our IPO closed, we have generated approximately 19% of our revenues and 30% of our gross margin pursuant to these agreements.




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A Natural Gas Liquids Purchase Agreement under which MarkWest Hydrocarbon agreed to receive and purchase, and we have agreed to deliver and sell, all of the NGL products we produce pursuant to our Gas Processing Agreement with Equitable. Under the terms of the Natural Gas Liquids Purchase Agreement, MarkWest Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale to third parties of such NGL products. This agreement also applies to any other NGL products we acquire. We retain a percentage of the proceeds attributable to the sale of NGL products we produce pursuant to our Gas Processing Agreement with Equitable, and remit the balance from such NGL product sales to Equitable. The initial term of the Natural Gas Liquids Purchase Agreement runs through 2012, with automatic annual renewals thereafter. Since our IPO closed, we have generated approximately 35% of our revenues and approximately 7% of our gross margin pursuant to this agreement.

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An Omnibus Agreement pursuant to which:



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MarkWest Hydrocarbon agreed not to compete with us in natural gas processing or in the transportation, fractionation and storage of NGLs, subject to certain exceptions;



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MarkWest Hydrocarbon agreed to indemnify us for a period of three years for losses due to environmental matters arising prior to our IPO, as well as for preexisting litigation; and



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Reimbursements to MarkWest Hydrocarbon for the provision of general and administrative services pursuant to our partnership agreement are not to exceed $4.9 million during the twelve months following completion of our IPO.

Competition

        We face competition in obtaining natural gas supplies for our processing and related services operations, in obtaining unprocessed NGLs for fractionation, and in marketing our products and services. Competition for natural gas supplies is based primarily on location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and to industry marketing centers, and cost efficiency and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of quality customer relationships.

        In competing for new business opportunities, we face strong competition in acquiring natural gas supplies and competing for fees for service. Our competitors include:

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Major integrated oil companies;



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Major interstate and intrastate pipelines;



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Other large raw natural gas gatherers that gather, process and market natural gas and NGLs; and



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A relatively large number of smaller gas gatherers of varying financial resources and experience.

        Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.

Regulatory Matters

        Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.

        Various phases of gas transportation operations in Michigan are subject to the jurisdiction of the Michigan Public Service Commission, including transportation rates and service.

        Our Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, who has entered into agreements with us providing for a fixed transportation charge for the term of the agreements, which expire on December 31, 2015. As we do not operate this pipeline as a common carrier and do not hold the pipeline out for service to the public generally, there are currently no third-party shippers on this pipeline and the pipeline is and will continue to be operated as a proprietary facility. However, if a shipper sought to challenge the jurisdictional status of the pipeline, the Federal Energy Regulatory Commission (FERC) could determine that such transportation is within its jurisdiction under the Interstate Commerce Act. In such a case, we would be required to file a tariff for such transportation and provide a cost justification for the transportation

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charge. Because MarkWest Hydrocarbon has agreed not to challenge the status of the pipeline or the transportation charge during the terms of our agreements with MarkWest Hydrocarbon and, moreover, the likelihood of other entities seeking to utilize the pipeline is limited, the likelihood of such a challenge is remote. We cannot predict, based on currently available information, whether the charges under these agreements would be altered if it became subject to the cost-of-service standards employed by the FERC.

Environmental Matters

General

        Our operation of processing and fractionation plants, pipelines and associated facilities in connection with the gathering and processing of natural gas and the transportation, fractionation and storage of NGLs is subject to stringent and complex federal, state and local laws and regulations relating to release of pollutants into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of constructing, maintaining and upgrading equipment and facilities. Our failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of investigatory or remedial requirements, and, in less common circumstances, issuance of injunctions. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial condition.

        Nevertheless, the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with our operations and we cannot assure you that we will not incur significant costs and liabilities as a result of such upsets, releases, or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. We will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.

Hazardous Substance and Waste

        To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous wastes, and may require investigatory and corrective actions of facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of "hazardous substance" into the environment. These persons include the owner or operator of a site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency, or EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek

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to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although "petroleum" is excluded from CERCLA's definition of a "hazardous substance," in the course of our ordinary operations we will generate wastes that may fall within the definition of a "hazardous substance." We may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA.

        We also generate both hazardous and non-hazardous solid wastes which are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. From time to time, the EPA has considered the adoption of stricter disposal standards for non-hazardous wastes, including crude oil and natural gas wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by us that are currently classified as non-hazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or plant operating expenses.

        We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering and processing and for NGL fractionation, transportation and storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, a possibility exists that hydrocarbons and other solid wastes may have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we had no control as to such entities' handling of hydrocarbons or other wastes and the manner in which such substances may have been disposed of or released. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination. We do not believe that there presently exists significant surface and subsurface contamination of our properties by hydrocarbons or other solid wastes for which we are currently responsible.

