UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ý	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2003.

o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to .

Commission File Number 1-11566

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

155 Inverness Drive West, Suite 200, Englewood, CO 80112-5000

(Address of principal executive offices)

Registrant’s telephone number, including area code: 303-290-8700

Securities registered pursuant to Section 12(b) of the Act: Common Units, $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 ý No o

The aggregate market value of Common Units held by non-affiliates of the registrant on June 30, 2003, was approximately $84,356,000.

As of March 4, 2004, the number of the registrant’s Common Units and Subordinated Units were 3,997,502 and 3,000,000, respectively.

DOCUMENTS INCORPORATED BY REFERENCE

None.

MarkWest Energy Partners, L.P.
Form 10-K

Table of Contents

PART I
Items 1. and 2.	Business and Properties
Item 3.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders

PART II
Item 5.	Market for the Registrant’s Common Units and Related Unitholder Matters
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.	Controls and Procedures

PART III
Item 10.	Directors and Executive Officers of the Registrant
Item 11.	Executive Compensation
Item 12.	Security Ownership of Certain Beneficial Owners and Management
Item 13.	Certain Relationships and Related Transactions

PART IV
Item 14.	Principal Accounting Fees and Services
Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K

SIGNATURES

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

Glossary of Terms

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

Bbls	barrels
Btu	one British thermal unit, an energy measurement
Gal/d	gallons per day
Mcf	one thousand cubic feet of natural gas
Mcf/d	one thousand cubic feet of natural gas per day
Mcfe/d	one thousand cubic feet of natural gas equivalent per day ⁽¹⁾
MMBtu	one million British thermal units, an energy measurement
MMcf	one million cubic feet of natural gas
Bcf	one billion cubic feet of natural gas
NGLs	natural gas liquids, such as propane, butanes and natural gasoline
NA	not applicable

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

Forward-Looking Statements

Statements included in this annual report on Form 10-K that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as “may,” “believe,” “estimate,” “expect,” “plan,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements.

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

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

•	The availability of raw natural gas supply for our gathering and processing services;
•	The availability of NGLs for our transportation, fractionation and storage services;
•	Our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas, including MarkWest Hydrocarbon;
•	The risks that third-party oil and gas exploration and production activities will not occur or be successful;
•	Prices of NGL products and crude oil, including the effectiveness of any hedging activities, and indirectly by natural gas prices;
•	Competition from other NGL processors, including major energy companies;
•	Changes in general economic conditions in regions in which our products are located; and
•	Our ability to identify and consummate grass roots projects or acquisitions complementary to our business.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. The Partnership does not update publicly any forward-looking statement whether as a result of new information or future events. Investors are cautioned not to put undue reliance on forward-looking statements. You should read “Risk Factors” included in Item 7 of this Form 10-K for further information, which is incorporated herein by reference.

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

MarkWest Energy Partners, L.P., is a publicly traded Delaware limited partnership. We were formed on January 25, 2002, but did not conduct operations until the May 24, 2002 closing date of our initial public offering (the IPO). We are engaged in the gathering, processing and transmission of natural gas and the transportation, fractionation and storage of natural gas liquids (NGLs) and the gathering and transportation of crude oil. We are the largest processor of natural gas in the northeastern United States, processing gas from the Appalachian Basin, one of the country’s oldest natural gas producing regions, and from Michigan. Through three acquisitions completed during 2003, the Partnership has expanded its natural gas gathering, processing and transmission geographic coverage to the southwest United States. A fourth acquisition has resulted in the Partnership’s entry into the Michigan crude oil transportation business.

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

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

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

Discussions of our business and properties include time periods in which MarkWest Hydrocarbon held our assets. MarkWest Hydrocarbon controls our operations through its ownership of our general partner. Additionally, MarkWest Hydrocarbon has a significant limited partner ownership interest in us through its ownership of a majority of our subordinated units. As of December 31, 2003, MarkWest Hydrocarbon and its affiliates, in the aggregate, owned a 43.8% interest in the Partnership, consisting of 2,479,762 subordinated limited partner units, which represents a 41.8% interest in the Partnership, and the entire general partner interest, which represents a 2.0% interest in the Partnership. MarkWest Hydrocarbon also is our largest customer, accounting for 42% of our revenues and 59% of our gross margin for the year ended December 31, 2003. Our reliance on MarkWest Hydrocarbon has diminished and will continue to diminish as a result of the four recent aforementioned acquisitions. Further details on our relationship with MarkWest Hydrocarbon are discussed below.

Overview

We are a rapidly growing, independent midstream energy company engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of NGLs and the gathering and transportation of crude oil. A substantial portion of our revenues and cash flows are generated from providing fee-based services to our customers, which provides us with a relatively stable base of cash flows. We have three primary geographic areas of operation:

•	Appalachia. We are the largest processor of natural gas in the Appalachian basin, one of the country’s oldest natural gas producing regions. Our 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. We own an aggregate of 302 miles of natural gas gathering pipelines in 19 gathering systems in Texas, Oklahoma, Louisiana, Mississippi and New Mexico. We also own 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. We own a 90-mile gas gathering pipeline and one natural gas processing plant in Michigan. We also own 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.

In these three areas we provide midstream services to our customers under four types of contracts. For the year ended December 31, 2003, we generated approximately 29% of our revenues and 74% of our gross margin (revenues less purchased products costs) from contracts under which we charge fees for providing midstream services. Gross margin from these fee-based services is dependent on throughput volume and is typically less affected by short-term changes in commodity prices. The remainder of our gross margin is generated pursuant to percent-of-index, percent-of-proceeds and keep-whole contracts and is more affected by changes in commodity prices. Under percent-of-index contracts we purchase natural gas at a percentage discount to a specified index price and then deliver the natural gas to pipelines where we resell the natural gas at the index price or at a different percentage discount to the index price. Under percent-of-proceeds arrangements, we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to the producers equal to the value of this natural gas.

We have grown rapidly through acquisitions and construction and expansion of our assets. Since our initial public offering in May 2002, we have completed four acquisitions with an aggregate purchase price of approximately $110 million. We initially financed these acquisitions primarily through borrowings under our credit facility, which has been expanded to $140 million.

At the closing of our initial public offering, all of our assets and operations were concentrated in the Appalachian region and Michigan, and our operations consisted solely of the gathering, processing and transmission of natural gas and the transportation, fractionation and storage of NGLs. Our operations historically have been largely dependent on MarkWest Hydrocarbon, which accounted for approximately 42% of our revenue and 59% of our gross margin for the year ended December 31, 2003. As a result of our four recent acquisitions, we now have operations in nine states and have expanded our operations into the gathering, processing and transmission of natural gas in the Southwest and the gathering and transportation of crude oil in Michigan. These acquisitions have reduced our dependence on MarkWest Hydrocarbon. We raised approximately $9.7 million, net of transaction costs, through the sale of 375,000 common units in a private placement to certain accredited investors. The sale was completed in two installments ending July 10, 2003. We also raised $43.3 million, net of transaction costs, through a secondary offering concluded January 2004. In each event, the proceeds raised were primarily used to pay down debt.

Competitive Strengths

Our competitive strengths include:

•	Strategic Position in the Appalachian basin and Michigan.

	•	We are the largest processor of natural gas in Appalachia and we believe our significant presence and asset base there provides us with a competitive advantage in capturing new supplies of natural gas. The Appalachian basin is a large natural gas producing region characterized by long-lived reserves, modest decline rates and natural gas with high NGL content providing our operations with

		a stable supply of natural gas for our processing plants and our Siloam NGL fractionation plant. In addition, the Appalachian basin is characterized by consistently high levels of drilling activity, which supplies us with significant opportunities to access new supplies of natural gas and NGLs. The concentration and integration of our Appalachian operations and the efficiencies of our facilities create operational synergies that allow us to provide cost-effective service to our customers. For example, we are able to transport a majority of the NGLs we extract at our processing plants to our Siloam fractionator via our pipeline, lowering our transportation costs. Our concentrated infrastructure and available land and storage assets in Appalachia provide us with a platform for additional cost-effective expansion.

	•	Our recent acquisition of the Michigan Crude Pipeline allowed us to enter into the crude oil transportation business and significantly expand our presence in Michigan. In addition to our natural gas gathering and processing operations, we are now the primary intrastate pipeline transporter of crude oil in Michigan. This gives us a competitive advantage over other higher cost crude oil transport methods, such as trucking. The Niagaran Reef Trend, from which the majority of our natural gas and crude oil in the state is produced, is generally characterized by long-lived natural gas and crude oil reserves.

•	Growing Presence in the Southwest. Our recent Pinnacle, Lubbock pipeline and western Oklahoma acquisitions have allowed us to expand our presence in long-lived natural gas basins in the Southwest, particularly in Texas and Oklahoma. The Pinnacle gathering systems and the western Oklahoma assets are strategically located in the East Texas and Permian basins and the Anadarko basin in Oklahoma. Each of these areas is undergoing significant development and exploration activities and provides us with an opportunity to capture additional supplies of natural gas. The lateral natural gas pipelines acquired in the Pinnacle acquisition and the Lubbock pipeline acquisition allowed us to establish natural gas transmission operations in central and west Texas. We believe we can use our proven expertise in asset acquisitions to develop and expand our presence in the Southwest.

