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MarkWest Hydrocarbon, Inc. Form 10-K Table of Contents
Index to Consolidated Financial Statements

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

FORM 10-K

Commission File Number 1-11566

MARKWEST HYDROCARBON, INC.
(Exact name of registrant as specified in its charter)

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

        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.          

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o    No ý

        The aggregate market value of voting common stock held by non-affiliates of the registrant on June 30, 2003 was approximately $30.4 million.

        The number of shares outstanding of the registrant's common stock as of February 29, 2004, was 9,706,401.

DOCUMENTS INCORPORATED BY REFERENCE

        Information required by Part III, Items 10 through 14, of this Report, is incorporated by reference from the registrant's proxy statement, to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K, pursuant to Regulation 14A with respect to the 2004 annual meeting of stockholders.

MarkWest Hydrocarbon, Inc.
Form 10-K
Table of Contents

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        In this document, unless the context requires otherwise, references to "we," "us," "our," "MarkWest Hydrocarbon" or the "Company" are intended to mean MarkWest Hydrocarbon, Inc., and its consolidated subsidiaries.

Glossary of Terms

        In addition, the following is a list of certain acronyms and terms used throughout the document:

(1)

One barrel of oil or NGLs is the energy equivalent of six Mcf of natural gas.

Forward-Looking Information

        Statements included in this Annual Report on Form 10-K and documents incorporated by reference to this report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as "may," "believe," "estimate," "expect," "plan," "intend," "project," "anticipate," and similar expressions to identify forward-looking statements. We have based these forward-looking statements on our current expectations and projections about future events, activities or developments. Our actual results could differ materially from those discussed in our forward-looking statements. Forward-looking statements include statements relating to, among other things:

•

Our expectations regarding MarkWest Energy Partners, L.P.



•

Our ability to grow MarkWest Energy Partners, L.P.



•

Our ability to amend certain producer contracts.



•

Our expectations regarding natural gas, NGL product and prices.



•

Our efforts to increase fee-based contract volumes.



•

Our ability to manage our commodity price risk.



•

Our ability to maximize the value of our NGL output.



•

The adequacy of our general public liability, property, and business interruption insurance.



•

Our ability to comply with environmental and governmental regulations.

3

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

•

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



•

The availability and prices of NGL and competing commodities.



•

The availability and prices of raw natural gas supply.



•

Our ability to negotiate favorable marketing agreements.



•

The risks that third party 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.



•

Competition from other NGL processors, including major energy companies.



•

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



•

Winter weather conditions.

        Forward-looking statements involve many uncertainties that are beyond our ability to control. In many cases, we cannot predict what factors would cause actual results to differ materially from those indicated by the forward-looking statements.

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PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

        We are an energy company primarily focused on growing MarkWest Energy Partners, L.P. (MarkWest Energy Partners or the Partnership), a publicly-traded limited partnership engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil. We also market natural gas and natural gas liquids (NGLs).

        Our assets consist almost exclusively of partnership interests in MarkWest Energy Partners. As of February 29, 2004, our partnership interests consisted of the following:

•

2,469,496 subordinated units, representing a 34.6% limited partner interest in the Partnership; and a



•

90.2% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.

        We were founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering in 1996.

        Our common stock is traded on the American Stock Exchange under the symbol "MWP." Our executive offices are located at 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112-5000.

Recent Developments

        During the year ended December 31, 2003, we completed several important initiatives that accomplished the transformation of MarkWest Hydrocarbon into a company focused on increasing shareholder value through our ownership in MarkWest Energy Partners. Specifically, we discontinued our exploration and production business and MarkWest Energy Partners grew primarily through the acquisition of third-party midstream assets.

MarkWest Hydrocarbon Dispositions

        Our three primary dispositions were the following:

•

We sold our San Juan Basin oil and gas producing properties in two separate sales during the second and third quarters of 2003. The San Juan Basin properties represented substantially all of our exploration and production business located in the United States. Net proceeds from the sales were approximately $55.3 million. We recognized a net pretax gain on the sales of approximately $23.3 million.



•

We sold our entire Canadian exploration and production business in two separate transactions during December 2003. Net proceeds from the sales were approximately $49.1 million. We recognized a net pretax loss on the sales of approximately $4.8 million.



•

We sold two of our three NGL terminals during the third quarter of 2003. Net proceeds were approximately $2.3 million. We recognized a net pretax loss on the sales of less than $0.1 million.

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MarkWest Energy Partners Acquisitions

        During 2003, MarkWest Energy Partners completed the following four acquisitions:

•

In March 2003, the Partnership completed the acquisition of $39.9 million of midstream assets in the Southwest. The acquired assets, primarily located in Texas, were comprised of (i) three lateral natural gas pipelines transporting natural gas under firm contracts to power plants and (ii) twenty gathering systems gathering more than 44 MMcf/d. One of the smaller gathering systems acquired was subsequently disposed of in December 2003 for an immaterial amount.



•

In September 2003, MarkWest Energy Partners acquired a 68-mile intrastate gas transmission pipeline near Lubbock, Texas for approximately $12.2 million.



•

In December 2003, the Partnership acquired a 167-mile gathering system, a processing plant and related compression facilities located in Oklahoma for approximately $38.0 million.



•

Also in December 2003, MarkWest Energy Partners acquired an intrastate crude oil pipeline in Michigan for approximately $21.3 million.

Reduction in Debt

        Primarily as a result of the dispositions discussed above, we strengthened our balance sheet during 2003 by paying off our credit facility in its entirety in December 2003 and by aggregating $33.4 million in unrestricted on-hand cash (exclusive of MarkWest Energy Partners' cash balance) as of December 31, 2003. The debt on our balance sheet at December 31, 2003, is comprised entirely of MarkWest Energy Partners' outstanding debt.

Strategy

        Our two-part strategy is to increase shareholder value by growing MarkWest Energy Partners and its cash distributions, and to improve the stability of our operating margins in our marketing segment.

        We believe the primary opportunity to increase shareholder value is tied to our ability to successfully grow MarkWest Energy Partners. The Partnership's strategy is to increase distributable cash flow per unit by increasing utilization of its facilities, expanding existing operations through new construction, expanding operations through accretive acquisitions, and securing additional long-term fee-based contracts. If the Partnership is successful in implementing this strategy, we believe the total amount of cash distributions it makes will increase and our share of those distributions will also increase. The Partnership has announced multiple increases in its quarterly distribution since its initial public offering in May 2002. During that time, the Partnership increased the quarterly per unit cash distribution on its common and subordinated units by 34%, from $0.50 to $0.67.

Financial Information About Segments

        Our business activities are segregated into two segments:

•

Managing MarkWest Energy Partners



•

Marketing of natural gas and NGLs

        During fiscal 2003, we discontinued our exploration and production business.

        You should read Note 17 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference, for financial information about our business segments.

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Narrative Description of Business

Our Relationship with MarkWest Energy Partners

        We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into MarkWest Energy Partners in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts with MarkWest Energy Partners whereby MarkWest Energy Partners provides midstream services for us in exchange for a fee. In accordance with generally accepted accounting principles, MarkWest Energy Partners' financial results are included in our consolidated financial statements. All intercompany accounts and transaction are eliminated during consolidation.

        As a result of the contracts between MarkWest Energy Partners and us mentioned above, we are the Partnership's largest customer, accounting for 42% of its revenues and 59% of its gross margin (revenues less purchased product costs) for the year ended December 31, 2003. We expect we will account for less of MarkWest Energy Partners' business in the future as it continues to acquire assets and increase its customer and business diversification.

        Also at the time of MarkWest Energy Partners' initial public offering, we entered into an omnibus agreement with MarkWest Energy Partners and related parties that governs potential competition and indemnification obligations among the involved parties.

        Through our majority ownership in the Partnership's general partner, we control and operate MarkWest Energy Partners. Our employees are responsible for conducting the Partnership's business and operating its assets pursuant to a Services Agreement, which was formalized effective January 1, 2004.

MarkWest Energy Partners' Assets

        The following discussion outlines MarkWest Energy Partners' business and assets. Discussion of the marketing assets we own that are unrelated to MarkWest Energy Partners follows the discussion of MarkWest Energy Partners' assets.

        The Partnership has three primary geographic areas of operation:

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Appalachia.  The Partnership is the largest processor of natural gas in the Appalachian basin, one of the country's oldest natural gas producing regions. MarkWest Energy Partners' Appalachian assets include five natural gas processing plants, 136 miles of NGL pipeline, a NGL fractionation plant and an 11 million-gallon underground NGL storage facility.



•

Southwest.  The Partnership owns an aggregate of 302 miles of natural gas gathering pipelines in 19 gathering systems in Texas, Oklahoma, Louisiana, Mississippi and New Mexico. MarkWest Energy Partners also owns a gas processing plant and four Texas intrastate gas transmission pipelines that transmit natural gas to power plants, municipalities and other large industrial end users.