Ongoing Remediation and Indemnification from Columbia Gas

        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 these four facilities pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and EPA Regions II, III, IV, and V in September 1994. Columbia Gas is also pursuing these remedial activities at the Boldman facility pursuant to an "Agreed Order" that it entered into with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The focus of the investigatory and remedial activities pursued by Columbia Gas has been the cleanup of polychlorinated biphenyls, also known as PCBs, and other hazardous substances which may be found in these real properties. Columbia Gas has agreed to retain sole liability and responsibility for, and indemnify MarkWest Hydrocarbon against, any environmental liabilities associated with the EPA Administrative Order, the Kentucky Agreed Order or any other environmental condition related to the real property prior to the effective dates of MarkWest Hydrocarbon's agreements pursuant to which MarkWest Hydrocarbon leased the real property or purchased the real property from Columbia Gas. In addition, Columbia Gas has agreed to perform all

13

the required response actions at its cost and expense in a manner that minimizes interference with MarkWest Hydrocarbon's use of the properties. On May 24, 2002, MarkWest Hydrocarbon assigned to 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 Kermit 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 indemnification pursuant to the terms of the Omnibus Agreement. To date, Columbia Gas has been performing all actions required under these agreements, and, accordingly, we do not believe that the remediation of these properties by Columbia Gas pursuant to the EPA Administrative Order or the Kentucky Agreed Order will have a material adverse impact on our financial condition or results of operations.

Air Emissions

        Our operations are subject to the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act were enacted in 1990. Moreover, recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. As a result of these amendments, our processing and fractionating plants, pipelines, and storage facilities that emit volatile organic compounds or nitrogen oxides may become subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources, which applies to some of our facilities. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and may result in the limitation or cessation of construction or operation of certain air emission sources. Although we can give no assurances, we believe implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations.

Clean Water Act

        The Federal Water Pollution Control Act, also known as the Clean Water Act, and similar state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid-related wastes, into state waters or waters of the United States. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed there under, and that continued compliance with such existing permit conditions will not have a material effect on our results of operations.

Safety Regulation

        Our pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns

14

or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the HLPSA will not have a material adverse effect on our results of operations or financial position.

        The Pipeline Safety Improvement Act of 2002, which was signed into law on December 17, 2002, includes numerous provisions that tighten federal inspectors and safety requirements for natural gas and hazardous liquids pipeline facilities. Many of the statute's provisions build on existing statutory requirements and strengthen regulations of the Research and Special Programs Administration and the office of Pipeline Safety, in particular, with respect to operator qualifications programs, natural mapping system and safe excavation practices. Management of the Partnership believes that compliance with the Pipeline Safety Improvement Acts of 2002 will not have a material effect on its operations.

Employee Safety

        The workplaces associated with the processing and storage facilities and the pipelines we operate are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and citizens. We believe that we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

        In general, we expect industry and regulatory safety standards to become stricter over time, thereby resulting in increased compliance expenditures. While these expenditures cannot be accurately estimated at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.

Employees

        To carry out our operations, our general partner or its affiliates employ approximately 56 individuals who operate our facilities as our agents, excluding general and administrative employees. The Paper, Allied Industrial, Chemical, and Energy Workers International Union Local 5-372 represent fourteen employees at our Siloam fractionation facility in South Shore, Kentucky. The collective bargaining agreement with this Union expires on June 28, 2004. The agreement covers only hourly, non-supervisory employees. We consider labor relations to be satisfactory at this time. The Partnership has no employees.

Available Information

        You can find more information about us at our Internet website located at www.markwest.com. Our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our current reports on Form 8-K and any amendments to those reports are available free of charge through our internet website as soon as reasonably practicable after we electronically file such material with the SEC.

Forward-Looking Statements

        Statements included in this annual report on Form 10-K that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as "may,"

15

"believe," "estimate," "expect," "plan," "intend," "project," "anticipate," and similar expressions to identify forward-looking statements.

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

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

•

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



•

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 natural gas exploration and production activities will not occur or be successful;



•

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



•

Competition from other NGL processors, including major energy companies;



•

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



•

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

        These factors are not necessarily all of the important factors that could cause actual results to differ material from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. The Partnership undertakes no obligation to update publicly any forward-looking statement whether as a result of new information or future events. Investors are cautioned not to put undue reliance on forward-looking statements. You should read "Risk Factors" below for further information.

Risk Factors

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating MarkWest Energy Partners:

•

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



•

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



•

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



•

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

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•

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



•

The amount of natural gas we gather and process and the amount of NGLs we transport and fractionate will decline over time unless new wells are connected to the gathering systems serving our facilities, particularly in Michigan.



•

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



•

The highly competitive nature of our industry could cause us to lose customers and future business opportunities, thereby reducing our revenues and limiting our future financial performance.



•

Our profitability depends upon the demand for our services and prices for our products.