•	Proven Acquisition Expertise. Since our initial public offering in May 2002, we have completed four acquisitions with an aggregate purchase price of approximately $110 million. We intend to continue to use our experience in acquiring assets to grow through accretive acquisitions with focus on opportunities in which we can improve volumes and cash flow.

•	Stable Cash Flows. For the year ended December 31, 2003, we generated approximately 29% of our revenues and 74% of our gross margin from fee-based contracts providing natural gas gathering, processing and transmission services, NGL transportation, fractionation and storage services and crude oil gathering and transportation services. These fee-based services are dependent on throughput volume but are typically not affected by short-term changes in commodity prices. In addition, our four lateral pipelines in the Southwest typically generate firm transportation fees independent of the volumes transported. We believe that the fee-based nature of a significant component of our business and the long-term nature of many of our contracts provide us with a relatively stable base of cash flows.

•	Long-term Contracts. Pursuant to our contracts with MarkWest Hydrocarbon and Equitable Production Company (Equitable; a subsidiary of Equitable Resources, Inc.), we process substantially all of the natural gas delivered into two of the three largest gathering systems in Appalachia and fractionate the NGLs extracted from such gas. These contracts have remaining terms ranging in length from six to 13 years. In Michigan, our gas transportation, treating and processing agreements have terms for the life of the wells. In conjunction with our Pinnacle assets, we have two significant, fixed-fee contracts for the transmission of natural gas that expire in 19 and 29 years. Our two largest customer contracts related to the Lubbock pipeline run through 2005 and 2008. Approximately 90% of our daily throughput in the Foss Lake gathering system in western Oklahoma is pursuant to contracts with remaining terms of five years or more.

•	Experienced management with operational and engineering expertise. Each member of our executive management team has at least 19 years of experience in the energy industry and our facility managers have extensive experience operating our facilities. Our technical and operational expertise has enabled us to upgrade existing facilities, as well as design and build new facilities. In addition, the ownership of interests in our general partner and in our partnership by members of our management, as well as our compensation and incentive plans, closely aligns the interests of our management team with the interests of our common unitholders.

•	Financial flexibility. During January 2004, we raised $43.3 million, net of transaction costs, through a secondary offering of 1.17 million units at a price of $39.90 per unit. The proceeds from the offering were used to pay down long-term debt. Upon completion of the January 2004 secondary public offering, we have available borrowing capacity of approximately $56 million under our $140 million credit facility. This facility, together with our ability to issue additional partnership units for financing and acquisition purposes, should provide us with a flexible financial structure that will facilitate the execution of our business strategy.

Business Strategies

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

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

•	Expanding operations through new construction. By leveraging our existing infrastructure and customer relationships, we intend to continue expanding our asset base in our primary areas of operation to meet the anticipated need for additional midstream services. In the first half of 2004, we began constructing a new, more efficient processing plant to replace our Cobb processing plant. In the Southwest, drilling in our two largest gathering systems, Appleby in east Texas and Foss Lake in western Oklahoma, has significantly increased volumes over the past several years.

•	Expanding operations through acquisitions. We intend to continue to pursue strategic acquisitions of assets and businesses in our existing areas of operation in order to leverage our current asset base, personnel and customer relationships. Our acquisition of the Michigan Crude Pipeline allows us to leverage off of our existing Michigan infrastructure and personnel. In addition, we seek to acquire assets outside of our existing areas of operation with a view towards creating new operating areas. Our Pinnacle, Lubbock pipeline and western Oklahoma acquisitions enabled us to establish and develop a new primary area of operation in the Southwest.

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

Our Relationship with MarkWest Hydrocarbon, Inc.

We were formed by MarkWest Hydrocarbon to acquire most of its natural gas gathering and processing and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon remains our largest customer and, for the year ended December 31, 2003, accounted for 42% of our revenues and 59% of our gross margin. We will derive a significant portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future. After the completion of our January 2004 secondary public offering, MarkWest Hydrocarbon and its affiliates own 35.4% of our limited partner interests and continues to direct our business operations through their

ownership and control of our general partner. MarkWest Hydrocarbon employees are responsible for conducting our business and operating our assets on our behalf.

During 2003, MarkWest Hydrocarbon sold substantially all of its oil and gas properties. MarkWest Hydrocarbon’s remaining business consists of its limited partnership interest in us, its ownership of a controlling interest in our general partner and the marketing of NGLs and natural gas. In 2003, MarkWest Hydrocarbon sold 177 million gallons of NGL products produced at our Siloam facility. NGL products are shipped from Siloam by truck, rail and barge. In addition, MarkWest Hydrocarbon transports propane from our Siloam facility, as well as propane purchased from third parties, to its wholesale propane terminals and to third party facilities for sale to customers. MarkWest Hydrocarbon’s 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 a best efforts basis and are priced in reference to Mt. Belvieu index prices or plant posting prices. In addition to its NGL product sales, MarkWest Hydrocarbon’s marketing operations are also responsible for the purchase of natural gas delivered for the account of producers pursuant to its keep-whole processing contracts.

Overview of our Business and Industry

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

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

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

Natural Gas Processing

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

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

NGL Fractionation

After being separated from natural gas at the processing plant, the mixed NGL stream is typically transported to a centralized facility for fractionation. Crude oil and condensate production also contain varying amounts of NGLs, which are removed during the refining process and, in the case of propane, are either marketed directly out of the refinery or, in the case of butanes, blended by refiners or delivered to NGL fractionation facilities for further processing.

Fractionation is the process by which NGLs are further separated into individual, more valuable components. Fractionation systems typically exist either as an integral part of a gas processing plant, or as a “central

fractionator,” often located many miles from the primary production and processing facility. A central fractionator may receive mixed streams of NGLs from many processing plants.

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

The composition of throughput at our Siloam fractionators is as follows:

Ethane		Propane		Normal Butane		Isobutane		Natural Gasoline		Total
0%		64%		18%		6%		12%		100%

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

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

•	Propane—Propane is used for heating fuel, engine fuel, industrial fuel and for agricultural burning and drying and as a petrochemical feedstock for production of ethylene and propylene. Propane is principally used as a fuel in our operating area.

•	Normal butane—Normal butane is principally used for gasoline blending, as a fuel gas, either alone or in a mixture with propane, and as a feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber.

•	Isobutane—Isobutane is principally used by refiners to enhance the octane content of motor gasoline and in the production of MTBE, an additive in cleaner burning motor gasoline.

•	Natural gasoline—Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock.

Our Assets

The following is a summary of the percentage of revenue and gross margin by geographical function for the year ended December 31, 2003:

	Appalachia Gas Processing		Appalachia NGL Transportation, Fractionation and Storage Services		Southwest Gas Gathering, Processing and Transportation		Michigan Gas Gathering and Processing		Total
Revenue	35	%	8	%	47	%	10	%	100	%
Gross margin	41	%	21	%	21	%	17	%	100	%

Given our four acquisitions during 2003, the above percentages are likely to change in the future.

Our Appalachian Assets

Appalachian Gathering and Processing Facilities

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

				Year Ended December 31, 2003
Facility	Location	Year Constructed	Design Throughput Capacity (Mcf/d)	Natural Gas Throughput (Mcf/d)	Utilization of Design Capacity
Kenova Processing Plant (1)	Wayne County, WV	1996	160,000	133,000	83	%
Boldman Processing Plant (1)	Pike County, KY	1991	70,000	46,000	66	%
Maytown Processing Plant	Floyd County, KY	2000	55,000	51,000	93	%
Cobb Processing Plant (2)	Kanawha County, WV	1968	35,000	24,000	69	%
Kermit Processing Plant (3)	Mingo County, WV	2001	32,000	NA	NA

(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, we began construction of a new 24 MMcf/d processing plant. This new plant will replace our existing Cobb plant.
(3)	The Kermit processing plant is operated by Columbia Gas and we do not receive inlet volume information.

Kenova Processing Plant. Our 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 our Siloam fractionator via our pipeline.

Boldman Processing Plant. Our 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. Prior to 2000, MarkWest Hydrocarbon leased the plant to Columbia Gas. This facility receives all of its 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 our Maytown facility and transported on our leased pipeline to Ranger for further delivery on our pipeline to our Siloam fractionator.

Maytown Processing Plant. Pursuant to contract, Equitable operates our Maytown facility, a straight refrigeration plant, on our behalf. As operator, Equitable is responsible for the day-to-day operation of the Maytown plant. Under our Gas Processing Agreement with Equitable, we have 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 all of its intake of raw natural gas from Equitable’s gathering system in Kentucky. NGLs extracted at this facility are transported to Siloam via pipeline. The plant also contains a truck unloading facility that allows for the delivery of NGLs into our pipeline system for transportation to our Siloam fractionator.

Under the terms of our Gas Processing Agreement, Equitable agrees to deliver to us all gas now or subsequently produced from specified wells, plus gas attributable to the interests of third parties that is currently being delivered into Equitable’s gathering system (to the extent Equitable has the right to process such third party gas). Equitable also grants us the exclusive right to process all of this natural gas and conveys to us title to the extracted NGLs.