•

Michigan.  The Partnership owns a 90-mile gas gathering pipeline and one natural gas processing plant in Michigan. MarkWest Energy Partners also owns approximately 250 miles of an intrastate crude gathering pipeline, which we refer to as the Michigan Crude Pipeline, the primary intrastate crude oil pipeline in Michigan.

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Appalachian Assets

Appalachian Gathering and Processing Facilities

        The table below describes MarkWest Energy Partners' processing assets in the Appalachian region:

(1)

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

(2)

During the first half of 2004, the Partnership began construction of a new 24 MMcf/d processing plant. This new plant will replace the Partnership's existing Cobb plant.

(3)

The Kermit processing plant is operated by Columbia Gas and the Partnership does not receive inlet volume information.

        Kenova Processing Plant.    MarkWest Energy Partners' Kenova cryogenic facility was expanded by 40 MMcf/d in 2001 to accommodate expected new production from Columbia Resources. The cryogenic process utilizes a turbo-expander and heat exchangers to cool the gas, which condenses the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives all of its intake of raw natural gas from Columbia Gas' transmission lines and processes gas produced in Knott, Magoffin, Floyd, Johnson, Martin and Lawrence Counties, Kentucky, and Mingo, Logan, Lincoln, Boone, Cabell, Putman, Wayne and Kanawha Counties, West Virginia. NGLs extracted at this facility are transported to the Partnership's Siloam fractionator via its pipeline.

        Boldman Processing Plant.    The Partnership's Boldman straight refrigeration processing plant processes gas using a propane refrigeration system to cool the gas and condense the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives its entire intake of raw natural gas from Columbia Gas' transmission lines and processes gas produced in Pike, Floyd, Letcher and Knott Counties, Kentucky. NGLs extracted at this facility are first delivered by truck to the Partnership's Maytown facility and transported on its leased pipeline to its Siloam fractionator.

        Maytown Processing Plant.    Pursuant to contract, Equitable Production Company (Equitable; a subsidiary of Equitable Resources, Inc.) operates MarkWest Energy Partners' Maytown facility, a straight refrigeration plant, on the Partnership's behalf. As operator, Equitable is responsible for the day-to-day operation of the Maytown plant. Under our Gas Processing Agreement with Equitable, MarkWest Energy Partners has the right to assume the role of operator upon providing Equitable with 30 day written notice. Like the Boldman plant, the Maytown plant also processes gas using a propane refrigeration system to cool the gas and condense the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives its entire intake of raw natural gas from Equitable's gathering system in Kentucky. NGLs extracted at this facility are transported to

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Siloam via pipeline. The plant also contains a truck unloading facility that allows for the delivery of NGLs into the Partnership's pipeline system for transportation to its Siloam fractionator.

        Under the terms of the Gas Processing Agreement, Equitable agrees to deliver to MarkWest Energy Partners 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 the Partnership the exclusive right to process all of this natural gas and conveys to it title to the extracted NGLs.

        As compensation for its services, MarkWest Energy Partners earns both a fee for its transportation and fractionation services as well as a percentage of the proceeds from the sale of NGLs produced on Equitable's behalf. A portion of the transportation and fractionation fee is subject to annual adjustment in proportion to the annual average percentage change in the Producer Price Index for Oil and Gas Field Services. We, in a separate agreement, have agreed to buy the NGLs from MarkWest Energy Partners and pay a purchase price equal to the net proceeds received from the resale of such NGLs to third parties. The initial term of the Gas Processing Agreement with Equitable runs through February 2015. The operating revenues the Partnership earns under the percent-of-proceeds component of this agreement will fluctuate with the sales price for the NGLs produced.

        Cobb Processing Plant.    MarkWest Energy Partners' Cobb facility, a refrigerated lean oil processing plant, was acquired by MarkWest Hydrocarbon in 2000 and then conveyed to the Partnership in 2002. The refrigerated lean oil process utilizes a propane refrigeration system to cool the gas and the lean oil. The chilled lean oil absorbs the NGLs that are then separated from the lean oil by distillation. An upgrade of this facility was completed in 2000 by MarkWest Hydrocarbon to decrease downtime and increase recoveries from the facility. This facility receives its entire intake of raw natural gas from Columbia Gas' transmission lines and processes gas produced in Kanawha, Clay, Roane and Jackson Counties, West Virginia. NGLs extracted at this facility are transported to the Partnership's Siloam facility by tanker truck. During the first half of 2004, the Partnership is replacing its existing Cobb facility with a newly constructed 24 MMcf/d processing plant. The new plant is expected to require significantly less operating and maintenance expense. The cost of the construction is expected to be approximately $2.1 million. We will provide approximately $1.7 million in payment of a portion of the costs. The Partnership will pay the remaining approximately $0.4 million and own and operate the plant.

        Kermit Processing Plant.    MarkWest Energy Partners' Kermit facility, a straight refrigeration plant, was constructed in connection with the expansion at its Kenova facility and in anticipation of increased demand for its services by Columbia Resources. This facility was designed and constructed to increase the volume of natural gas transported to the Partnership's Kenova facility by decreasing the liquid content of the natural gas in Columbia Gas' transmission lines. The Kermit plant processes gas using a similar straight refrigeration process used at the Partnership's Boldman plant. NGLs extracted at this facility are transported to MarkWest Energy Partners' Siloam facility via tanker truck.

        The Partnership does not operate its Kermit plant. Under the terms of a Construction and Lease Agreement between MarkWest Hydrocarbon and Columbia Gas, Columbia Gas has the exclusive authority and responsibility for the operation, maintenance and repair of the Kermit Plant. Columbia has the right to operate the plant only during such times as it deems necessary for operational purposes. Columbia Gas has the right to purchase the Kermit plant from the Partnership at any time during the lease term and at the termination of the lease. The lease expires on December 31, 2015. If Columbia Gas does not exercise its option to purchase, MarkWest Energy Partners, at its expense, must remove the plant from Columbia Gas' property within a reasonable time following the expiration of the lease.

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        Prior to conveying it to the Partnership in 2002, MarkWest Hydrocarbon completed a multi-year expansion of the Appalachian infrastructure in mid-2001, increasing total natural gas designed processing capacity by 127 MMcf/d.

Appalachian NGL Pipelines

        All of the NGLs recovered at the Partnership's 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 the Partnership's Cobb and Kermit plants are transported to Siloam via tanker trucks.

        MarkWest Energy Partners' Appalachian 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.

        The Partnership's 40-mile Ranger to Kenova NGL pipeline and the Maytown to Ranger segment of its leased Maytown to Institute pipeline, together with its existing Kenova to Siloam pipeline, form 136 miles of NGL pipeline running through the southern portion of the Appalachia basin. Prior to conveying it to the Partnership in 2002, MarkWest Hydrocarbon acquired the Ranger to Kenova pipeline and leased the 100-mile Maytown to Institute pipeline in 2000 as part of an overall Appalachian expansion project. MarkWest Hydrocarbon originally acquired the Kenova to Siloam pipeline in 1988. MarkWest Energy Partners leases the Maytown to Institute pipeline from Equitable. Our lease expires in 2015. Prior to leasing the Maytown to Institute pipeline, Boldman NGLs were transported by truck to Siloam at significantly greater expense than trucking to an injection point.

Appalachian Fractionation Facility

        MarkWest Energy Partners' Siloam fractionation plant receives substantially all of its NGLs via pipeline or tanker truck from its five Appalachia processing plants, with the balance received from tanker truck and rail car deliveries from other third-party NGL sources. The NGLs are then separated into NGL products, including propane, isobutane, normal butane and natural gasoline. The typical composition of the NGL throughput in its Appalachian operations has been approximately 64% propane, 18% normal butane, 6% isobutane, and 12% natural gasoline. The Partnership does not currently produce or sell ethane. Its Siloam fractionation plant has been continually upgraded and maintained since its acquisition by MarkWest Hydrocarbon in 1988.

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        The following table provides additional detail regarding MarkWest Energy Partners' Siloam fractionation plant:

Appalachian Storage Facilities

        In Appalachia, the Partnership's 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 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.

Southwest Assets

Southwest Gathering and Processing Facilities

        The table below describes MarkWest Energy Partners' Southwest gathering and processing assets:

(1)

The Partnership acquired the Foss Lake Gathering System and Arapaho Processing Plant on December 1, 2003.

(2)

The Partnership acquired the Appleby Gathering System, along with 18 other gathering systems, as part of its March 28, 2003 Pinnacle acquisition.

(3)

Throughput volumes are for the calendar year ended December 31, 2003, and not just for the period of time the Partnership owned each facility.

        Foss Lake Gathering System.    MarkWest Energy Partners acquired the Foss Lake Gathering System as part of its western Oklahoma acquisition in December 2003. The system is a low-pressure gathering system consisting of approximately 167 miles of four to 20-inch pipeline connected to approximately 270 wells and includes 10,240 horsepower of owned-compression and 770 horsepower of leased-compression. The system gathers natural gas from the Anadarko Basin in western Oklahoma from approximately 50 producers. The Partnership generates operating margins by charging fixed fees per Mcf of natural gas gathered. All of the natural gas gathered into the system is dehydrated at the Butler compression station for delivery to the Arapaho processing plant.