•

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



•

Terrorist attacks, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and future war or risk of war may adversely impact our results of operations.



•

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.



•

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



•

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



•

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



•

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



•

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

ITEM 3. LEGAL PROCEEDINGS

        MarkWest Energy Partners, in the ordinary course of business, is a party to various legal actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on our financial condition, liquidity or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        No matter was submitted to a vote of the holders of our common units during the fourth quarter of the fiscal year ended December 31, 2002.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS

        Our common units were listed on the American Stock Exchange (AMEX) national market under the symbol "MWE", beginning on May 24, 2002. Prior to May 24, 2002, our equity securities were not traded on any public trading market. The following table sets forth the range of high and low bid prices of the common units, as reported by AMEX, as well as the amount of cash distributions paid per quarter for 2002 since the close of the IPO on May 24, 2002.

(1)

Reflects the pro rata portion of the $0.50 minimum quarterly distribution per unit, representing the period from the May 24, 2002, the closing date of our initial public offer, through December 31, 2002.

        As of February 24, 2003, there were approximately 24 holders of record of our common units, which includes an estimated 3,035 beneficial owners of our common units.

        The Partnership has also issued 3,000,000 subordinated units for which there is no established public trading market.

        The Partnership distributes 100% of its "Available Cash" within 45 days after the end of each quarter to unitholders of record and to the general partner. "Available Cash" is defined in the Partnership Agreement, and generally consists of all cash and cash equivalents of the Partnership on hand at the end of each quarter less reserves established by the general partner for future requirements plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. The general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business; (ii) comply with applicable law, any of our debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters. Working capital borrowings are generally borrowings that are made under our working capital facility and in all cases are used solely for working capital purposes.

        During the subordination period (as defined in the Partnership Agreement and discussed further below), our quarterly distributions of available cash will be made in the following manner:

•

First, 98% to the common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters;



•

Second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters; and



•

Third, 98% to all units, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.55 per quarter.

        There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility. The information concerning restrictions on distributions required by this Item 5 is incorporated herein by reference to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation—Credit Facility". The subordination period generally will not end earlier than June 30, 2007.

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ITEM 6. SELECTED FINANCIAL DATA

        On May 24, 2002, the Partnership completed its initial public offering whereby the Partnership became the successor to the business of the MarkWest Hydrocarbon Midstream Business (Midstream Business). The selected financial information for the Partnership was derived from the audited consolidated and combined financial statements as of and for the year ended December 31, 2002. The selected historical financial statements of the Midstream Business as of and for the years ended December 31, 2001, 2000, and 1999 are derived from the audited financial statements of the Midstream Business. The selected historical financial statements of the Midstream Business as of and for the year ended December 31, 1998, are derived from the unaudited financial statements of the Midstream Business and, in our opinion, include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information. The selected financial data should be read in conjunction with the combined and consolidated financial statements, including the notes thereto, and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

NM

Not meaningful

(1)

At the closing of its IPO, the Partnership entered into contracts with MarkWest Hydrocarbon. These contracts were substantially different from those contracts in effect under the Midstream Business. The contractual differences materially affected the comparability of the information reflected in Revenues and Purchased product costs.

(2)

Represents throughput at our Kenova, Cobb, Boldman, and Maytown processing plants.

(3)

Prior to May 24, 2002, this represents NGL product production through our Siloam fractionator.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations

Overview

        We are a Delaware limited partnership formed to own and operate a growing midstream business. We are engaged in the gathering and processing of natural gas and the transportation, fractionation, and storage of NGL products. We are the largest processor of natural gas in the northeastern United States, processing gas from the Appalachian basin, one of the country's oldest natural gas producing regions, and from Michigan.

        On March 24, 2003, we entered into an agreement to merge with Pinnacle Natural Gas Company and certain affiliates for approximately $38 million. The acquired assets, primarily located in Texas, are comprised of (a) three lateral natural gas pipelines transporting up to 1.1 Bcf/d of natural gas under firm contracts to power plants and (b) eighteen gathering systems gathering more than 44,000 Mcf/d. The acquisition complements and expands our core fee-based businesses, while providing geographic and customer diversification. The acquisition will be financed primarily through borrowings under our credit facility, which was recently expanded by $15 million.

        The results of operations discussed below are those of MarkWest Energy Partners, L.P. on and after May 24, 2002, the closing date of our IPO and of our predecessor, the MarkWest Hydrocarbon Midstream Business (the Midstream Business), prior to May 24, 2002. Audited financial statements for the Partnership and the Midstream Business appear elsewhere in this Form 10-K. The financial statements of the Midstream Business include charges from MarkWest Hydrocarbon for direct costs and allocations of indirect corporate overhead and the results of contracts in force at that time. We believe that the allocation methods are reasonable, and that the allocations are representative of the costs that would have been incurred on a stand-alone basis. Beginning on May 24, 2002, the consolidated and combined financial statements reflect the financial statements of the Partnership and its subsidiaries, including the results of contracts entered into on May 24, 2002.