As compensation for our services, we earn both a fee for our transportation and fractionation services as well as receive a percentage of the proceeds from the sale of NGLs produced on Equitable’s behalf. A portion of the transportation and fractionation fee will be subject to annual adjustment in proportion to the annual average percentage change in the Producer Price Index for Oil and Gas Field Services. MarkWest Hydrocarbon, in a separate agreement, has agreed to buy the NGLs from us and pay us a purchase price equal to the proceeds it receives from the resale of such NGLs to third parties. Please see “Certain Relationships and Related Transactions” included in Item 13 of this Form 10-K, which is incorporated herein by reference. The initial term of our Gas Processing Agreement with Equitable runs through February 2015. The

operating revenues we earn under the percent-of-proceeds component of this agreement will fluctuate with the sales price for the NGLs produced.

Cobb Processing Plant. Our Cobb facility, a refrigerated lean oil processing plant, was acquired in 2000. The refrigerated lean oil process utilizes a propane refrigeration system to cool the gas and the lean oil. The chilled lean oil then absorbs the NGLs which are then separated from the lean oil by distillation. An upgrade of this facility was completed in 2000 to decrease downtime and increase recoveries from the facility. This facility receives all of its 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 our Siloam facility by tanker truck. During the first half of 2004, we are replacing our existing Cobb facility with a newly constructed 24 MMcf/d processing plant. We believe this new plant will require significantly less operating and maintenance expense. The cost of the construction is expected to be approximately $2.1 million. MarkWest Hydrocarbon will provide approximately $1.7 million in payment of a portion of the costs. We will pay the remaining approximately $0.4 million and own and operate the plant.

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

We do not operate our 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 us 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, we, at our own expense, must remove the plant from Columbia Gas’ property within a reasonable time following the expiration of the lease.

We generate most of our processing revenues in Appalachia by charging fees for processing gas. We completed a multi-year expansion of our Appalachian infrastructure in mid-2001, increasing our total natural gas designed processing capacity by 127 MMcf/d.

Appalachian NGL Pipelines

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

Our Appalachia liquids pipeline includes the following segments:

				Year Ended December 31, 2003
Pipeline	Location	Year Constructed	Design Throughput Capacity (gal/day)	NGL Throughput (gal/day)	Utilization of Design Capacity
Maytown to Institute (1)	Floyd County, KY to Kanawha County, WV	1956	250,000	154,000	62	%
Ranger to Kenova (2)	Lincoln County, WV to Wayne County, WV	1976	831,000	154,000	19	%
Kenova to Siloam	Wayne County, WV to South Shore, KY	1957	831,000	409,000	49	%

(1)	Includes 40 miles of currently unused pipeline extending from Ranger to Institute.
(2)	NGLs transported through the Ranger to Kenova pipeline are included in the Kenova to Siloam volumes.

Our 40-mile Ranger to Kenova NGL pipeline and the Maytown to Ranger segment of our leased Maytown to Institute pipeline, together with our existing Kenova to Siloam pipeline, form 136 miles of NGL pipeline running through the southern portion of the Appalachia basin. We acquired our Ranger to Kenova pipeline and leased the 100-mile Maytown to Institute pipeline in 2000 as part of our Appalachian expansion. We acquired our Kenova to Siloam pipeline in 1988. We lease the Maytown to Institute pipeline from Equitable. 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. We generate transportation revenues by charging fees for transporting NGLs to our Siloam fractionator on our pipeline.

Appalachian Fractionation Facility

Our Siloam fractionation plant receives substantially all of its NGLs via pipeline or tanker truck from our five Appalachia processing plants, with the balance received from tanker truck and rail car deliveries from other third-party NGL sources. The NGLs are then separated into NGL products, including propane, isobutane, normal butane and natural gasoline. The typical composition of the NGL throughput in our Appalachian operations has been approximately 64% propane, 18% normal butane, 6% isobutane, and 12% natural gasoline. We do not currently produce or sell any ethane. Our Siloam fractionation plant has been continually upgraded and maintained since its acquisition by MarkWest Hydrocarbon in 1988. We generate revenues by charging fees for fractionating NGLs that we receive from our processing plants and third parties.

The following table provides additional detail regarding our Siloam fractionation plant:

				Year Ended December 31, 2003
Facility	Location	Year Constructed	Design Throughput Capacity (Mcf/d)	Natural Gas Throughput (Mcf/d)	Utilization of Design Capacity
Siloam Fractionation Plant	South Shore, KY	1957	600,000	458,000	76	%

Appalachian Storage Facilities

In Appalachia, our Siloam facility has both above ground, pressurized storage facilities, with capacity of three million gallons, and underground storage facilities, with capacity of 11 million gallons. Product can be received by truck, pipeline or rail car and can be transported from the facility by truck, rail car or barge. There are eight automated 24-hour-a-day truck loading and unloading slots, a modern rail loading/unloading rack with 12 unloading slots, and a river barge facility capable of loading barges with a capacity of up to 840,000 gallons. We generate revenues from our underground storage facilities by charging a fee based on gallons of storage contracted.

Our Southwest Assets

Southwest Gathering and Processing Facilities

The table below describes our Southwest gathering and processing assets:

				Year Ended December 31, 2003
Facility	Location	Year of Initial Construction	Design Throughput Capacity (Mcf/d)	Natural Gas Throughput (Mcf/d)(3)	Utilization of Design Capacity		NGL Throughput (gal/day)
Foss Lake Gathering System(1)	Roger Mills and Custer County, OK	1998	65,000	52,100	80	%	NA
Appleby Gathering System(2)	Nacogdoches County, TX	1990	40,000	23,800	60	%	NA
18 Other Gathering Systems(2)	Various in TX, LA, MS, NM	Various	53,000	20,500	39	%	NA

Arapaho Processing Plant(1)	Custer County, OK	2000	75,000	51,500	69	%	82,500

(1)	We acquired the Foss Lake Gathering System and Arapaho Processing Plant on December 1, 2003.
(2)	We acquired the Appleby Gathering System, along with 18 other gathering systems, as part of our 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 we owned each facility.

Foss Lake Gathering System. We acquired the Foss Lake Gathering System as part of the 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. We generate operating margins by charging fixed fees per Mcf of natural gas gathered. All of the natural gas gathered into the system is dehydrated at our Butler compression station for delivery to our Arapaho processing plant.

Appleby Gathering System. We acquired the Appleby Gathering System as part of the 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 the Travis Peak Basin in east Texas from approximately seven producers, with one producer accounting for approximately 50% of the volumes. We sell the gas to marketing companies and to an industrial user under short-term marketing contracts. We generate a majority of our 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, we acquired 19 other natural gas gathering systems, primarily located in Texas. The systems typically gather natural gas from mature producing wells. We generate operating margins from these systems through percent-of-index, percent-of-proceeds and fixed-fee contracts.

Arapaho Processing Plant. We acquired the Arapaho Processing Plant, located in Custer County, Oklahoma, as part of the western Oklahoma acquisition in December 2003. Our 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. We generate operating margins through keep-whole contracts. Under these keep-whole arrangements, we process the natural gas and sell the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers, or make a cash payment to the producers. Accordingly, under these arrangements our revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. In the latter case, however, we have 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 our 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, our exposure is limited to a portion of the operating costs of the plant.

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

•	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. We have 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. We have 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. We have a fixed-fee contract as operator of the pipeline through September 2005. However, our fixed-fee revenue reduces as of April 2004, at which time ownership of the lateral will transfer to Borger Energy Associates.

We 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. We have 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.

Our Michigan Assets

Michigan Gathering and Processing Facilities

The table below describes our Michigan gathering and processing assets:

				Year Ended December 31, 2003
Facility	Location	Year of Initial Construction	Design Throughput Capacity (Mcf/d)	Natural Gas Throughput (Mcf/d)	Utilization of Design Capacity		NGL Throughput (gal/day)
90-mile Gas Gathering Pipeline	Manistee, Mason and Oceana Counties, MI	1994 -1998	35,000	15,000	43	%	NA
Fisk Processing Plant	Manistee County, MI	1998	35,000	15,000	43	%	32,200

(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.

Our Michigan gathering pipeline gathers and transports sour gas produced by third parties in Oceana, Mason and Manistee Counties for sulfur removal at a treatment plant that is owned and operated by Merit Energy Company (Merit). Our Fisk processing plant is located adjacent to Merit’s treatment plant. Our gathering pipeline serves approximately 30

wells and 13 producers in this three county area. The Fisk plant processes all of the natural gas gathered by our pipeline and produces propane and a butane-natural gasoline mix. We process natural gas under a number of third-party agreements containing both fee and percent-of-proceeds components. Under these agreements, production from all of the acreage adjacent to our pipeline and processing facility is dedicated to our gathering and processing facilities. Under the fee component of these agreements, which represent approximately half of our gross margin in Michigan, producers pay us a fee to transport and treat their gas. Under the percent-of-proceeds component, we retain a portion of the proceeds from the sale of the NGLs as compensation for the processing services provided.