        Appleby Gathering System.    MarkWest Energy Partners acquired the Appleby Gathering System as part of its Pinnacle acquisition in March 2003. The system is a low-pressure gathering system consisting of approximately 80 miles of three to eight-inch pipeline connected to approximately 136 wells and includes approximately 6,520 horsepower of leased-compression. The system gathers natural gas from

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the Travis Peak Basin in east Texas from approximately seven producers, with one producer accounting for approximately 50% of the volumes. The Partnership sells the gas to marketing companies and to an industrial user under short-term marketing contracts. The Partnership generates a majority of its operating margin through percent-of-index contracts, with the remaining margin generated through fee-based contracts.

        Other Gathering Systems.    As part of the Pinnacle acquisition, MarkWest Energy Partners acquired 19 other natural gas gathering systems, primarily located in Texas. One of the smaller gathering systems was subsequently disposed of in December 2003. The systems typically gather natural gas from mature producing wells. The Partnership generates operating margins from these systems through percent-of-index, percent-of-proceeds and fixed-fee contracts.

        Arapaho Processing Plant.    MarkWest Energy Partners' acquired the Arapaho Processing Plant, located in Custer County, Oklahoma, as part of the western Oklahoma acquisition in December 2003. The Arapaho gas processing plant is a cryogenic plant installed in early 2000. The plant is designed to recover ethane and heavier NGLs, including propane. The plant can also reject ethane and continue to recover high levels of propane. The plant delivers processed natural gas into the Panhandle Eastern Pipe Line, or PEPL, and recovered NGLs are sold to Koch Hydrocarbon LP. The Partnership generates operating margins through keep-whole contracts. Under these keep-whole arrangements, MarkWest Energy Partners processes the natural gas and sells the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas stream during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers, or make a cash payment to the producers. Accordingly, under these arrangements the Partnership's revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. In the latter case, however, the Partnership has the option of not operating the plant in a low processing margin environment because the Btu content of the inlet natural gas meets the PEPL Btu specification. In addition, approximately 45% of the Foss Lake gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low processing margin environment. Because of its ability to operate the plant in several recovery modes, or to turn it off, as well as the additional fees provided for in the gas gathering contracts, the Partnership's exposure is limited to a portion of the operating costs of the plant.

        Southwest Lateral Pipelines.    MarkWest Energy Partners acquired the Lake Whitney lateral, the Rio Nogales lateral and the Blackhawk lateral as part of its Pinnacle acquisition in March 2003.

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The Lake Whitney lateral, constructed in 2001 and 2002, is a 33-mile intrastate natural gas pipeline that transports natural gas to Mirant America Energy Marketing's 556-megawatt Bosque power plant, located near Waco, Texas. The lateral transports natural gas from the El Paso Field Services Pipeline and is the only pipeline connected to, and the sole source of natural gas for, the Bosque power plant. The Partnership has a 30-year fixed-fee contract with Mirant for natural gas transportation on this lateral pipeline. This contract expires in 2030.



•

The Rio Nogales lateral, constructed in 2001, consists of two natural gas lateral pipelines, which in aggregate total 27 miles in length. The laterals transport natural gas from the Duke Energy Field Services Pipe Line, the Houston Pipe Line and the Oasis Pipe Line to Constellation Energy Group's 800-megawatt Rio Nogales power plant, located near Seguin, Texas. The Partnership has a 20-year fixed-fee contract with Constellation. This contract expires in 2022.



•

The Blackhawk lateral is a seven-mile intrastate natural gas pipeline that serves as a back-up natural gas supply source for Borger Energy Associates' 200-megawatt cogeneration power facility, located in Borger, Texas. The lateral is connected to the El Paso Natural Gas pipeline. The Partnership has a fixed-fee contract as operator of the pipeline through September 2005.

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However, the Partnership's fixed-fee revenue reduces as of April 2004, at which time ownership of the lateral will transfer to Borger Energy Associates.

        MarkWest Energy Partners acquired the Lubbock Lateral from Power-Tex Joint Venture in September 2003. It consists of one 12-inch, 50-mile pipeline and one six-inch, 18-mile pipeline serving several industrial users and municipalities in and around Lubbock, Texas, including the City of Lubbock, Texas Tech University and Southwestern Public Service, a subsidiary of Xcel Energy. The Lubbock Lateral transports natural gas from the El Paso Natural Gas pipeline and the Northern Natural Gas Pipeline. The Partnership has fixed-fee contracts with maturities ranging from one to five years. The lateral has a capacity of 100 MMcf/d and throughput was approximately 26 MMcf/d for 2003.

Michigan Assets

Michigan Gathering and Processing Facilities

        The table below describes MarkWest Energy Partners' Michigan gathering and processing assets:

(1)

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

        The Partnership's 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 Merit Energy Company (Merit), Inc. The Partnership's Fisk processing plant is located adjacent to Merit's treatment plant. The Partnership's gathering pipeline serves approximately 30 wells and 13 producers in this three county area. The Fisk plant processes all of the natural gas gathered and produces propane and a butane-natural gasoline mix. The Partnership processes 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 the Partnership's pipeline and processing facility is dedicated to its gathering and processing facilities. Under the fee component of these agreements, which represent approximately half of the Partnership's gross margin in Michigan, producers pay a fee to transport and treat their gas. Under the percent-of-proceeds component, the Partnership retains a portion of the proceeds from the sale of the NGLs as compensation for the processing services provided.

        MarkWest Energy Partners receives 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that it gathers and processes in Michigan. MarkWest Hydrocarbon retains a 70% net profits interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d.

        Under a Gas Treating and Processing Agreement between MarkWest Energy Partners' subsidiary, West Shore Processing Company, LLC and Merit, Merit operates the Fisk natural gas processing plant. Under the terms of this agreement, Merit treats and processes sour gas delivered to its treatment plant by the Partnership and delivers the treated gas to the Partnership's Fisk plant where NGLs are extracted. For these services, the Partnership pays Merit a set monthly treating fee and a volumetric treating fee based on the amount of gas we deliver to Merit. Both of these fees are adjusted annually

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in proportion to the change in a government reported index. In addition, Merit has agreed to pay the Partnership a per-gallon surcharge for propanes, butanes and pentanes (or a combination thereof) contained in the treated gas that is not subsequently delivered to it for processing at its natural gas processing plant.

        The Partnership generates revenues from its Michigan natural gas and NGL operations primarily by charging a fee for the gathering and processing services provided. Its contracts in Michigan also provide that the Partnership retains a portion of the proceeds from the sale of NGLs that are produced at its Michigan facility. The Partnership's propane and butane-natural gasoline production is usually sold at the plant.

Michigan Crude Pipeline

        MarkWest Energy Partners acquired the Michigan Crude Pipeline in December 2003. The system consists of approximately 152 miles of eight to 16-inch main pipeline, approximately 92 miles of four to ten-inch gathering pipeline, four truck loading facilities and 15 storage tanks. The pipeline, which serves over 1,000 oil and gas wells on the Niagaran Reef Trend, delivers crude oil to the Enbridge Pipeline. Approximately 60% of the crude oil transported through the pipeline was shipped for one marketing customer. The Partnership generates operating margins by charging a tariff per barrel of crude oil transported. Because the Partnership has the ability to set the amount of this tariff, it believes this pipeline will provide it with a relatively stable base of cash flows. The pipeline has a capacity of 60,000 bpd and transported approximately 16,200 bpd of crude oil for the year ended December 31, 2003.

MarkWest Hydrocarbon Assets

Marketing

        Our marketing group markets our NGL production in Appalachia. In 2003, we sold approximately 177 million gallons of NGLs extracted at the Partnership's Siloam facility. We ship NGL products from Siloam by truck, rail and barge. Our marketing customers include propane retailers, refineries, petrochemical plants and NGL product resellers. Most marketing sales contracts have terms of one year or less, are made on best-efforts basis and are priced in reference to Mt. Belvieu index prices or plant posting prices. In addition to our NGL product sales, our marketing operations are also responsible for the purchase of natural gas delivered for the account of producers pursuant to our keep-whole processing contracts.

        We strive to maximize the value of our NGL output by marketing directly to our customers. We minimize the use of third-party brokers, preferring instead to support a direct marketing staff focused on multi-state and independent dealers. Additionally, we use our own trailer and railcar fleet, as well as our own terminal and owned and leased storage facilities, to enhance supply reliability to our customers. These efforts have allowed us to maintain premium pricing for the majority of our NGL products compared to Gulf Coast spot prices.

        In Appalachia, we have entered into operating agreements with Columbia Gas Transmission Corporation (Columbia Gas) with respect to natural gas delivered into its transmission facilities upstream of MarkWest Energy Partners' Kenova, Boldman and Cobb facilities. Under the terms of these operating agreements, Columbia Gas has agreed to use reasonable, diligent efforts to supply these facilities with consistent volumes of natural gas shipped by Columbia Gas on behalf of the Appalachian producers. The initial terms of our agreements with Columbia Gas run through December 31, 2015, with annual renewals thereafter.