        The Midstream Business's financial statements differ substantially from our financial statements principally because of the differences in the way in which we generate revenues and the way in which the MarkWest Hydrocarbon Midstream Business generated revenues. Historically, the Midstream Business generated its revenues pursuant to two types of contracts:

•

"Keep-whole" contracts under which the Midstream Business would take title to and sell the NGLs it produced in its processing operations and would reimburse or "keep whole" the producers for the Btu content of the NGLs removed through the redelivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas; and



•

"Percent-of-proceeds" contracts under which the Midstream Business would take title to the NGLs it produced in its processing operations, sell the NGLs to third parties, and pay the producer a specified percentage of the proceeds received from the sales.

        Currently, none of our revenues are generated pursuant to keep-whole contracts. We generate the majority of our revenues pursuant to contracts that we entered into with MarkWest Hydrocarbon at the closing of our IPO that provide for us to be paid a fee per unit for services that we provide. However, we continue to generate a portion of our revenues pursuant to percent-of-proceeds contracts under which we retain a percentage of the NGLs that we produce as compensation for processing the raw gas for producers. The largest of the differences between the financial statements of the Midstream

20

Business and our financial statements is in revenues and purchased gas cost. Generally, revenues and purchased product costs in the Midstream Business's financial statements are higher because:

•

The Midstream Business's revenues included the aggregate sales price for all the NGL products produced in its operations; and



•

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

        In contrast, our revenues and purchased product costs, for the most part, do not include these items. Instead,

•

Our revenues include just the fees we receive for the provision of gathering, processing, transportation, fractionation and storage services and the aggregate proceeds from NGL sales we receive under our percent-of-proceeds contracts; and



•

Our purchased product costs primarily consists of the percentage of proceeds from the sale of NGL products remitted to producers under our percent-of-proceeds contracts.

        Accordingly, whereas the Midstream Business's results of operations depended on the volumes of NGL products sold and the difference between the sale price of NGL products and the cost of natural gas, our results of operations depend primarily on the volume of natural gas processed, NGLs fractionated and, to the extent of our percent-of-proceeds contracts, the market price of NGL products. Because of these significant differences, the results of operations for the Midstream Business discussed below may be of limited use in evaluating the business to be conducted by us. The nature of the Midstream Business's and our revenues and costs are presented in more extensive detail below and may help you better understand the historical results discussed herein, as well as our operating results going forward.

MarkWest Hydrocarbon Midstream Business

        The Midstream Business historically generated the majority of its revenues through the sale of NGL products obtained in exchange for providing processing and fractionation services to natural gas producers. NGL product prices, and the volume of natural gas processed and NGLs fractionated and sold, were the primary determinants of revenues. In Appalachia, the Midstream Business processed natural gas under keep-whole contracts and a contract containing both fee and percent-of-proceeds components. In Michigan, the Midstream Business processed natural gas under contracts containing both fee and percent-of-proceeds components. Under keep-whole and percent-of-proceeds contracts, the Midstream Business recorded as revenues the gross proceeds retained from the sale of NGL products produced. Gathering and processing contracts containing a fee component required producers to pay the Midstream Business a fee to gather and process their gas.

        The Midstream Business's purchased product costs were comprised of a keep-whole contract component and a percent-of-proceeds contract component. Under keep-whole contracts, the Midstream Business's principal cost was the reimbursement to the natural gas producers for the energy extracted from their natural gas stream in the form of NGLs. The Midstream Business kept the producers whole on an energy basis by replacing the extracted Btu content of the NGLs with additional volumes of dry natural gas. Under percent-of-proceeds contracts, the Midstream Business's principal cost was the percentage of the proceeds from the sale of the NGL products that was remitted to the producers.

        The Midstream Business's plant operating expenses principally consisted of costs needed to operate its facilities, including personnel costs, fuel needed to operate the plants, plant utility costs and maintenance expenses. The Midstream Business's fuel costs were partially offset by contractual

21

reimbursements from producers. Some operating costs, such as fuel costs, fluctuated depending on the amount of natural gas processed or NGL products fractionated and the price of natural gas.

        The Midstream Business's general and administrative expenses were costs allocated by MarkWest Hydrocarbon. Historically, these costs have included legal, accounting, treasury, engineering, information technology, insurance and other corporate services.

MarkWest Energy Partners, L.P.

        We generate the majority of our revenues from gas processing and NGL transportation, fractionation and storage. In Appalachia, our primary sources of revenues are our operating agreements with MarkWest Hydrocarbon.

        These operating agreements include:

•

A Gas Processing Agreement under which MarkWest Hydrocarbon delivers all gas gathered by Columbia Gas and delivered to MarkWest Hydrocarbon upstream of our facilities for processing at our Kenova, Boldman and Cobb plants. We accept and process all such gas up to the then-existing capacity of the applicable plant. As payment for these services, we receive a monthly processing fee based on the natural gas volumes delivered to us.