We receive 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that we gather and process in Michigan. MarkWest Hydrocarbon retains a 70% net profits interest in the gathering and processing income we earn on quarterly pipeline throughput in excess of 10 MMcf/d.

Under a Gas Treating and Processing Agreement between our subsidiary, West Shore Processing Company, LLC and Merit, Merit operates our Fisk natural gas processing plant. Under the terms of this agreement, Merit treats and processes sour gas delivered to its treatment plant by us and delivers the treated gas to our Fisk plant where NGLs are extracted. We retain the NGLs. Merit retains any treated products (including carbon dioxide) and any liquids recovered prior to treating the gas at its treatment plant by use of conventional mechanical separation equipment, as well as any sulfur recovered. For these services, we pay 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 in proportion to the change in a government reported index. In addition, Merit has agreed to pay us a per-gallon surcharge for propanes, butanes and pentanes (or a combination thereof) contained in the treated gas that is not subsequently delivered to us for processing at our natural gas processing plant.

We generate revenues from our Michigan natural gas and NGL operations primarily by charging a fee for the gathering and processing services we provide. Our contracts in Michigan also provide that we retain a portion of the proceeds from the sale of NGLs that are produced at our Michigan facility. Our propane and butane-natural gasoline production is usually sold at the plant.

Michigan Crude Pipeline

We 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 customer. We generate operating margins by charging a tariff per barrel of crude oil transported. Because we have the ability to set the amount of this tariff, we believe this pipeline will provide us 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.

Customers and Contracts

Appalachia

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

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

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

The operating revenues we earn under the percent-of-proceeds component of the Gas Processing Agreement will fluctuate with the sales price for the NGLs produced.

Michigan

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

We receive 100% of all fee and percent-of-proceeds consideration for the first 10,000 Mcf/d that we gather and process in Michigan. MarkWest Hydrocarbon retains a 70% net profits interest in the gathering and processing income we earn on quarterly pipeline throughput in excess of 10,000 Mcf/d. Throughput is expected to remain between 10,000 to 15,000 Mcf/d in 2004.

Our Contracts with MarkWest Hydrocarbon

The following is a summary of the percentage of our revenue and gross margin under various contracts with MarkWest Hydrocarbon for the year ended December 31, 2003.

	Gas Processing Agreement		Pipeline Liquids Transportation Agreement, Fractionation, Storage and Loading Agreement		NGL Purchase Agreement		Total
Revenue	12	%	8	%	22	%	42	%
Gross margin	31	%	21	%	7	%	59	%

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

•

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

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

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

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

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

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

•	An Omnibus Agreement pursuant to which:

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

	•	MarkWest Hydrocarbon agreed to indemnify us for a period of three years for losses due to environmental matters arising prior to our IPO, as well as for pre-existing litigation.

•	A Services Agreement pursuant to which:

	•	MarkWest Hydrocarbon agreed to act in a management capacity rendering day-to-day operational, business and asset management, accounting, personnel and related administrative services to the Partnership.

	•	The Partnership is obligated to reimburse MarkWest Hydrocarbon for all documented expenses incurred on behalf of the Partnership and which are expressly designated as reasonably necessary for the performance of the prescribed duties and specified functions.

You should read “Agreements with MarkWest Hydrocarbon” included in Item 13 of this Form 10-K for a more complete description of the contracts we have entered into with MarkWest Hydrocarbon, which is incorporated herein by reference.

Competition

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

In competing for new business opportunities, we face strong competition in acquiring natural gas and crude oil supplies and in competing for service fees. Our 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 our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.

Title to Properties

Substantially all of our 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. We have 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 our pipelines were built was purchased in fee. Our Siloam fractionation plant and Kenova processing plant are on land that we own in fee.

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

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

The Partnership has pledged substantially all of its assets to secure our credit facility as discussed in Note 7 of the accompanying Notes to Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference.

Regulatory Matters

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

Some of our 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 we operate are subject to rate and service regulation. The applicable state statutes generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services. Regulatory authorities in the states in which we operate 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.

Our Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, who has entered into agreements with us providing for a fixed transportation charge for the term of the agreements, which expire on December 31, 2015. We are the only other shipper on the pipeline. As we do not operate our Appalachian pipeline as a common carrier and do not hold the pipeline out for service to the public generally, there are currently no third-party shippers on this pipeline and the pipeline is and will continue to be operated as a proprietary facility. Similarly, our 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, we 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 our Appalachian pipeline or the transportation charge during the term of our agreements with MarkWest Hydrocarbon and, moreover, the likelihood of other entities seeking to utilize our Appalachian pipeline is limited, the likelihood of such a challenge on our Appalachian pipeline is remote. Similarly, because we are operating our Michigan Crude Pipeline in the same manner as it was historically operated by Shell for a significant period of time prior to our acquisition and because our operations are entirely within the state of Michigan, we believe that the likelihood of a challenge to the status of this pipeline is remote. However, we 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 our results of operations.

Some of our liquids and crude oil gathering facilities deliver into pipelines that have the ability to make redeliveries in both interstate and intrastate commerce. The rates we charge on our 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

General. Our 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 our overall cost of doing business, including our cost of constructing, maintaining and upgrading equipment and facilities. Our failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of investigatory or remedial requirements, and, in less common circumstances, issuance of injunctions. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial condition.

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

Hazardous Substance and Waste. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous wastes, and may require investigatory and corrective actions of facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of “hazardous substance” into the environment. These persons include the owner or operator of a site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency, or EPA, and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we will generate wastes that may fall within the definition of a “hazardous substance.” We may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA.

We also generate both hazardous and 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. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or plant operating expenses.

We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering and processing, 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 us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we had no control as to such entities’ handling of hydrocarbons or other wastes and the manner in which such substances may have been disposed of or released. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future

contamination. We do not believe that there presently exists significant surface and subsurface contamination of our properties by hydrocarbons or other solid wastes for which we are currently responsible.

Ongoing Remediation and Indemnification from Columbia Gas. Columbia Gas is the previous or current owner of the property on which our Kenova, Boldman, Cobb and Kermit facilities are located and is the previous operator of our Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying 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 us the benefit of its indemnity from Columbia Gas with respect to the Cobb, Boldman and Kermit facilities. While we are not a party to the agreement under which Columbia Gas agreed to indemnify MarkWest Hydrocarbon with respect to the Kermit facility, MarkWest Hydrocarbon has agreed to provide us 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, we do not believe that the remediation of these properties by Columbia Gas pursuant to the EPA Administrative Order or the Kentucky Agreed Order will have a material adverse impact on our financial condition or results of operations. MarkWest Hydrocarbon has also agreed to provide us an additional environmental indemnification pursuant to the terms of the Omnibus Agreement. See “Certain Relationships and Related Transactions.”

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

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

Safety Regulation. Our pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the HLPSA will not have a material adverse effect on our results of operations or financial position.

The Pipeline Safety Improvement Act of 2002 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.

Employee Safety

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

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

Employees

We do not have any employees. To carry out our operations, our general partner or its affiliates employ approximately 128 individuals who operate our facilities and provide general and administrative services as our agents. The Paper, Allied Industrial, Chemical and Energy Workers International Union Local 5-372 represents fourteen employees at our Siloam fractionation facility in South Shore, Kentucky. The collective bargaining agreement with this Union expires on June 28, 2004. The agreement covers only hourly, non-supervisory employees. We consider labor relations to be satisfactory at this time.

Litigation

We have been, and may continue to be, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other legal proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.

Available Information

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

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

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

No matter was submitted to a vote of the holders of our common units during the fourth quarter of the fiscal year ended December 31, 2003.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS AND RELATED UNITHOLDER MATTERS

Our common units have been listed on the American Stock Exchange (AMEX) under the symbol “MWE” since May 24, 2002. Prior to May 24, 2002, our equity securities were not listed on any exchange or traded on any public trading market. The following table sets forth the high and low sales prices of the common units, as reported by AMEX, as well as the amount of cash distributions paid per quarter for 2003 and 2002 since the close of the IPO on May 24, 2002.

Quarter Ended	High	Low	Per Common Unit		Per Subordinated Unit		Record Date	Payment Date
March 31, 2003	$26.00	$22.95	$0.58		$0.58		May 5, 2003	May 15, 2003
June 30, 2003	$32.50	$25.30	$0.58		$0.58		August 4, 2003	August 14, 2003
September 30, 2003	$35.98	$29.55	$0.64		$0.64		November 4, 2003	November 14, 2003
December 31, 2003	$40.90	$34.05	$0.67		$0.67		January 31, 2004	February 13, 2004

June 30, 2002 (1)	$21.90	$20.50	$0.21	(1)	$0.21	(1)	August 13, 2002	August 15, 2002
September 30, 2002	$22.64	$17.90	$0.50		$0.50		October 31, 2002	November 14, 2002
December 31, 2002	$23.50	$20.80	$0.52		$0.52		January 31, 2003	February 14, 2003

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

As of February 29, 2004, there were approximately 133 holders of record of our common units.

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

Distributions of Available Cash

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

Distributions of Available Cash During the Subordination Period

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

•	First, 98% to the common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters.
•	Second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters.
•	Third, 98% to all units, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.55 per quarter.