        Our operating agreements with Columbia Gas require us to enter into contracts with the natural gas producers whose production will be processed in the Partnership's Kenova, Boldman and Cobb facilities. We have contractual commitments with approximately 260 such producers in Appalachia.

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Approximately 54% of these contracts representing approximately 27% of the committed volumes expire in 2009. The remaining balance of approximately 46% of the contracts representing approximately 73% of the committed volumes expires in 2015. Our largest producers are Columbia Resources and Equitable. Under the provisions of our contracts with the Appalachian producers, the producers have committed all of the natural gas they deliver into Columbia Gas' transmission facilities upstream of MarkWest Energy Partners' Kenova, Boldman and Cobb facilities for processing.

        As compensation for providing processing services to our Appalachian producers (we have since outsourced these services to MarkWest Energy Partners as discussed below), we earn both a fee and the NGLs produced. In return, we are required to replace, in dry natural gas, the Btu value of the NGLs extracted. This Btu replacement obligation is referred to in the industry as a "keep-whole" arrangement. In keep-whole arrangements, our principal cost is the replacement of the Btus extracted from the gas stream in the form of NGLs or consumed as fuel during processing with dry gas of an equivalent Btu content. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. In the event natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer "whole" results in operating losses. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the "frac spread."

        At the closing of MarkWest Energy Partners' initial public offering on May 24, 2002, we outsourced our midstream services to the Partnership, which performs natural gas gathering and processing and NGL transportation, fractionation and storage services for us for a fee pursuant to the terms of our operating agreements with the Partnership. Under those agreements, we retained all the benefits and associated risks of our keep-whole contracts with producers. Our NGL and gas marketing operations were not contributed to MarkWest Energy Partners.

        Our keep-whole contracts expose us to commodity price risk, both on the sales side (of NGLs) and on the purchase side (of natural gas), which may make our marketing results and cash flows volatile. We attempt to mitigate our commodity price risk through our hedging program. You should read Item 7A, "Quantitative and Qualitative Disclosures About Market Risk" for further details about our commodity price risk management program, which is incorporated herein by reference.

        Our natural gas marketing group sources new gas for MarkWest Energy Partners' facilities, purchases our replacement Btu gas requirements, and assists with our business development efforts. Our natural gas marketing operations are a fundamentally high-dollar, low-margin business. Consequently, a significant percentage of our overall revenue stems from gas marketing, but the contribution to our gross margin is modest. For the years ended December 31, 2003, 2002, and 2001, 17%, 37%, and 36%, respectively, of gathering, processing and marketing revenue stemmed from gas marketing. However, the gas marketing gross margin as a percent of gathering, processing and marketing gross margin was just 0%, 12%, and 4%, respectively.

Exploration and Production

        We discontinued our exploration and production business during 2003. At December 31, 2003, our exploration and production assets had been reduced to a minority interest in three wells in Michigan.

Reserves

        Please review Note 20 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference, for information regarding our proved and developed oil and gas reserves and the standardized measure of discounted future net cash flows and changes therein.

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        We have not filed any oil or natural gas reserve estimates or included any such estimates in reports to a federal or foreign government authority or agency, other than the Securities and Exchange Commission (SEC) and the Department of Energy (DOE). There were no differences between the reserve estimates included in the SEC report, the DOE report and those included herein, except for production and additions and deletions due to the difference in the "as of" dates of such reserve estimates.

Production

        The following table sets forth information regarding net oil and natural gas production, average sales prices and other production information. Hedging gains and losses are disclosed separately for the years ended December 31, 2003, 2002 and 2001.

(1)

The results for 2001 reflect the result of our Canadian acquisition since August 2001. Production in Canada for August 1, 2001 to December 31, 2001, averaged 13,500 Mcfe/d.

(2)

Oil and liquid production is converted to natural gas equivalents (Mcfe) at a rate of one barrel to six Mcf.

Productive Wells

        The following table sets forth information regarding the number of productive wells in which we held a working interest at December 31, 2003:

(1)

Each well completed to more than one producing zone is counted as a single well.

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(2)

A gross well is a well in which a working interest is owned.

(3)

One net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interest owned in gross wells.

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Drilling and Recompletion Activity

        The following table sets forth our gross and net interest in exploration and developmental wells drilled and wells recompleted during the periods indicated.

(1)

The results for 2001 reflect the results of our Canadian acquisition since August 2001.

(2)

A gross well is a well in which a working interest is owned.

(3)

One net well is deemed to exist when the sum of the fractional ownership working interest in gross wells equals one producing well, in addition to the existing producing horizon. These are dually completed wells.

(4)

A non-productive well is a well deemed to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.

(5)

A recompletion well is a well which within an existing wellbore, a different geological horizon with proved reserves is completed as a producing well, in addition to the existing producing horizon. These are dually completed wells.

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Acreage

        The following table sets forth the leasehold acreage held by MarkWest Hydrocarbon at December 31, 2003.

(1)

Developed acres are those acres that are spaced or assigned to productive wells.

(2)

Undeveloped acres are considered to be those acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. It should not be confused with undrilled acreage held by production under the terms of a lease.

(3)

A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)

A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres.

(5)

On December 12, 2003, the Company assigned all of its remaining undeveloped acreage located in Michigan to M & M Exploration Partners, LLC. After the second anniversary of the assignment, the Company has the right to receive re-assignment of any acreage not committed to an exploration venture.

Factors Affecting our Operations

Seasonality

        A substantial portion of our revenues and, as a result, our gross margin, remains dependent upon the volume and sales price of NGL products, particularly propane. The volume and sales price of NGL products fluctuate with the winter weather conditions and other supply and demand determinants. The strongest demand for propane and the highest propane sales margins generally occur during the winter heating season. As a result, we recognize a substantial portion of our annual income from our marketing segment during the first and fourth quarters of the year.

Competition

MarkWest Hydrocarbon

        MarkWest Hydrocarbon faces competition for marketing products and purchasing natural gas supplies. Competition for customers and purchases of natural gas are based primarily on price, delivery capabilities, flexibility, and maintenance of quality customer relationships. The Company's competitors are similar to those of MarkWest Energy Partners (described below).

MarkWest Energy Partners

        MarkWest Energy Partners faces competition for crude oil and natural gas transportation and in obtaining natural gas supplies for processing and related services operations, in obtaining unprocessed NGLs for fractionation, and in marketing products and services. Competition for natural gas supplies is based primarily on location of gas gathering facilities and gas processing plants, operating efficiency

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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, MarkWest Energy Partners faces strong competition in acquiring natural gas and crude oil supplies and in competing for service fees. The Partnership's competitors include:

•

major integrated oil companies;



•

major interstate and intrastate pipelines;



•

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



•

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

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

Operational Risks and Insurance

        Our operations are subject to the usual hazards incident to the exploration, production, gathering and processing of natural gas; the transmission, fractionation and storage of NGLs; and the transmission of crude oil; such as explosions, product spills, leaks, emissions and fires. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage, and may result in curtailment or suspension of operations at the affected facility.

        We maintain general public liability, property and business interruption insurance in amounts that we consider to be adequate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive. Consistent with insurance coverage generally available to the industry, our insurance policies provide coverage for losses or liabilities related to sudden occurrences of pollution or other environmental damage.

        The occurrence of a significant event that we are not fully insured or indemnified against, and/or the failure of a party to meet its indemnification obligations to us, could materially and adversely affect our operations and financial condition. Moreover, we cannot provide assurance that we will be able to maintain adequate insurance in the future at rates we consider reasonable. To date, however, we have not experienced material uninsured losses or any difficulty in acquiring insurance coverage in amounts we believe to be adequate.

Title to Properties

        We believe we have satisfactory title to all of our assets.

        Substantially all of MarkWest Energy Partners' pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. The Partnership has obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which the Partnership's pipelines were built was purchased in fee. The Partnership's Siloam fractionation plant and Kenova processing plant are on land that the Partnership owns in fee.

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        Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to the Partnership required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. The Partnership's general partner believes that it has obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for the Partnership to operate its business in all material respects.

        The Partnership's general partner believes that the Partnership has satisfactory title to all of the Partnership's assets. To the extent certain defects in title to the assets contributed to the Partnership or failures to obtain certain consents and permits necessary to conduct our business arise within three years after the closing of the Partnership's initial public offering, the Partnership is entitled to indemnification from MarkWest Hydrocarbon under the Omnibus Agreement. Title to property may be subject to encumbrances. The Partnership's general partner believes that none of such encumbrances materially detract from the value of the Partnership's properties or from its interest in these properties or should materially interfere with their use in the operation of the Partnership's business.

        The Partnership has pledged substantially all of its assets to secure its credit facility as discussed in Note 9 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference.

Regulatory Matters

        The activities of MarkWest Hydrocarbon and MarkWest Energy Partners 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.