•

A Pipeline Liquids Transportation Agreement under which MarkWest Hydrocarbon delivers all of its NGLs acquired from our Kenova facility, and any of its NGLs it desires to deliver from our Boldman facility or from other sources in the Appalachian region for transportation through our pipeline facilities to our Siloam fractionation facility. As payment for these services, MarkWest Hydrocarbon pays us a monthly transportation fee based on the number of gallons transported.



•

A Fractionation, Storage and Loading Agreement under which MarkWest Hydrocarbon delivers all of the mixed NGLs produced at our Kenova, Boldman or Cobb processing plants for fractionation at our Siloam fractionation facility. We unload the NGLs delivered to us, fractionate all the NGLs, lease tracking rights on our Siloam railroad siding to MarkWest Hydrocarbon, load the finished NGL products for shipment and as directed by MarkWest Hydrocarbon, store the finished NGL products in underground storage caverns. As payment for these services, MarkWest Hydrocarbon pays us a monthly fractionation fee based on the number of gallons we fractionate, an annual storage fee and a monthly fee based on the number of gallons of NGLs we unload at our Siloam facility.



•

A Natural Gas Liquids Purchase Agreement under which MarkWest Hydrocarbon receives and purchases, and we deliver and sell, all of the NGL products we produce pursuant to our 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 to third parties of such NGL products. This contract applies to any other NGL products we acquire. We retain a percentage of the proceeds attributable to the sale of NGL products we produce pursuant to our agreement with a third party, and remit the balance from such NGL product sale proceeds to a third party.

        A portion of each of the above-mentioned fees is adjusted annually to reflect changes in the Producers Price Index for Oil and Gas Field Services.

        In Michigan, we assumed the Midstream Business's existing contracts and gather and process natural gas directly for the third parties who are parties to those contracts. We receive 100% of all fee and percent-of-proceeds consideration for the first 10,000 Mcf/d that we gather in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and processing income we earn on quarterly Michigan pipeline throughput in excess of 10,000 Mcf/d.

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        Our principal purchased product costs are the percentage of proceeds from the sale of NGL products that we remit to a third party in Appalachia and the third-party producers in Michigan.

        Our plant operating expenses, similar to the Midstream Business, principally consist of those expenses needed to operate our facilities, including applicable personnel costs, fuel, plant utility costs and maintenance expenses. One difference between our plant operating expenses and those of the MarkWest Hydrocarbon Midstream Business is fuel costs. MarkWest Hydrocarbon retains the producer fuel reimbursement obligation in our current arrangements.

        Our general and administrative expenses are dictated by the terms of the Omnibus Agreement between MarkWest Hydrocarbon and us. We reimburse MarkWest Hydrocarbon monthly for the general and administrative support it provided us in the prior month. In the first year of the agreement, this reimbursement will not exceed $4.9 million. This limitation excludes the cost of any third party legal, accounting or advisory services received, or the direct expenses of MarkWest Hydrocarbon and its affiliates incurred, in connection with business development opportunities evaluated on our behalf.

Operating Data

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

        Revenues.    Our Combined (defined as the period from January 1, 2002 through May 23, 2002 plus the period from May 24, 2002 through December 31, 2002) revenues were $70.2 million for the year ended December 31, 2002, compared to $93.7 million for the year ended December 31, 2001, a decrease of $23.4 million, or 25%. Revenues were lower in 2002 than in 2001 primarily due to the terms of the new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of the IPO. You should read the Overview section appearing under "Results of Operations" earlier in this Form 10-K for a detailed discussion of the financial statement line items differences between the Partnership and the Midstream Business. On the percent-of-proceed contracts retained by the

23

Partnership, average NGL product sales prices were lower in the 2002 period than in the comparable 2001 period.

        Purchased Product Costs.    Our Combined purchased product costs were $38.9 million for the year ended December 31, 2002, compared to $65.5 million for the year ended December 31, 2001, a decrease of $26.6 million, or 41%. Purchased product costs were lower in 2002 primarily due to the terms of new contracts entered into by MarkWest Hydrocarbon and us concurrent with the closing of the IPO. You should read the Overview section appearing under "Results of Operations" earlier in this Form 10-K for a detailed discussion of the financial statement line items differences between the Partnership and the Midstream Business.

        Plant Operating and Other Expenses.    Our Combined plant operating and other expenses were $15.1 million for the year ended December 31, 2002, compared to $13.1 million for the year ended December 31, 2001, an increase of $2.0 million, or 15%. Plant operating and other expenses increased due to increased throughput in our Michigan facilities and the expansion of our Kenova processing plant.