•	Thereafter, in the manner described in “—Incentive Distribution Rights” below.

Distributions of Available Cash After the Subordination Period

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

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

Incentive Distribution Rights

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

	If for any quarter:

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

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

•	First, 98% to all unitholders, pro rata, and 2% to our general partner until each unit receives a total of $0.55 per unit for that quarter (the “first target distribution”);
•	Second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.625 per unit for that quarter (the “second target distribution”);
•	Third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.75 per unit for that quarter (the “third target distribution”); and
•	Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

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

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

ITEM 6. SELECTED FINANCIAL DATA

On May 24, 2002, the Partnership completed its initial public offering whereby the Partnership became the successor to the business of the MarkWest Hydrocarbon Midstream Business (Midstream Business). The selected financial information for the Partnership was derived from the audited consolidated and combined financial statements as of and for the years ended December 31, 2003 and 2002. The selected historical financial statements of the Midstream Business as of and for the years ended December 31, 2001, 2000, and 1999 are derived from the audited financial statements of the Midstream Business. The selected financial data should be read in conjunction with the combined and consolidated financial statements, including the notes thereto, and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which are herein incorporated by reference.

	Partnership						MarkWest Hydrocarbon Midstream Business
	Year Ended December 31,
	2003			2002			2001			2000			1999
	(in thousands)
Statement of Operations:
Revenues	$	117,537		$	70,246		$	93,675		$	109,810		$	57,490
Operating expenses:
Purchased product costs	70,832			38,906			65,483			71,341			33,549
Facility expenses	20,463			15,101			13,138			13,224			10,514
Selling, general and administrative expenses	7,686			5,283			5,047			4,733			3,971
Depreciation	7,548			4,980			4,490			4,341			3,413
Impairment	1,148			—			—			—			—
Total operating expenses	107,677			64,270			88,158			93,639			51,447
Income from operations	9,860			5,976			5,517			16,171			6,043
Interest expense, net	(4,057		)	(1,414		)	(1,307		)	(1,697		)	(1,741		)
Miscellaneous income (expense)	(25		)	52			—			—			—
Income before income taxes	5,778			4,614			4,210			14,474			4,302
Provision (benefit) for income taxes	—			(17,175		)	1,624			5,693			1,631
Net income	$	5,778		$	21,789		$	2,586		$	8,781		$	2,671
Net income per limited partner unit:
Basic	$	0.96		$	4.86		$	0.86		$	2.93		$	0.89
Diluted	$	0.96		$	4.83		$	0.86		$	2.93		$	0.89
Cash distributions declared per limited partner unit	$	2.47		$	1.23		NA			NA			NA

Balance Sheet Data (at period end):
Working capital	$	2,564		$	1,762		$	18,240		$	6,047		$	4,083
Property, plant and equipment, net	184,214			79,824			82,008			77,501			69,695
Total assets	212,978			87,709			104,891			95,520			80,776
Total debt, including debt due to parent	126,200			21,400			19,179			20,782			17,956
Capital/partnership equity	65,051			60,863			65,429			50,751			46,646

Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	21,229		$	33,502		$	(524	)	$	13,997		$	6,776
Investing activities	(112,893		)	(2,056		)	(8,997		)	(12,147		)	(10,544		)
Financing activities	97,641			(28,670		)	9,521			(1,850		)	3,768

Other Financial Data:
Sustaining capital expenditures	$	1,041		$	511		$	576		$	955		$	489
Expansion capital expenditures	1,903			1,634			9,075			11,192			10,055
Total capital expenditures	$	2,944		$	2,145		$	9,651		$	12,147		$	10,544

	Partnership		MarkWest Hydrocarbon Midstream Business
	Year Ended December 31,
	2003	2002	2001	2000	1999
	(in thousands)
Operating Data:
Appalachia
Natural gas processed (Mcf/d) (1)	202,000	202,000	192,000	196,000	171,000
NGL fractionated (gallons/day)	458,000	476,000	423,000	406,000	310,000
NGL product sales (gallons)	40,305,000	99,235,000	—	—	—
Southwest:
Gathering systems throughput (Mcf/d) (2)	55,000	—	—	—	—
Michigan:
Pipeline throughput (Mcf/d)	15,000	13,800	8,800	11,000	17,800
NGL product sales (gallons)	11,800,000	11,100,000	8,000,000	9,200,000	13,500,000

(1) Represents throughput from our Kenova, Cobb and Boldman processing plants.

(2) Includes volumes since March 28, 2003, the date our Pinnacle acquisition was completed. Also, includes our Lubbock Pipeline volumes; the Lubbock Pipeline was acquired September 2, 2003.

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

Overview

We are a Delaware limited partnership formed by MarkWest Hydrocarbon on January 25, 2002 to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon Midstream Business. Since our initial public offering in May of 2002, we have significantly expanded our operations through a series of acquisitions. We are engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of NGL products and the gathering and transportation of crude oil.

To better understand our business and the results of operations discussed below, it is important to have an understanding of two factors:

• the nature of the contracts from which we derive our revenues; and

• the difficulty in comparing our results of operations across periods, both because of our significant and recent acquisition activity, as well as the restructuring of our business in connection with our initial public offering in May 2002.

Our Contracts

For the year ended December 31, 2003, we generated the following percentages of our revenue and gross margin from the following types of contracts:

	Fee-Based		Percent-of-Proceeds		Percent-of-Index		Keep-Whole		Total
Revenue	29	%	28	%	36	%	7	%	100	%
Gross Margin	74	%	15	%	10	%	1	%	100	%

Given the four acquisitions during the year ended December 31, 2003, the above percentages are likely to change.

We generate the majority of our revenues from natural gas gathering, processing and transmission, NGL transportation, fractionation and storage, and crude oil gathering and transportation. While all of these services constitute midstream energy operations, we provide our services pursuant to four different types of contracts.

• Fee-based contracts. Under fee-based contracts, we receive a fee or fees for one or more of the following services: gathering, processing, and transmission of natural gas, transportation, fractionation and storage of NGLs, and gathering and transportation of crude oil. The revenue we earn from these contracts is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, our contracts provide for minimum annual payments. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these contracts would be reduced.

• Percent-of-proceeds contracts. Under percent-of-proceeds contracts, we generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGLs at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGLs to the producer and sell the volumes we keep to third parties at market prices. Under these types of contracts, our revenues and gross margins increase as natural gas prices and NGL prices increase, and our revenues and gross margins decrease as natural gas prices and NGL prices decrease.

• Percent-of-index contracts. Under percent-of-index contracts, we generally purchase natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. We then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price, or at a different percentage discount to the index price. With respect to (1) and (3) above, the gross margins we realize under the arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price. Conversely, our gross margins increase during periods of high natural gas prices.

• Keep-whole contracts. Under keep-whole contracts, we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to the producers equal to the value of this natural gas. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs.

In our current areas of operations, we have a combination of contract types and limited keep-whole arrangements. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common and other market factors. Any change in mix will impact our financial results.

Items Impacting Comparability of Financial Results

In reading the discussion of our historical results of operations, you should be aware of the impact of both our significant and recent acquisitions, as well as the restructuring we completed in connection with our initial public offering in May 2002. Together, these items fundamentally impact the comparability of our results of operations over the periods discussed.

Our Recent Acquisitions

Since our initial public offering, we have completed four acquisitions for an aggregate purchase price of approximately $110 million. These four acquisitions include:

• the Pinnacle acquisition, which closed on March 28, 2003, for consideration of $38.5 million;

• the Lubbock pipeline acquisition, which closed September 2, 2003, for consideration of $12.2 million;

• the western Oklahoma acquisition, which closed December 1, 2003, for consideration of $38.0 million; and

• the Michigan Crude Pipeline acquisition, which closed December 18, 2003, for consideration of $21.3 million.

Three of these acquisitions closed in the second half of 2003. Accordingly, our historical results of operations for the year ended December 31, 2003 do not fully reflect the impact these acquisitions will have on our operations in future periods. The aggregate impact of each of these acquisitions will fundamentally change our future results of operations.

Contractual Restructuring in Connection with our IPO

Our financial statements reflect the MarkWest Hydrocarbon Midstream Business on a historical cost basis for the years ended December 31, 1999 through 2001. Our financial statements for the year ended December 31, 2002 reflect in part the results of the MarkWest Hydrocarbon Midstream Business on a historical cost basis for the period from January 1, 2002 through May 23, 2002 combined with our results for the period from May 24, 2002, the date of our initial public offering, through December 31, 2002. Our results prior to May 24, 2002 include charges from MarkWest Hydrocarbon for direct costs and allocations of indirect corporate overhead and the results of contracts in force at the time. The MarkWest Hydrocarbon Midstream Business predominantly consists of our Appalachian operations. Our results of operations after our initial public offering differ substantially, primarily as a result of the contracts we entered into in connection with our initial public offering. These differences are primarily driven by the way in which we generate revenues and the way in which the MarkWest Hydrocarbon Midstream Business generated revenues. Historically, the MarkWest Hydrocarbon Midstream Business generated its revenues pursuant to keep-whole and percent-of-proceeds contracts.