        Some of MarkWest Energy Partners' gas, liquids and crude oil gathering and transmission operations are subject to regulation by various state regulatory bodies. In many cases, various phases of our gas, liquids and crude oil operations in the states in which the Partnership operates are subject to rate and service regulation. The applicable state statutes generally require that the Partnership's rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services. Regulatory authorities in the states in which the Partnership operates have generally not been aggressive in regulating gas, liquids and crude oil gathering and transmission facilities and have generally not investigated the rates or practices of the owners of such facilities in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally.

        The Partnership's Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, who has entered into agreements with the Partnership providing for a fixed transportation charge for the term of the agreements, which expire on December 31, 2015. The Partnership is the only other shipper on the pipeline. As the Partnership does not operate its Appalachian pipeline as a common carrier and does 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. Similarly, the Partnership's Michigan Crude Pipeline delivers crude oil to a third party carrier which makes deliveries both within and outside Michigan, in this case for unaffiliated third parties. Neither pipeline is currently subject to regulation by the Federal Energy Regulatory Commission, or FERC. However, if a shipper sought to challenge the jurisdictional status of either of these pipelines, the FERC could determine that such transportation is within its jurisdiction under the Interstate Commerce Act. In such a case, the Partnership would be required to file a tariff for such transportation with the FERC and provide a cost justification for the transportation charge. Because MarkWest Hydrocarbon has agreed to not challenge the status of the Partnership's Appalachian pipeline or the transportation charge during the term of the agreements between the Partnership and MarkWest Hydrocarbon and, moreover, the likelihood of

21

other entities seeking to utilize the Partnership's Appalachian pipeline is limited, the likelihood of such a challenge on the Partnership's Appalachian pipeline is remote. Similarly, because the Partnership is operating its Michigan Crude Pipeline in the same manner as it was historically operated by Shell for a significant period of time prior to the Partnership's acquisition and because the Partnership's operations are entirely within the state of Michigan, the likelihood of a challenge to the status of this pipeline is considered remote. However, the Partnership cannot predict whether a FERC jurisdictional challenge might be made with respect to either of these pipelines, nor provide assurance that such a challenge would not adversely affect the Partnership's results of operations.

        Some of the Partnership's liquids and crude oil gathering facilities deliver into pipelines that have the ability to make redeliveries in both interstate and intrastate commerce. The rates the Partnership charges on its liquids and crude oil facilities are not regulated at the state or federal level, however, there can be no assurance that the rates for service on these facilities will remain unregulated in the future.

Environmental Matters

MarkWest Hydrocarbon

        We are subject to environmental risks normally incident to our operations and construction activities including, but not limited to, uncontrollable flows of natural gas, fluids and other substances into the environment, explosions, fires, pollution, and other environmental and safety risks. Our business is subject to comprehensive state and federal environmental regulations. For example, we, without regard to fault, could incur liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (also known as Superfund), or state counterparts, in connection with the disposal or other releases of hazardous substances, including sour gas, and for natural resource damages. Further, the recent trend in environmental legislation and regulations is toward stricter standards, and this will likely continue in the future.

        Our activities are subject to environmental and safety regulation by federal and state authorities, including, without limitation, the state environmental agencies and the federal Environmental Protection Agency, which can increase the costs of designing, installing and operating our facilities. In most instances, the regulatory requirements relate to the discharge of substances into the environment and include measures to control water and air pollution.

        Laws and regulations may require us to obtain a permit or other authorization before we may conduct certain activities or we may be subject to fines and penalties for non-compliance. Further, these rules may limit or prohibit our activities within wilderness areas, wetlands, and areas providing habitat for certain species or other protected areas. We are also subject to other federal, state and local laws covering the handling, storage or discharge of materials used by us. We believe that we are in material compliance with all applicable laws and regulations.

MarkWest Energy Partners

        General.    MarkWest Energy Partners' operation of processing and fractionization plants, pipelines and associated facilities in connection with the gathering and processing of natural gas, the transportation, fractionization and storage of NGLs and the storage and gathering and transportation of crude oil 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 the Partnership's overall cost of doing business, including the Partnership's cost of constructing, maintaining and upgrading equipment and facilities. The Partnership's 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,

22

issuance of injunctions. MarkWest Energy Partners believes that the Partnership's 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 the Partnership's 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 MarkWest Energy Partners currently anticipates. Moreover, risks of process upsets, accidental releases or spills are associated with the Partnership's operations and MarkWest Energy Partners cannot assure you that MarkWest Energy Partners 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, MarkWest Energy Partners may be unable to pass on those increases to the Partnership's customers. MarkWest Energy Partners 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 the Partnership's 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 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 the Partnership's ordinary operations MarkWest Energy Partners will generate wastes that may fall within the definition of a "hazardous substance." MarkWest Energy Partners may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. MarkWest Energy Partners has not received any notification that MarkWest Energy Partners may be potentially responsible for cleanup costs under CERCLA.

        MarkWest Energy Partners also generates both hazardous and nonhazardous 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 nonhazardous wastes, including crude oil and natural gas wastes. MarkWest Energy Partners is not currently required to comply with a substantial portion of the RCRA requirements because the Partnership's operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by the Partnership that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more

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rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in the Partnership's capital expenditures or plant operating expenses.

        MarkWest Energy Partners currently owns or leases, and has in the past owned or leased, properties that have been used over the years for natural gas gathering and processing, for NGL fractionation, transportation and storage and for the storage and gathering and transportation of crude oil. 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 the Partnership during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom MarkWest Energy Partners 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, MarkWest Energy Partners 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. MarkWest Energy Partners does not believe that there presently exists significant surface and subsurface contamination of the Partnership's properties by hydrocarbons or other solid wastes for which MarkWest Energy Partners is currently responsible.

        Ongoing Remediation and Indemnification from Columbia Gas.    Columbia Gas is the previous or current owner of the property on which the Partnership's Kenova, Boldman, Cobb and Kermit facilities are located and is the previous operator of the Partnership's Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman and Cobb facilities pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and 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 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 the Partnership the benefit of its indemnity from Columbia Gas with respect to the Cobb, Boldman and Kermit facilities. While MarkWest Energy Partners is 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 the Partnership with the benefit of its indemnity, as well as any other third-party environmental indemnity of which it is a beneficiary. To date, Columbia Gas has been performing all actions required under these agreements, and, accordingly, MarkWest Energy Partners does 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 the Partnership's financial condition or results of operations. MarkWest Hydrocarbon has also agreed to provide the Partnership an additional environmental indemnification pursuant to the terms of the Omnibus Agreement. See "Certain Relationships and Related Transactions."

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        Air Emissions.    The Partnership's 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, the Partnership's 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 the Partnership's 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 MarkWest Energy Partners can give no assurances, MarkWest Energy Partners believes implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on the Partnership's 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. MarkWest Energy Partners believes that MarkWest Energy Partners is in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that continued compliance with such existing permit conditions will not have a material effect on the Partnership's results of operations.

        Safety Regulation.    The Partnership's 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 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. MarkWest Energy Partners believes that the Partnership's 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 the Partnership's results of operations or financial position.

        The Pipeline Safety Improvement Act of 2002 includes numerous provisions that tighten federal specifications 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 Act of 2002 will not have a material effect on its operations.

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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 statues that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to our 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 we cannot accurately estimate these expenditures at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.

Employees

        As of December 31, 2003, we had 128 employees. At our fractionation facility in South Shore, Kentucky, the Paper, Allied Industrial, Chemical, and Energy Workers International Union Local 5-372 represents 14 employees. We entered into our collective bargaining agreement with this Union on June 29, 2001 that expires on June 28, 2004. The agreement covers only hourly, non-supervisory employees. We consider our labor relations to be good.

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 is reasonably practicable after we electronically file such material with the SEC.

        In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

ITEM 3. LEGAL PROCEEDINGS

        MarkWest Hydrocarbon, 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

        There were no matters submitted to a vote of security holders during the quarter ended December 31, 2003.

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PART II

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

        Our common stock trades on the American Stock Exchange national market under the symbol "MWP." As of December 31, 2003, there were 9,562,407 shares of common stock outstanding held by approximately 33 holders of record. The following table sets forth quarterly high and low sales prices as reported by the American Stock Exchange, as retroactively amended to give effect to the 2003 stock dividend (see below), for the periods indicated.

Dividend Policy

        On July 10, 2003, the Board of Directors declared a stock dividend of one share for each ten shares owned by stockholders of record as of the close of business on July 31, 2003. The stock dividend was paid on August 11, 2003, with an ex-dividend date of July 29, 2003.

        On January 22, 2004, the Board of Directors declared a one-time special cash dividend of $0.50 per share of common stock. The dividend was paid on February 18, 2004 to stockholders of record as of the close of business on February 4, 2004, with an ex-dividend date of February 2, 2004.

        Other than the stock dividend and one-time special dividend, we have never paid dividends on our common stock. Payment of dividends in the future will depend on our earnings, financial condition and contractual restrictions, including those under our bank line of credit or imposed by law and other factors deemed relevant by our Board of Directors, if any.