        Selling, General and Administrative Expenses.    Our Combined selling, general and administrative expenses (SG&A) were $5.3 million for the year ended December 31, 2002, compared to $5.0 million for the year ended December 31, 2001, an increase of $0.2 million, or 5%. SG&A expenses increased principally due to the Partnership's incremental costs associated with being a publicly traded company, as well as increased insurance costs.

        Depreciation.    Our Combined depreciation expense was $5.0 million for the year ended December 31, 2002, compared to $4.5 million for the year ended December 31, 2001, an increase of $0.5 million, or 11%. The increase is principally attributable to additional fixed assets placed into service during the second half of 2001.

        Interest Expense.    Our Combined interest expense was $1.4 million for the year ended December 31, 2002, compared to $1.3 million for the year ended December 31, 2001.

        Income Taxes.    The Partnership has not been subject to income taxes since its inception on May 24, 2002.

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

        Revenues.    Revenues were $93.7 million for the year ended December 31, 2001 compared to $109.8 million for the year ended December 31, 2000, a decrease of $16.1 million, or 15%. Revenues were lower in 2001 than in 2000 primarily due to a decrease in the average Appalachian NGL sales price, which accounted for $14.9 million of the decrease. The average Appalachian NGL sales price was $0.53 per gallon for the year ended December 31, 2001, compared to $0.63 per gallon for the year ended December 31, 2000, a decrease of $0.10 per gallon, or 16%. Appalachian NGL sales volumes remained essentially flat. Lower Michigan NGL sales volumes in 2001, a result of decreased pipeline throughput, accounted for the remainder of the decrease in revenues and were partially offset by a modest increase in average Michigan NGL sales price during 2001.

        Purchased Products Costs.    Purchased products costs were $65.5 million for the year ended December 31, 2001, compared to $71.3 million for the year ended December 31, 2000, a decrease of $5.9 million, or 8%. Purchased products costs were lower in 2001 primarily due to:

•

A decrease in the average Appalachian replacement natural gas cost, which accounted for an approximately $4.1 million decrease in purchased gas costs. The average cost of Appalachian replacement natural gas was equivalent to $0.40 per NGL gallon for the year ended

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December 31, 2001, compared to $0.44 per gallon for the year ended December 31, 2000, a decrease of $0.04 per gallon, or 9%;

•

A decrease in our average Appalachian NGL prices, which accounted for $2.4 million of the decrease. Reduced average Appalachian NGL prices reduced the percent of proceeds remitted to an Appalachian producer; and



•

Increased transportation costs, a result of an increase in the number of our sales outlets, partially offset the decrease in the average Appalachian replacement natural gas cost.

        Plant Operating and Other Expenses.    Plant operating and other expenses were $13.1 million for the year ended December 31, 2001, compared to $13.2 million for the year ended December 31, 2000, a decrease of $0.1 million, or 1%.

        Selling, General and Administrative Expenses.    Selling, general and administrative expenses were $5.0 million for the year ended December 31, 2001, compared to $4.7 million for the year ended December 31, 2000, an increase of $0.3 million, or 7%.

        Depreciation and Amortization.    Depreciation and amortization were $4.5 million for the year ended December 31, 2001, compared to $4.3 million for the year ended December 31, 2000, an increase of $0.1 million, or 3%.

        Interest Expense.    Interest expense was $1.3 million for the year ended December 31, 2001, compared to $1.7 million for the year ended December 31, 2000, a decrease of $0.4 million, or 23%. The decrease was principally caused by a reduction in interest rates throughout 2001.

        Provision for Income Taxes.    Provision for income taxes for the year ended December 31, 2001, was $1.6 million, compared to $5.7 million for the year ended December 31, 2000, a decrease of $4.1 million, or 72%. Provision for income taxes decreased principally due to lower income before income taxes.

        Net Income.    Net income for the year ended December 31, 2001, was $2.6 million, compared to $8.8 million for the year ended December 31, 2000, a decrease of $6.2 million, or 71%. Net income decreased principally as a result of decreased average Appalachian NGL sales prices.

Seasonality

        A portion of the Midstream Business's revenues and, as a result, its gross margins, were dependent upon the sales prices of NGL products, particularly propane, which fluctuate with winter weather conditions, and other supply and demand determinants. The strongest demand for propane, which increases sales volumes, and the highest propane sales margins generally occur during the winter heating season. As a result, the Midstream Business recognized a substantial portion of its annual income during the first and fourth quarters of the year.

        With respect to our percent-of-proceeds contracts, which accounted for approximately 15% of our gross margin (revenue less purchased product costs) as of December 31,2002, we are also dependent upon the sales price of NGL products, particularly propane, which fluctuates with the winter weather conditions, and other supply and demand determinants.