In connection with our initial public offering, we entered into contracts with MarkWest Hydrocarbon that replaced our keep-whole contracts with fee-based contracts. Entering into these contracts significantly impacted our financial statements before and after the date of our initial public offering. The largest of the differences between the financial statements of the MarkWest Hydrocarbon Midstream Business and our financial statements is in revenues and purchased product costs. Generally, revenues and purchased product costs in the MarkWest Hydrocarbon Midstream Business’s financial statements are higher because:

•		the MarkWest Hydrocarbon Midstream Business’s revenues included the aggregate sales price for all the NGL products produced in its operations; and

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

In contrast, after entering into the new contractual arrangements,


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

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

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

Under the services agreement, we reimburse MarkWest Hydrocarbon monthly for the general and administrative support provided to us in the prior month.

Results of Operations

Operating Data

	Year Ended December 31, 2003	Year Ended December 31, 2002
Appalachia:
Natural gas processed for a fee (Mcf/d)	202,000	202,000
NGLs fractionated for a fee (gallons/day)	458,000	476,000
NGL product sales (gallons)	40,305,000	99,235,000
Southwest:
Gathering systems throughput (Mcf/d)(1)	55,000	—
Michigan:
Gas volumes processed for a fee (Mcf/d)	15,000	13,800
NGL product sales (gallons)	11,800,000	11,100,000

(1) Includes volumes since March 28, 2003, the date our Pinnacle acquisition was completed. Also, includes our Lubbock Pipeline volumes; the Lubbock Pipeline was acquired September 2, 2003.

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

	Year Ended December 31						Change
	2003			2002			$			%

Revenues	$	117,537		$	70,246		$	47,291		67	%

Operating expenses:
Purchased product costs	70,832			38,906			31,926			82	%
Facility expenses	20,463			15,101			5,362			36	%
Selling, general and administrative	7,686			5,283			2,403			45	%
Depreciation	7,548			4,980			2,568			52	%
Impairment	1,148			—			1,148			NA
Total operating expenses	107,677			64,270			43,407			68	%
Income from operations	9,860			5,976			3,884			65	%

Other income and (expense):
Interest expense, net	(4,057		)	(1,414		)	(2,643		)	187	%
Miscellaneous income (expense)	(25		)	52			(77		)	NA
Income before income taxes	5,778			4,614			1,164			25	%

Provision (benefit) for income taxes	—			(17,175		)	17,175			NA

Net income	$	5,778		$	21,789		$	(16,011	)	(73	)%

Revenues. Our 2003 revenues were higher than our 2002 revenues primarily due to our 2003 acquisitions, which increased our revenues by $54.8 million, partially offset by the impact of the terms of the new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our May 2002 initial public offering.

Purchased Product Costs. Purchased product costs were higher in 2003 primarily due to our 2003 acquisitions, which increased our purchased product costs by $44.8 million, partially offset by the impact of the terms of the new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our May 2002 initial public offering.

Facility Expenses. Facility expenses increased during 2003 primarily due to our 2003 acquisitions, which added $3.2 million. Increased fuel expenses in Appalachia and increased throughput at our Michigan operations also increased facility expenses.

Selling, General and Administrative Expenses. SG&A expenses increased in 2003 principally due to increased non-cash, phantom unit compensation expense, a result of an increase in our common unit price and the number of units granted and vested during 2003, and the Partnership’s incremental costs associated with being a publicly traded company.

Depreciation. Depreciation expense increased during 2003 primarily due to our 2003 acquisitions.

Impairment. During the fourth quarter of 2003, our general partner’s board of directors approved a plan to replace our existing Cobb extraction facility with a new facility by the third quarter of 2004. Consequently, in accordance with SFAS No. 144, Accounting for the Impairment of Disposal of Long Lived Assets, we wrote down the carrying value of the current Cobb facility to its expected recoverable value.

Interest Expense. Interest expense increased during 2003 primarily due to an increase in our average outstanding debt. Most of our 2003 acquisitions were financed through additional borrowings under our credit facility.

Income Taxes. The Partnership has not been subject to income taxes since its inception on May 24, 2002, the date of conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership. The Midstream Business recorded a non-cash adjustment of $17.2 million to eliminate deferred income tax liabilities that existed at the date of conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership. Accordingly, the Midstream Business has recorded a benefit to the deferred tax provision for the year ended December 31, 2002, which increased net income by $17.2 million.

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

	Year Ended December 31,						Change
	2002			2001			$			%

Revenues	$	70,246		$	93,675		$	(23,429	)	(25	)%

Operating expense:
Purchased product costs	38,906			65,483			(26,577		)	(41	)%
Facility expenses	15,101			13,138			1,963			15	%
Selling, general and administrative	5,283			5,047			236			5	%
Depreciation	4,980			4,490			490			11	%
Total operating expenses	64,270			88,158			(23,888		)	(27	)%
Income from operations	5,976			5,517			459			8	%

Other income and (expenses):
Interest expense, net	(1,414		)	(1,307		)	(107		)	8	%
Miscellaneous income	52			—			52			NA
Income before income taxes	4,614			4,210			404			10	%

Provision (benefit) for income taxes	(17,175		)	1,624			(18,799		)	NA

Net income	$	21,789		$	2,586		$	19,203		743	%

Revenues. Our revenues were lower in 2002 than in 2001 primarily due to the terms of the new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of the IPO. On the percent-of-proceed contracts retained by the Partnership, average NGL product sales prices were lower in the 2002 period than in the

comparable 2001 period.

Purchased Product Costs. Our purchased product costs were lower in 2002 primarily due to the terms of new contracts entered into by MarkWest Hydrocarbon and us concurrent with the closing of our May 2002 initial public offering.

Facility Expenses. Our facility expenses increased in 2002 due to increased throughput in our Michigan facilities and the expansion of our Kenova processing plant.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses increased in 2002 principally due to the Partnership’s incremental costs associated with being a publicly traded company, as well as increased insurance costs.

Depreciation. Our depreciation expense increased in 2002 principally due to additional fixed assets placed into service during the second half of 2001.

Income Taxes. Income tax expense decreased because the Partnership has not been subject to income taxes since May 24, 2002, the date of conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership. The Midstream Business recorded a non-cash adjustment of $17.2 million to eliminate deferred income tax liabilities that existed at the date of conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership. Accordingly, the Midstream Business has recorded a benefit to the deferred tax provision for the year ended December 31, 2002, which increased net income by $17.2 million.

Seasonality

With respect to our percent-of-proceeds, percent-of-index and keep-whole contracts, which collectively accounted for approximately 71% of our revenues and 26% of our gross margin (revenue less purchased product costs) for the year ended December 31, 2003, we are dependent upon the sales prices of commodities, such as oil, natural gas and NGL products, which fluctuates with the winter weather conditions, and other supply and demand determinants.

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

Liquidity and Capital Resources

Cash generated from operations, borrowings under our credit facility and funds from private and public equity offerings are our primary sources of liquidity. We believe that funds from these sources should be sufficient to meet both our short-term working capital requirements and our long-term capital expenditures requirements. Relative to capitalization, the Partnership’s objective is to maintain parity between debt and equity.

During December 2003, financial institutions increased our maximum lending limit to $140.0 million and, at December 31, 2003, we had borrowed $126.2 million. Total partners’ capital at that date was $65.1 million, and resulted in a long-term debt-to-total capital ratio of 66%. During January 2004, proceeds raised from a secondary public offering, were used to pay down the credit facility. Immediately after we paid down our long-term debt with $42 million from our January 2004 secondary offering, our long-term debt-to-total capital ratio approximated 44%.

The Partnership has the ability to issue an unlimited number of units to fund immediately accretive acquisitions. During 2003, the Partnership consummated four acquisitions aggregating approximately $110 million that were immediately accretive and, accordingly, were partially funded by the aforementioned secondary public offering. For acquisitions that are not immediately accretive, the Partnership has the ability to issue up to 1,207,500 common units without unitholder approval.

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

Our primary customer is MarkWest Hydrocarbon, which accounted for 42% of our revenues for the year ended December 31, 2003. Consequently, matters affecting the business and financial condition of MarkWest Hydrocarbon—including its operations, management, customers, vendors, and the like—have the potential to impact, both positively and negatively, our liquidity.

Capital Requirements

The Partnership has budgeted $6.1 million for capital expenditures for the year ending December 31, 2004, exclusive of any acquisitions, consisting of $3.9 million for expansion capital and $2.2 million for sustaining capital. Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives.

Cash Flow

	Year Ended December 31,
	2003			2002
Net cash provided by operating activities	$	21,229		$	33,502
Net cash used in investing activities	(112,893		)	(2,056		)
Net cash provided by (used in) financing activities	97,641			(28,670		)

Net cash provided by operating activities was lower in 2003 than in 2002 by $12.3 million, primarily due to the impact of the terms of the new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our May 2002 initial public offering. Net cash used in investing activities was higher in 2003 than 2002 by $110.8 million because of our four 2003 acquisitions, which aggregated approximately $110 million. For the year ended December 31, 2002, the Partnership’s financing activities used $28.7 million. Those activities included $43.6 million from the IPO and $20.3 from issuance of bank debt, reduced by $88.7 million paid to MarkWest Hydrocarbon for capitalization of the Partnership and distributions to unitholders of $3.9 million.