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ITEM 6.    SELECTED FINANCIAL DATA

        The following table sets forth selected consolidated historical financial and operating data for MarkWest Hydrocarbon. Certain prior year amounts have been reclassified to conform to the 2003 presentation. The selected consolidated statement of operations and balance sheet data for the years ended December 31, 2003, 2002 and 2001, and as of December 31, 2003 and 2002, are derived from, and are qualified by reference to, our audited Consolidated Financial Statements included elsewhere in this Form 10-K. The selected consolidated statement of operations and balance sheet data set forth below for the years ended December 31, 2000 and 1999, and as of December 31, 2001, 2000 and 1999, have been derived from audited financial statements not included in this Form 10-K. You should read this in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of

28

Operations" and our Consolidated Financial Statements and accompanying Notes included elsewhere in this Form 10-K, which are incorporated herein by reference.

(1)

Represents MarkWest Hydrocarbon until May 23, 2002, and MarkWest Energy Partners from May 24, 2002—the date its initial public offering closed.

(2)

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

(3)

Prior to May 24, 2002, this represents NGL product production at the Siloam fractionator.

(4)

Includes volumes since March 28, 2003, the date the Partnership's Pinnacle acquisition was completed. Also, includes the Partnership's Lubbock Pipeline volumes. The Partnership acquired the Lubbock Pipeline on September 2, 2003.

(5)

Represents sales at the Siloam fractionator.

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

        The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three years ended December 31, 2003, 2002 and 2001. Certain prior year amounts have been reclassified to conform to the presentation used in 2003. In conjunction with the following discussion and analysis, you should also read our Consolidated Financial Statements and related Notes thereto and the "Selected Financial Data" included elsewhere in this Form 10-K, which are incorporated herein by reference.

Recent Developments

        During the year ended December 31, 2003, we completed several important initiatives that accomplished the transformation of MarkWest Hydrocarbon into a company focused on increasing shareholder value through our ownership in MarkWest Energy Partners. Specifically, we discontinued our exploration and production business and significantly grew MarkWest Energy Partners, primarily through the acquisition of third-party midstream assets.

MarkWest Hydrocarbon Dispositions

        Our three primary dispositions were the following:

•

We sold our San Juan Basin oil and gas producing properties in two separate sales during the second and third quarters of 2003. The San Juan Basin properties represented substantially all of our exploration and production business located in the United States. Net proceeds from the sales were approximately $55.3 million. We recognized a net pretax gain on the sales of approximately $23.3 million.



•

We sold our entire Canadian exploration and production business in two separate transactions during December 2003. Net proceeds from the sales were approximately $49.1 million. We recognized a net pretax loss on the sales of approximately $4.8 million.



•

We sold two of our three NGL terminals during the third quarter of 2003. Net proceeds were approximately $2.3 million. We recognized a net pretax loss on the sales of less than $0.1 million.

MarkWest Energy Partners Acquisitions

        Pinnacle Merger.    On March 28, 2003, we completed the acquisition of Pinnacle Natural Gas Company, or Pinnacle. The aggregate purchase price of $39.9 million was comprised of $23.4 million in cash plus the assumption of $16.6 million of bank indebtedness. The assets are primarily located in Texas and include three lateral natural gas pipelines and twenty natural gas gathering systems. One of the gathering systems was subsequently disposed of in December 2003 for an immaterial amount. The three lateral natural gas pipelines consist of approximately 67 miles of pipeline that deliver natural gas under firm contracts to power plants. The nineteen natural gas gathering systems gathered an aggregate of approximately 44.3 MMcf/d of natural gas during the year ended December 31, 2003, and have a capacity of approximately 93.0 MMcf/d. This acquisition provided MarkWest Energy Partners with a new area for growth in the Southwest and diversified its lines of business and revenues. In addition, the acquisition is expected to increase the stability of the Partnership's cash flows because Pinnacle has a high percentage of fee-based lateral pipeline contracts.

        Lubbock Pipeline Acquisition.    Effective September 1, 2003, MarkWest Energy Partners completed the acquisition of an intrastate gas transmission pipeline and related assets near Lubbock, Texas, from Power-Tex Joint Venture, a subsidiary of ConocoPhillips, for $12.2 million in cash. This gas pipeline is the only connection between the Northern Natural Gas and El Paso interstate pipelines and the City of

30

Lubbock. Its customers include the City of Lubbock, Texas Tech University, Xcel Energy and several other end-use consumers. This acquisition allowed the Partnership to further expand its operations in the Southwest with an additional lateral system while providing an added source of fee-based cash flows.

        Western Oklahoma Acquisition.    On December 1, 2003, MarkWest Energy Partners completed the acquisition of substantially all of the assets of American Central Western Oklahoma Gas Company, LLC for approximately $38.0 million in cash. These assets include 167 miles of natural gas gathering pipeline, known as the Foss Lake gathering system, and the associated Arapaho gas processing plant in western Oklahoma. The Foss Lake gathering system, which has a current capacity of 65.0 MMcf/d, connects to approximately 270 wells. The Arapaho gas processing plant has a current capacity of 75.0 MMcf/d. Capacity on the gathering system can be expanded to 75.0 MMcf/d with additional compression. By establishing a presence in Oklahoma, this acquisition significantly expanded the Partnership's Southwest operations.

        Michigan Crude Pipeline Acquisition.    On December 18, 2003, the Partnership completed the acquisition of approximately 250 miles of intrastate crude oil gathering pipeline, for $21.3 million in cash. The pipeline serves over 1,000 oil and gas wells on the Niagaran Reef Trend and has 487,000 barrels of storage capacity in 15 storage tanks. This acquisition further diversifies the Partnership's lines of business with the addition of crude oil gathering and transportation services. The acquisition also provides the Partnership with the opportunity to leverage off its existing infrastructure and personnel in Michigan while adding additional fee-based cash flows.

Initial and Secondary Public Offerings of MarkWest Energy Partners, L.P.

Initial Public Offering

        On May 24, 2002, MarkWest Hydrocarbon contributed most of the assets, liabilities and operations of our midstream business to MarkWest Energy Partners, L.P. in exchange for 3,000,000 subordinated units, a 2% general partner interest in the Partnership, incentive distribution rights (as defined in the Partnership Agreement), and $63.5 million in cash (which was used to pay down bank debt). The Partnership closed its initial public offering on that date selling 2,415,000 common units (including the underwriters' exercise of their over-allotment option) for gross proceeds of $49 million and net proceeds (after fees and expenses) of $43 million. Concurrent with its initial public offering the Partnership borrowed $21.4 million. MarkWest Energy Partners' limited partnership structure reduces its cost of capital thereby enhancing its ability to grow more efficiently.

Secondary Public Offering

        On January 12, 2004, the Partnership priced its offering of 1,148,000 common units at $39.90 per unit. Of the 1,148,000 common units, 1,100,444 were sold by the Partnership for gross proceeds of $43.9 million. The remaining 47,556 were sold by certain selling unitholders, proceeds of which have been retained by them, and not the Partnership.

        By the terms of the over-allotment provisions of the underwriting agreement, the Partnership granted underwriters a 30-day option to purchase up to 172,200 additional common units. In connection therewith, the Partnership issued an additional 72,500 common units for gross proceeds of $2.9 million during the first quarter of 2004.

        Gross proceeds of $46.8 million were reduced by underwriters' fees of $2.5 million and professional fees and other offering costs of $1.0 million, resulting in net proceeds of $43.3 million. The net proceeds were used to pay down the Partnership's credit facility.

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        As of February 29, 2004, MarkWest Hydrocarbon's partnership interests consisted of the following:

•

2,469,496 subordinated units, representing a 34.6% limited partner interest in the Partnership; and a



•

90.2% ownership interest in the general partner of the Partnership. The general partner owns a 2% general partner interest in the Partnership.

        MarkWest Hydrocarbon's consolidated financial statements reflect the consolidation of MarkWest Energy Partners, with the public unitholders' interest being reflected as a minority interest in the consolidated statement of operations and the consolidated balance sheet.

Results of Operations

Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002

        Revenues.    Revenues were $207.7 million for the year ended December 31, 2003, compared to $154.3 million for the year ended December 31, 2002, an increase of $53.3 million, or 35%. The increase was primarily due to MarkWest Energy Partners' acquisitions, which added approximately $54.8 million. Increases in our weighted average NGL product sales prices in Appalachia were generally offset by decreases in our Appalachian NGL and gas marketing sales volumes. Included in our 2003 revenues were approximately $18.8 million in hedging losses, primarily from crude oil hedges, an increase of approximately $11.2 million over the prior year.

        Purchased product costs.    Purchased product costs were $187.5 million for the year ended December 31, 2003, compared to $127.5 million for the year ended December 31, 2002, an increase of $60.0 million, or 47%. Purchased product costs increased in 2003 primarily due to:

•

MarkWest Energy Partners' acquisitions added approximately $44.8 million.



•

An increase in the weighted average price of our Appalachian replacement natural gas from our keep-whole and percent-of-proceeds contract based business increased purchased product costs $32.6 million.