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Liquidity and Capital Resources

        Cash generated from operations and borrowings under our credit facility are our primary sources of liquidity. At December 31, 2002, the Partnership had working capital of $1.8 million. As of December 31, 2002, the Partnership had borrowed $21.4 million of the $38.6 million available under its credit facility. In March 2003, the credit facility was amended to increase the aggregate committed sum to $75 million. We believe that cash generated from operations and funds available under our credit facility will be sufficient to meet both our short-term and long-term working capital requirements and anticipated capital expenditures. In addition, we have the ability to issue up to 1,207,500 additional common units without unitholder approval, to raise equity capital.

        Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, and more broadly, on the availability of debt and equity financing which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

        Our primary customer is MarkWest Hydrocarbon, which accounted for 79% of our revenues since our IPO closed. Consequently, matters affecting the business and financial condition of MarkWest Hydrocarbon—including its operations, management, customers, vendors, and the like—have the potential to impact, both positively and negatively, our liquidity.

Capital Requirements

        Sustaining capital expenditures, which 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, are estimated to be $0.5 million for the year ended December 31, 2003, exclusive of any acquisitions.

Cash Flow

        Our Combined net cash provided by operating activities was $33.5 million for the year ended December 31, 2002. Net cash used in operating activities was $0.5 million for the year ended December 31, 2001. Net cash provided by operating activities was higher in 2002 than in 2001 primarily due to new, ongoing contracts as well as the initial conveyance contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of the IPO. You should read the Overview section appearing under "Results of Operations" earlier in Item 7 for a detailed discussion of the financial statement line items differences between the Partnership and the Midstream Business.

        Our Combined net cash used in investing activities was $2.1 million for the year ended December 31, 2002, compared to $9.0 million for the year ended December 31, 2001, for the Midstream Business. The decrease was principally attributable to the level of construction in Appalachia during 2001, which has since been completed.

        Our Combined net cash used in financing activities was $28.7 million for the year ended December 31, 2002, compared to net cash provided by financing activities of $9.5 million for the year ended December 31, 2001, for the Midstream Business. The financing activities for the year ended December 31, 2002, reflect the Partnership's IPO and related transactions. Financing activities through May 23, 2002, primarily represent repayments to MarkWest Hydrocarbon following the Midstream Business's seasonal conversion of working capital to cash.

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Total Contractual Cash Obligations

        A summary of our total contractual cash obligations as of December 31, 2002, is as follows:

Credit Facility

        You should read Note 4 of the accompanying Notes to Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K for a description of our credit facility.

Related Parties

        We entered into various agreements with MarkWest Hydrocarbon at the closing of our IPO. Specifically, we entered into a:

•

Gas Processing Agreement



•

Pipeline Liquids Transportation Agreement



•

Fractionation, Storage and Loading Agreement



•

Natural Gas Liquids Purchase Agreement



•

Omnibus Agreement

        These agreements were not the result of arm's-length negotiations. You should read Items 1. and 2., "Business and Properties—Our Contracts with MarkWest Hydrocarbon" for further information regarding these agreements.

Critical Accounting Policies

        The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policy is discussed below. For further details on our accounting policies, you should read Note 2 of the accompanying Notes to Consolidated and Financial Statements included in Item 8 of this Form 10-K. You should also read the "Recent Accounting Pronouncements" below.

Impairment of Long-Lived Assets

        In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted

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future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value determine the amount of the impairment recognized. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

        When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the volume of reserves behind the asset and future NGL product and natural gas prices. The amount of reserves and drilling activity are dependent in part on natural gas prices. Projections of reserves and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

•

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



•

The availability and prices of NGL products and competing commodities;



•

The availability and prices of raw natural gas supply;



•

Our ability to negotiate favorable marketing agreements;



•

The risks that third party or MarkWest Hydrocarbon's (in the case of Michigan) natural gas exploration and production activities will not occur or be successful;



•

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



•

Competition from other NGL processors, including major energy companies.

        Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

Recent Accounting Pronouncements

        In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets, which is effective for fiscal years beginning after December 15, 2001, and applies to all goodwill and other intangibles recognized in the financial statements at that date. Under the provisions of this statement, goodwill will not be amortized, but will be tested for impairment on an annual basis. The adoption of SFAS No. 142 did not have a material impact on the Partnership's financial position or results of operations.

        In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. With respect to our midstream services, we have certain surface facilities with ground leases requiring us to dismantle and remove these facilities upon the termination of the applicable lease. We anticipate

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recording a liability, if one can be reasonably estimated, for such obligations in the first quarter of 2003.

        In January 2002, the FASB Emerging Issues Task Force released Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The Task Force reached a consensus to rescind EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, the impact of which is preclude mark-to-market accounting for all energy trading contracts not within the scope of FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. The Task Force also reached a consensus that gains and losses on derivative instruments within the scope of Statement 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The consensus regarding the rescission of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002. We do not have any trading activities and did not account for any contracts as trading contracts in accordance with EITF Issue No. 98-10. Therefore, the EITF consensus to rescind EITF Issue No. 98-10 will not have an impact on our financial position or results of operations.