For the year ended December 31, 2003, the Partnership’s financing activities provided $97.6 million. The Partnership issued $100.8 million of debt to finance its four acquisitions. Additional funds were provided by a private placement of common units for $9.5 million, and an infusion by MarkWest Hydrocarbon of $0.7 million to fund pre-construction activities at the Cobb Processing Plant. Funds provided by these activities were reduced by distributions to unitholders of $13.4 million.

Total Contractual Cash Obligations

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

	Payment Due by Period
Type of obligation	Total obligation		Due in 2004		Due in 2005-2006		Due in 2007-2008		Thereafter

Long-term debt	$	126,200	$	—	$	126,200	$	—	$	—
Operating leases	3,472		1,125		1,326		600		421
Total contractual cash obligations	$	129,672	$	1,125	$	127,526	$	600	$	421

Credit Facility

You should read Note 7 of the accompanying Notes to Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K for a description of our credit facility, which is incorporated herein by reference.

Related Parties

You should read “Agreements with MarkWest Hydrocarbon” included in Item 13 of this Form 10-K for a complete description of the related party transactions we have entered into with MarkWest Hydrocarbon, which is incorporated herein by reference.

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 applied 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 are critical. For further details on our accounting policies, you should read Note 2 of the accompanying Notes to Consolidated and Financial Statements included in Item 8 of this Form 10-K , 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 the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value determine the amount of the impairment recognized. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

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

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

• The availability and prices of NGL products and competing commodities;

• The availability and prices of raw natural gas supply;

• Our ability to negotiate favorable marketing agreements;

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

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

• Competition from other NGL processors, including major energy companies.

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

Recent Accounting Pronouncements

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. 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 Partnership 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 Partnership 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.

Risk Factors

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

ITEM 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

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 of our general partner, 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 conduct a standard credit review on counterparties and have agreements containing collateral requirements where deemed necessary. We use standardized swap agreements that allow for offset of positive and negative exposures. Net credit exposure is marked to market daily. We are subject to margin deposit requirements under OTC agreements and NYMEX positions.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of 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.

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.

As of December 31, 2003, we have hedged natural gas sales as follows:

	Year Ending December 31,
	2004		2005
Hedged Natural Gas Sales
Natural gas MMbtu	183,000		182,500
Natural gas sales price per MMbtu	$	4.57	$	4.26

Natural Gas Puts
Natural gas MMbtu	366,000		—
Natural gas sales price per MMbtu	$	4.00	$	NA

Total Hedged Natural Gas
Natural gas MMbtu	549,000		182,500
Natural gas sales price per MMbtu	$	4.19	$	4.26

Interest Rate

We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. We may make use of interest rate swap agreements, during the term of the Partnership 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, we are a party to contracts that fix interest rates on $8.0 million of our 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:

• for every $0.10 per MMBtu increase in the natural gas price, our gross margin, exclusive of our Arapaho processing plant, would decrease by $0.3 million; and

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

Our Arapaho plant processing margins are sensitive to commodity price changes. Because of the nature of the contracts associated with the plant, our gross margin increases as the price of NGLs increases relative to natural gas and our gross margin decreases as the price of natural gas increases relative to the price of NGLs. In the latter case, however, we have 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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated and Combined Financial Statements


Report of Independent Auditors

Consolidated Balance Sheets at December 31, 2003 and 2002

Consolidated and Combined Statements of Operations for each of the three years in the period ended December 31, 2003

Consolidated and Combined Statements of Comprehensive Income for each of the three years in the period ended December 31, 2003

Consolidated and Combined Statements of Cash Flows for each of the three years in the period ended December 31, 2003

Consolidated Statements of Changes in Capital for each of the three years in the period ended December 31, 2003

Notes to Consolidated and Combined Financial Statements

REPORT OF INDEPENDENT AUDITORS

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated and combined statements of operations, of comprehensive income, of cash flows and of changes in capital present fairly, in all material respects, the financial position of MarkWest Energy Partners, L.P., a Delaware partnership, and its subsidiaries (the Partnership) at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2003, and for the MarkWest Hydrocarbon Midstream Business results of operations, cash flows and changes in capital for the year ended December 31, 2001,in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s 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 10 to the consolidated financial statements, the MarkWest Hydrocarbon Midstream Business changed its method of accounting for derivative financial instruments in accordance with Statement of Financial Accounting Standards No. 133 on January 1, 2001.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
March 15, 2004

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
ASSETS	2003			2002
Current assets:
Cash and cash equivalents	$	8,753		$	2,776
Receivables, net	11,942			976
Receivables from affiliate	2,417			2,847
Inventories	353			130
Other assets	223			336
Total current assets	23,688			7,065

Property, plant and equipment	224,534			111,648
Less: Accumulated depreciation	(40,320		)	(31,824		)
Total property, plant and equipment, net	184,214			79,824

Other assets:
Deferred financing costs, net of amortization of $1,275 and $291, respectively	3,831			820
Deferred offering costs	995			—
Investment in and advances to equity investee	250			—
Total other assets	5,076			820
Total assets	$	212,978		$	87,709

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	14,064		$	1,199
Payables to affiliate	1,524			723
Accrued liabilities	5,163			2,880
Risk management liability	373			501
Total current liabilities	21,124			5,303

Long-term debt	126,200			21,400
Risk management liability	125			143
Other liabilities	478			—
Commitments and contingencies (Note 13)

Capital:
Partners’ capital	65,549			61,574
Accumulated other comprehensive loss	(498		)	(711		)
Total capital	65,051			60,863
Total liabilities and capital	$	212,978		$	87,709

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

	Year Ended December 31,
	2003			2002			2001 (MarkWest Hydrocarbon Midstream Business)
Revenues:
Sales to affiliates	$	49,850		$	26,093		$	—
Sales to unaffiliated parties	67,687			44,153			93,675
Total revenues	117,537			70,246			93,675

Operating expenses:
Purchased product costs	70,832			38,906			65,483
Facility expenses	20,463			15,101			13,138
Selling, general and administrative expenses	7,686			5,283			5,047
Depreciation	7,548			4,980			4,490
Impairment	1,148			—			—
Total operating expenses	107,677			64,270			88,158

Income from operations	9,860			5,976			5,517

Other income and (expense):
Interest expense, net	(4,057		)	(1,414		)	(1,307		)
Miscellaneous income (expense)	(25		)	52			—

Income before income taxes	5,778			4,614			4,210

Provision (benefit) for income taxes:
Current due from parent	—			(1,535		)	(1,468		)
Deferred	—			(15,640		)	3,092
Provision (benefit) for income taxes	—			(17,175		)	1,624
Net income	$	5,778		$	21,789		$	2,586

Interest in net income:
General partner	$	260		$	89		$	—
Limited partners	$	5,518		$	21,700		$	2,586

Net income per limited partner unit:
Basic	$	0.96		$	4.86		$	0.86
Diluted	$	0.96		$	4.83		$	0.86
Weighted average units outstanding:
Basic	5,722			4,469			3,000
Diluted	5,773			4,493			3,000

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Year Ended December 31,
	2003		2002			2001 (MarkWest Hydrocarbon Midstream Business)

Net income	$	5,778	$	21,789		$	2,586

Other comprehensive income (loss):
Cumulative effect of change in accounting principle, net of tax	—		—			1,328
Risk management activities (net of tax for periods prior to formation of partnership)	213		(1,679		)	(360		)
Total other comprehensive income (loss)	213		(1,679		)	968

Comprehensive income	$	5,991	$	20,110		$	3,554

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2003			2002			2001 (MarkWest Hydrocarbon Midstream Business)
Cash flows from operating activities:
Net income	$	5,778		$	21,789		$	2,586
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation	7,548			4,980			4,490
Impairment	1,148			—			—
Amortization of deferred financing costs included in interest expense	984			291			—
Deferred income taxes	—			(15,640		)	3,092
Phantom unit compensation expense	1,357			73			—
Equity in investee losses	81			—			—
Other	21			(366		)	48
Changes in operating assets and liabilities, net of working capital assumed:
(Increase) decrease in receivables	(1,576		)	(43		)	5,018
(Increase) decrease in inventories	(223		)	2,333			(726		)
(Increase) decrease in other assets	113			4,933			(7,952		)
Increase (decrease) in accounts payable and accrued liabilities	5,998			12,062			(7,080		)
Increase in long-term replacement natural gas payable	—			3,090			—

Net cash provided by (used in) operating activities	21,229			33,502			(524		)

Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	(38,526		)	—			—
Lubbock Pipeline acquisition	(12,235		)	—			—
Western Oklahoma acquisition	(37,951		)	—			—
Michigan Crude Pipeline acquisition	(21,283		)	—			—
Capital expenditures	(2,944		)	(2,145		)	(9,651		)
Proceeds from sale of assets	46			89			654

Net cash used in investing activities	(112,893		)	(2,056		)	(8,997		)

Continued on next page.
The accompanying notes are an integral part of these financial statements.