•

A decrease in the level of gas marketing activity offset the above increases by approximately $19.3 million.

        Facility expenses.    Facility expenses were $20.0 million for the year ended December 31, 2003, compared to $16.3 million for the year ended December 31, 2002, an increase of $3.7 million, or 23%. Facility expenses increased primarily due to MarkWest Energy Partners' 2003 acquisitions.

        Selling, general and administrative expenses. Selling, general and administrative expenses were $14.5 million for the year ended December 31, 2003, compared to $9.4 million for the year ended December 31, 2002, an increase of $5.0 million, or 54%. The increase is principally attributable to MarkWest Energy Partners' 2003 acquisitions; the incremental, public company costs from MarkWest Energy Partners first full year of operations in 2003; and compensation expense related to phantom units granted to our employees.

        Depreciation.    Depreciation was $8.3 million for the year ended December 31, 2003, compared to $5.7 million for the year ended December 31, 2002, an increase of $2.6 million, or 46%. The increase was principally due to MarkWest Energy Partners' 2003 acquisitions.

        Impairment.    MarkWest Energy Partners recorded an impairment of $1.1 million related to its Cobb processing facility. The facility is slated to be replaced in mid-2004, at which time the current facility will be retired. The Cobb facility was written down to its estimated recoverable value. No impairment was recorded during the year ended December 31, 2002.

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        Interest expense, net.    Interest expense was $5.9 million for the year ended December 31, 2003, compared to $3.8 million for the year ended December 31, 2002, an increase of $2.2 million, or 57%. The increase was primarily attributable to borrowings by MarkWest Energy Partners to finance its 2003 acquisitions.

        Write-down of deferred financing costs.    Write-down of deferred financing costs was $0.4 million for the year ended December 31, 2003, compared to $3.0 million for the year ended December 31, 2002, a decrease of $2.6 million, or 86%. The 2003 write-down eliminated the remaining deferred financing costs associated with the MarkWest Hydrocarbon credit facility that was terminated in December 2003.

        Income from discontinued operations.    Income from discontinued operations was $11.0 million for the year ended December 31, 2003, compared to $1.9 million for the year ended December 31, 2002, an increase of $9.1 million, or 473%. The increase is primarily attributable to the net gain on sales of our oil and gas properties during 2003.

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

        Revenue.    Revenue was $154.3 million for the year ended December 31, 2002 compared to $173.9 million for the year ended December 31, 2001, a decrease of $19.6 million, or 11%. Revenue was lower in 2002 than in 2001 primarily due to:

•

A decrease in the average NGL product sales price from our keep-whole contract, or "frac spread", business, net of volume increases, which accounted for approximately $3.6 million of the overall decrease. The average NGL sales price was $0.43 per gallon for the year ended December 31, 2002, compared to $0.55 per gallon for the year ended December 31, 2001, a decrease of $0.12 per gallon, or 22%.



•

We recognized a $2.4 million hedging ineffectiveness charge in 2002.



•

A decrease in gas marketing revenues, which accounted for approximately $6.2 million of the decrease. Gas marketing revenues declined in 2002 as natural gas prices retreated from above average levels that existed in 2001, more than offsetting volume increases.



•

A net $5.4 million decrease from our Michigan operations, primarily a function of the sales of an unusual amount of NGL products in the first quarter of 2001.

        Purchased gas costs.    Purchased gas costs were $127.5 million for the year ended December 31, 2002, compared to $140.2 million for the year ended December 31, 2001, a decrease of $12.7 million, or 9%. Purchased gas costs were lower in 2001 primarily due to:

•

A decrease in our gas marketing cost of goods sold, which accounted for $8.2 million of the overall decrease. Gas marketing costs declined in 2002 as natural gas prices retreated from above average levels that existed in 2001, more than offsetting volume increases.



•

A net $5.6 million decrease from our Michigan operations, primarily a function of the sales of an unusual amount of NGL products in the first quarter of 2001.

        Facility expenses.    Facility expenses were $16.3 million for the year ended December 31, 2002, compared to $16.5 million for the year ended December 31, 2001, a decrease of $0.3 million, or 2%.

        Selling, general and administrative expenses. Selling, general and administrative expenses were $9.4 million for the year ended December 31, 2002, compared to $7.5 million for the year ended December 31, 2001, an increase of $1.9 million, or 26%. The increase primarily stems from the incremental, public company costs from our consolidated subsidiary, MarkWest Energy Partners, which closed its IPO on May 24, 2002.

33

        Depreciation.    Depreciation was $5.7 million for the year ended December 31, 2002, compared to $5.2 million, for the year ended December 31, 2001, an increase of $0.5 million, or 11%.

        Interest expense, net.    Net interest expense was $3.8 million for the year ended December 31, 2002, compared to $3.7 million for the year ended December 31, 2001, an increase of $0.1 million, or 2%.

        Income from discontinued operations.    Income from discontinued operations was $1.9 million for the year ended December 31, 2002, compared to $2.5 million for the year ended December 31, 2001, a decrease of $0.6 million, or 23%. The decrease was primarily a result of increased depletion expense during 2002.

        Write-down of deferred financing costs.    We wrote off $3.0 million in deferred financing costs as a result of the May 24, 2002 amendment of our credit facility—which was completed concurrently with the IPO of our consolidated subsidiary, MarkWest Energy Partners—and an earlier amendment.

        Gain on sale of non-operating assets.    During November 2002, we sold 500,000 of our subordinated units of MarkWest Energy Partners to a third party.

Seasonality

        A portion of our revenue and, as a result, our gross margin, is dependent upon the sales prices of natural gas and NGL products, particularly propane, and the purchase price of natural gas 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, we historically recognize a substantial portion of our annual income during the first and fourth quarters of the year.

Liquidity and Capital Resources

MarkWest Hydrocarbon

        During 2003, we discontinued our exploration and production activities and sold all of our related Canadian oil and gas properties and substantially all of our U.S. oil and gas properties. The sales netted us $106.7 million in cash. The proceeds were primarily used to pay off and terminate our existing credit facility in its entirety in December 2003. We also had $33.4 million in unrestricted cash on hand at December 31, 2003, exclusive of MarkWest Energy Partners' cash on hand. As a result, our outstanding debt, exclusive of MarkWest Energy Partners' debt, was $0 as of December 31, 2003. In February 2004, we disbursed approximately $4.8 million to pay a special one-time dividend of $0.50 per share to our common shareholders.

        Going forward, we expect MarkWest Hydrocarbon's primary sources of liquidity to be quarterly distributions received from MarkWest Energy Partners and cash flows generated from operations, principally the marketing of natural gas and NGLs.

        We own 90.2% of the general partner of MarkWest Energy Partners. The general partner of MarkWest Energy Partners owns the 2% general partner interest and all of the incentive distribution rights. The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.55 for that quarter, 23.0% of all cash distributed after each unit has received $0.625 for that quarter and 48.0% of all cash distributed after each unit has received $0.75 for that quarter. For the year ended December 31, 2003, we received $5.7 million in distributions for our subordinated units, and the general partner received $0.4 million, including $0.2 million representing payments on incentive distribution rights. As the Partnership continues to grow and increase its quarterly distributions per limited partner unit, we expect our distributions to increase accordingly.

34

        Cash flows generated from our marketing operations are subject to volatility in energy prices, especially prices for NGLs and natural gas. Our cash flows are enhanced in periods when the prices received for NGLs are high relative to the price of natural gas we purchase to satisfy our "keep-whole" contractual arrangements in Appalachia, and are reduced in periods when the prices received for NGLs are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under "keep-whole" contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or "keep whole" the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. Periodically, when natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer "whole" can result in operating losses. For the year ended December 31, 2003, our loss from continuing operations before income taxes was $33.1 million. The loss from operations was primarily caused by the combination of an unfavorable pricing environment (primarily in the first half of 2003) and unfavorable crude oil hedges (throughout 2003). However, prices improved during the latter half of 2003 and remained at or above historical levels into the first quarter of 2004. Additionally, we exited certain unfavorable crude oil hedges in late 2003. We, however, cannot predict with any certainty what the pricing environment will be in the future.

        We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners, and cash generated from our marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the foreseeable future. Most of our future capital expenditures are discretionary and minimal in nature. During 2004, we have budgeted $1.7 million for our contribution to the Cobb plant replacement and an additional $0.3 million for other miscellaneous projects. Cash generated from our marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

        In an effort to increase our liquidity, we may seek to establish a bank credit facility and renegotiate certain keep-whole contracts in order to reduce our commodity price risk.

MarkWest Energy Partners

        For the Partnership, future acquisitions or projects are expected to be financed through a combination of debt and issuance of additional units, as is common practice with master limited partnerships.

        As of December 31, 2003, the Partnership had borrowed $126.2 million of the $140 million available under its credit facility. The Partnership paid down its debt by $42 million in January 2004 with the proceeds from its secondary offering.