        In April 2002, the FASB issued SFAS No. 145, Rescission of SFAS Nos. 4, 44 and 64; Amendment of SFAS Statement No. 13; and Technical Corrections, which is generally effective for transactions occurring after May 15, 2002. Through the rescission of SFAS Nos. 4 and 64, SFAS No. 145 eliminates the requirement that gains and losses from extinguishments of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect. SFAS No. 145 made several other technical corrections to existing pronouncements that may change accounting practice. SFAS No. 145 did not impact on our results of operations or financial position.

        In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). We do not believe that the adoption of SFAS No. 146 will have a material impact on our results of operations or financial position.

        In November 2002, FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45), was issued. The accounting recognition provisions of FIN 45 are effective January 1, 2003 on a prospective basis. They require that a guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Under prior accounting principles, a guarantee would not have been recognized as a liability until a loss was probable and reasonably estimable. As FIN 45 only applies to prospective transactions, we are unable to determine the impact, if any, that adoption of the accounting recognition provisions of FIN 45 would have on our future financial position or results of operations.

        In January of 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (FIN 46), which requires the consolidation of certain variable interest entities, as defined. FIN 46 is effective immediately for variable interest entities created after January 31, 2003, and on July 1, 2003 for investments in variable interest entities acquired before February 1, 2003; however, disclosures are required currently if a company expects to consolidate any variable interest entities. We do not have investments in any variable interest entities, and therefore, the adoption of FIN 46 is not expected to have an impact on our results of operations, financial position or cash flows.

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ITEM 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

        As of December 31, 2002, approximately 15% of our business (as measured by gross margin, which is defined as revenues less purchased product cost) was directly subject to NGL product price risk. Our Maytown gas processing plant in Appalachia and our Michigan operations have percent-of-proceeds contracts. Under percent-of-proceeds contracts, we, as the processor, retain a portion of the sales price of the NGL products produced as compensation for our services.

        Our primary risk management objective is to manage this NGL product price risk, thereby reducing volatility in our cash flows. Our hedging approach uses a statistical method that analyzes momentum and average pricing over time, and various fundamental data such as industry inventories, industry production, demand and weather. A committee, which includes members of senior management of our general partner, oversees all of our hedging activity.

        We may utilize a combination of fixed-price forward contracts, fixed-for-float price swaps and options on over-the-counter (OTC) market. New York Mercantile Exchange (NYMEX) traded futures are authorized for use. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.

        We enter OTC swaps with counterparties that are primarily financial institutions. We use standardized swap agreements that allow for offset of positive and negative exposures. Net credit exposure is marked to market daily. We are subject to margin deposit requirements under OTC agreements (with non-bank counterparties) and NYMEX positions.

        The use of financial 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 NGLs or crude oil or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.

        We are also subject to basis risk. Basis risk is the risk that an adverse change in the hedging market will not be completely offset by an equal and opposite change in the price of the physical commodity being hedged.    We have two different types of NGL product basis risk. First, NGL product basis risk stems from the geographic price differentials between our sales locations and hedging contract delivery locations. We cannot hedge our geographic basis risk because there are no readily available products or markets. Second, NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL hedge products and markets are limited. Crude oil is typically highly correlated with certain NGL products. We are generally unable to hedge our basis risk for NGL products.

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        We hedge our NGL product sales by selling forward propane or crude oil. As of December 31, 2002, we have hedged NGL product sales as follows:

        All projected margins or prices on open positions assume (a) the basis differentials between our sales location and the hedging contract's specified location, and (b) the correlation between crude oil and NGL products, are consistent with historical averages.

Interest Rate Risk

        We are exposed to changes in interest rates, primarily as a result of our long-term debt under our credit facility with floating interest rates. We may make use of interest rate swap agreements expiring May 19, 2005 to adjust the ratio of fixed and floating rates in the debt portfolio. As of December 31, 2002, we are a party to contracts to fix interest rates on $8.0 million of our debt at 3.84% compared to floating LIBOR, plus an applicable margin.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated and Combined Financial Statements

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REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors of MarkWest Energy GP, L.L.C.

        In our opinion, the accompanying consolidated and combined balance sheets and the related consolidated and combined statements of operations, of cash flows and of changes in capital present fairly, in all material respects, the financial position of MarkWest Energy Partners, L.P., a Delaware partnership (the Partnership), and its subsidiaries at December 31, 2002 and the results of its operations and their cash flows for the period ended December 31, 2002 and the financial position of the MarkWest Hydrocarbon Midstream Business at December 31, 2001, and the results of its operations and its cash flows for the period from January 1, 2002 through May 23, 2002 and for both of the two years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's and the MarkWest Hydrocarbon Midstream Business's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
February 12, 2003, except for Note 14,
as to which the date is March 25, 2003

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MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED BALANCE SHEETS

(in thousands)

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

34

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

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

35

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(in thousands)