Cash Flows

        Net cash used in operations during 2003 resulted primarily from losses from operations. Net cash provided by operations increased during 2002 relative to 2001 primarily because 2002 represented the first full year of our Canadian operations.

35

        Net cash flows used in investing activities increased during 2003 relative to 2002 principally due to cash paid for the Partnership's 2003 acquisitions (net of proceeds from 2003 dispositions). Net cash used in investing activities decreased in 2002 relative to 2001 due to cash paid for our 2001 Canadian acquisitions.

        Net cash provided by financing activities during 2003 was primarily a result of borrowing by the Partnership to fund its acquisitions. Net cash used in financing activities in 2002 was primarily the result of using the proceeds from the Partnership's initial public offering to pay down debt. Net cash provided by financing activities in 2001 was principally due to borrowings used to finance our two Canadian acquisitions.

Total Contractual Cash Obligations

        A summary of our total contractual cash obligations as of December 31, 2003, is as follows:

Credit Facility

        You should read Note 9 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference, for information on our financing facilities.

Related Parties

        You should read Note 16 of the accompanying Notes to consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference, for information regarding related parties.

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 policies are discussed below. You should also read Note 2 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference.

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 our long-lived assets (excluding the full cost pool), 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

36

may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. 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 re-determined 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.



•

The availability and prices of crude oil.



•

Our ability to negotiate favorable marketing agreements.



•

The risks that third party oil and 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.



•

Competition from other midstream service providers, 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.

Commodity Price Risk Management Activities

        We account for price risk management activities based upon the fair value accounting methods prescribed by SFAS No. 133, Accounting for Derivative Instruments. Risk management activities include utilizing various hedging contracts and other derivatives to reduce volatility in our cash flow. SFAS No. 133 requires that we determine the fair value of the instruments we use in these business activities and reflect them in our balance sheet at their fair values. However, changes in the fair value of our cash flow hedges are generally recognized in our income statement when the hedge is settled.

        The determination of fair value for our hedging derivatives requires substantial judgment. The fair values of our derivatives are based upon certain estimations and internal valuation techniques. These estimations use various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, correlation of the hedged items to the hedging instruments and basis (location) differences. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by market volatility and changes.

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Recent Accounting Pronouncements

        In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, as amended. This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. In general, SFAS No. 149 was effective for the Company on a prospective basis for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after that date. The adoption of SFAS No. 149 had no impact on our results of operations, financial position or cash flows.

        In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS No. 150 requires that certain financial instruments previously classified as equity be classified as liabilities or, in some cases, as assets. The adoption of SFAS No. 150 had no impact on our results of operations, financial position or cash flows.

        In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, which it revised in December 2003 (collectively, FIN 46). FIN 46 requires the consolidation of certain variable interest entities, as defined. FIN 46 is effective for the Company as of December 31, 2003, as it relates to special-purpose entities, as defined, and in the first quarter 2004 for all other types of variable interest entities. 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 did not have an impact on our 2003 financial statements and is not expected to have an impact on our 2004 results of operations, financial position or cash flows.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price variations and also incur, to a lesser extent, credit risks and risks related to interest rate variations.

Commodity Price Risk

        Through our consolidated subsidiary, MarkWest Energy Partners, L.P., we are engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of NGLs and the gathering and transportation of crude oil. We also market natural gas and NGL products. Our products are commodities that are subject to price risk resulting from material changes in response to fluctuations in supply and demand, general economic conditions and other market conditions, such as weather patterns, over which we have no control.

        Our primary risk management objective is to reduce 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, oversees all of our hedging activity.

        We utilize a combination of fixed-price forward contracts, fixed-for-float price swaps and options on the 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 financial institutions and other energy company counterparties. We use standardized swap agreements that allow for the offset of positive and negative exposures. Net credit exposure is marked to market daily. We are subject to margin deposit requirements under OTC agreements and NYMEX positions.

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        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 natural gas, 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.

        In addition to these risk management tools, we utilize our NGL product storage facilities and contracts for third-party storage to build product inventories during lower-demand periods for resale during higher-demand periods.

Types of Price Risk

        Within our NGL marketing segment, our price risk varies by contract as well as by spot market prices for both NGL and natural gas commodities. Our Appalachian producers compensate us for providing midstream services under one of two contract types:

•

Under "keep-whole" contracts, we take title to and sell the NGLs produced in our processing operations. We also reimburse or "keep whole" the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Keep-whole contracts therefore expose us to NGL product price risk (on the sales side) and natural gas price risk (on the purchase or reimbursement side).



•

Under "percent-of-proceeds" contracts, we take title to the NGLs produced in our processing operations, sell the NGLs to third parties and pay the producer a specified percentage of the proceeds received from the sales. Percent-of-proceeds contracts therefore expose us to NGL product price risk. All of our Michigan processing business is also governed by percent-of-proceeds contracts.

Basis Risk

        We are also subject to basis risk, which 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. Basis risk is primarily due to geographic price differentials between our physical sales locations and the hedging contract delivery location. While we are able to hedge our basis risk for natural gas commodity transactions in the readily available natural gas financial marketplace, similar markets do not exist for hedging basis risk on NGL products. 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 hedge our NGL product sales by selling forward propane or crude oil.

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Commodity Risk Management Position

        As of December 31, 2003, we have hedged NGLs and natural gas 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.

        As of December 31, 2003, we are not a party to any basis risk hedges.

Credit Risk

        Counterparties, pursuant to the terms of their contractual obligations, expose us to potential losses as a result of nonperformance. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. Such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements where deemed necessary, and the use of standardized agreements, which facilitate the netting of cash flows associated with a single counterparty. We also monitor the financial condition of existing counterparties on an ongoing basis. In general, our risk of default by these counterparties is low. However, we experienced a loss in 2001 as described below.

        SFAS No. 133 provides that hedge accounting must be discontinued on contracts when it becomes reasonably possible that the counterparty will default. During the fourth quarter of 2001, Enron Corporation and its subsidiaries (Enron) filed for bankruptcy protection. In response to this filing, we terminated all derivative contracts where Enron was the counterparty. As a result, in 2001 we wrote off $1.1 million of risk management assets related to our cash flow hedges offset by $0.1 million of risk management liabilities related to our fair value hedges. In addition, our contracts with Enron provided for netting of amounts owed to each other and as such we netted $0.6 million in amounts payable to Enron. The net result of the above transactions was a charge of $0.4 million to earnings in the fourth quarter of 2001. In the case of discontinued hedge accounting for cash flow hedges, SFAS No. 133 provides the amount in other comprehensive income will be reclassified to earnings in the periods of the forecasted transactions. As such, we reclassified $0.2 and $0.8 million from other comprehensive income to revenue, net of $0.1 million and $0.3 million of deferred taxes for 2003 and 2002, respectively.

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        While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future.

Interest Rate Risk

        Through our consolidated subsidiary, MarkWest Energy Partners, L.P., we are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. MarkWest Energy Partners may make use of interest rate swap agreements during the term of the Partnership's Credit Facility that matures on November 30, 2006, to adjust the ratio of fixed and floating rates in the debt portfolio. As of December 31, 2003, the Partnership is a party to contracts to fix interest rates on $8.0 million of debt at 3.85% through May 2005, compared to floating LIBOR, plus an applicable margin.

Sensitivities

        Our annual sensitivities to changes in commodity prices considering our hedge position are as follows:

MarkWest Hydrocarbon, Inc.

•

for every $0.10 per MMBtu increase in the natural gas price, our gross margin would decrease by $1.0 million; and



•

for every $0.01 per gallon reduction in NGL prices, our gross margin would decrease by $1.7 million.

MarkWest Energy Partners, L.P.

•

for every $0.10 per MMBtu increase in the natural gas price, the Partnership's gross margin, exclusive of the Arapaho processing plant, would increase by $0.3 million, and



•

for every $0.02 per gallon reduction in NGL prices, exclusive of the Arapaho processing plant, the Partnership's gross margin would decrease by $0.1 million.

        The Partnership's Arapaho plant processing margins are sensitive to commodity price changes. Because of the nature of the contracts associated with the plant, gross margin increases as the price of NGLs increases relative to natural gas and gross margin decreases as the price of natural gas increases relative to the price of NGLs. In the latter case, however, the Partnership has the option of not operating the plant in a low processing margin environment since the Btu content of the inlet natural gas meets the Btu specification of the interstate line into which the natural gas is delivered. A $0.01 per Mcf change in the processing margin results in a $0.2 million change in gross margin.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

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REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc.

        In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of cash flows and of changes in stockholders' equity present fairly, in all material respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware corporation, and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company'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.

        As discussed in Note 2 to the consolidated financial statements, MarkWest Hydrocarbon, Inc. changed its method of accounting for inventory effective January 1, 2002. As discussed in Note 13 to the consolidated financial statements, MarkWest Hydrocarbon, Inc. changed its method of accounting for derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standards No. 133 on January 1, 2001. As discussed in Note 8 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143 on January 1, 2002.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
March 30, 2004

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MARKWEST HYDROCARBON, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

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

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MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)