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2003				2002			2001 (MarkWest Hydrocarbon Midstream Business)
Cash flows from financing activities:
Payments for deferred offering costs	(389)				—			—
Proceeds from initial public offering, net	—				43,625			—
Proceeds from private placement, net	9,964				—			—
Capital contribution by MarkWest Hydrocarbon	695				—			—
Distribution to MarkWest Hydrocarbon	—				(63,476)			—
Distributions to unitholders	(13,434)				(3,923)			—
Payments for debt issuance costs	(3,995)				(1,111)			—
Proceeds from long-term debt	391,700				23,400			—
Repayment of long-term debt	(286,900)				(2,000)			—
Net advances from (distributions to) parent	—				(24,218)			11,124
Debt due from parent	—				(967)			(1,603)

Net cash provided by (used in) financing activities	97,641				(28,670)			9,521

Net increase in cash	5,977				2,776			—
Cash and cash equivalents at beginning of year	2,776				—			—
Cash and cash equivalents at end of year	$	8,753			$	2,776		$	—

Supplemental disclosures of cash flow information:

Cash paid during the year for:
Interest	$		2,068		$		499	$		—

Supplemental schedule of non-cash investing and financing activities:

Property, plant and equipment asset retirement obligation	$			450	$	—		$		—

Deferred offering costs	$			606	$	—		$		—

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN CAPITAL

(in thousands)

				PARTNERS’ CAPITAL													Accumulated Other
	Net Parent Investment			Limited Partners								General Partner			Other		Comprehensive Income (Loss)
				Common				Subordinated
	$			Units	$			Units	$			$			$		$			Total
Balance, December 31, 2000	$	50,751		—	$	—		—	$	—		$	—		$	—	$	—		$	50,751
Net income	2,586			—	—			—	—			—			—		—			2,586
Other comprehensive income	—			—	—			—	—			—			—		968			968
Net change in parent advances	11,124			—	—			—	—			—			—		—			11,124
Balance, December 31, 2001	64,461			—	—			—	—			—			—		968			65,429
Net income applicable to the period from January 1 through May 23, 2002	17,332			—	—			—	—			—			—		—			17,332
Net change in parent advances	(24,218		)	—	—			—	—			—			—		—			(24,218		)
Adjustment to reflect net liabilities not assumed by the Partnership	23,316			—	—			—	—			—			—		—			23,316
Book value of net assets contributed by MarkWest Hydrocarbon to the Partnership	(80,891		)	—	—			3,000	79,273			1,618			—		—			—
Distribution to MarkWest Hydrocarbon	—			—	—			—	(62,206		)	(1,270		)	—		—			(63,476		)
Issuance of units to public (including underwriter over-allotment), net of offering and other costs	—			2,415	43,625			—	—			—			—		—			43,625
Distributions to unitholders	—			—	(1,715		)	—	(2,130		)	(78		)	—		—			(3,923		)
Net income applicable to the period from May 24 through December 31, 2002	—			—	1,948			—	2,420			89			—		—			4,457
Other comprehensive loss	—			—	—			—	—			—			—		(1,679		)	(1,679		)
Balance at December 31, 2002	—			2,415	43,858			3,000	17,357			359			—		(711		)	60,863
Issuance of private placement units, net of offering costs	—			375	9,747			—	—			217			—		—			9,964
Contributions by MarkWest Hydrocarbon	—			—	—			—	—			—			695		—			695
Phantom units	—			24	952			—	—			20			—		—			972
Distributions to partners	—			—	(6,060		)	—	(6,960		)	(414		)	—		—			(13,434		)
Net income	—			—	2,546			—	2,972			260			—		—			5,778
Other comprehensive income	—			—	—			—	—			—			—		213			213
Balance at December 31, 2003	$	—		2,814	$	51,043		3,000	$	13,369		$	442		$	695	$	(498	)	$	65,051

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

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

1. Organization

MarkWest Energy Partners, L.P. (the Partnership), was formed on January 25, 2002, as a Delaware limited partnership. The Partnership and its wholly owned subsidiary, MarkWest Energy Operating Company, L.L.C. (the Operating Company), were formed to acquire, own and operate most of the assets, liabilities and operations of MarkWest Hydrocarbon, Inc.’s Midstream Business (the Midstream Business).

On May 24, 2002, MarkWest Hydrocarbon, Inc. (MarkWest Hydrocarbon), through its subsidiaries, MarkWest Energy GP, L.L.C. (the general partner of the Partnership), and MarkWest Michigan, Inc., conveyed the Midstream Business to the Partnership in exchange for:

• 3,000,000 subordinated limited partnership units, representing a 54.3% interest in the Partnership after the issuance of the common limited partnership units.

• A general partner interest, representing a 2.0% interest in the Partnership after the issuance of the common limited partnership units.

• Incentive distribution rights (as defined in the Partnership Agreement).

• The direct and indirect assumption of certain liabilities by the Partnership, including $1.8 million in working capital liabilities and $19.4 million of indebtedness.

• The right to be reimbursed by the Partnership for $15.6 million of capital expenditures.

• The right to receive $26.7 million in cash upon the closing of our initial public offering (the IPO) and the Operating Company’s new $60 million credit facility. The Operating Company is a wholly owned subsidiary of the Partnership.

In the IPO, the transfer of assets and liabilities to the Partnership from MarkWest Hydrocarbon represented a reorganization of entities under common control and was recorded at historical cost.

The Partnership concurrently issued 2,415,000 common limited partnership units (including 315,000 units issued pursuant to the underwriters’ over-allotment option), representing a 43.7% interest in the Partnership, at a price of $20.50 per unit. The Operating Company concurrently entered into a $60 million credit facility with various lenders.

A summary of the proceeds received and use of proceeds is as follows (in thousands):

Proceeds received:
Sale of common units	$	49,508
Underwriters’ fees	(3,466		)
Professional fees and other offering costs	(2,417		)
Net proceeds from initial public offering	43,625

Borrowing under term loan facility	21,400
Debt issuance costs	(1,111		)
Net proceeds from debt issuance	20,289

Total net proceeds received	63,914

Use of proceeds:
Repayment of assumed working capital liabilities	1,800
Repayment of debt due to parent	19,376
Reimbursement of capital expenditures to MarkWest Hydrocarbon	15,600
Distribution to MarkWest Hydrocarbon	26,700
Total use of proceeds	63,476

Net proceeds remaining	$	438

2. Summary of Significant Accounting Policies

Basis of Presentation

The consolidated and combined financial statements include the accounts of the Partnership and the Midstream Business and have been prepared in accordance with accounting principles generally accepted in the United States of America. Intercompany balances and transactions within the Partnership and Midstream Business have been eliminated.

Prior to May 24, 2002, the date on which the MarkWest Hydrocarbon Midstream Business was conveyed to the Partnership (see Note 1) the financial statements include charges from MarkWest Hydrocarbon for direct costs and allocations of indirect corporate overhead as well as federal and state income tax provisions. Selling, general and administrative expenses for the MarkWest Hydrocarbon Midstream Business in 2001 are comprised entirely of allocations of indirect corporate overhead from MarkWest Hydrocarbon. Management of the Partnership believes that the allocation methods are reasonable. Commencing with the conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership on May 24, 2002, the consolidated financial statements do not reflect any amounts for federal and state income taxes as the Partnership is not a taxable entity. However, the consolidated financial statements of the Partnership subsequent to May 24, 2002 do include charges from MarkWest Hydrocarbon for direct costs and allocation of indirect corporate overhead as more fully described in Note 6.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Inventories

Inventories consist primarily of crude oil and unprocessed natural gas and are valued at the lower of weighted average cost or market. Materials and supplies are valued at the lower of average cost or estimated net realizable value.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-term assets are capitalized and amortized over the related asset’s estimated useful life. Depreciation is provided principally on the straight-line method over the following estimated useful lives: gas gathering facilities and processing plants, fractionation and storage facilities, natural gas pipelines, crude oil pipelines and NGL transportation facilities—20 years or the number of years reserves behind our facilities are contractually dedicated, whichever is longer; buildings—40 years; furniture, leasehold improvements and other—3 to 10 years.

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, the Partnership evaluates its long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value determine the amount of the impairment recognized. For assets identified to be disposed of in the future, the carrying value of these assets is

compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.

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

• The availability and prices of NGL products and competing commodities.

• The availability and prices of raw natural gas supply.

• Our ability to negotiate favorable marketing agreements.

• The risks that third party 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.

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.

Capitalization of Interest

We capitalize interest on major projects during construction. Interest is capitalized on borrowed funds. The interest rates used are based on the average interest rate on related debt. During the years ended December 31, 2003 and 2002, we had no major construction project. Consequently, we did not capitalize any interest in either year.

Deferred Financing Costs

Deferred financing costs are amortized on a straight-line basis and charged to interest expense over the anticipated term of the associated agreement.

Commodity Price Risk Management Activities

In June 1998, SFAS No. 133 was issued effective for fiscal years beginning after June 15, 2000 (effective on January 1, 2001). Under SFAS No. 133, which was subsequently amended by SFAS No. 138 and SFAS No. 149 we are required to recognize the change in the market value of all derivatives as either assets or liabilities in our Balance Sheet and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction.

See also Notes 9 and 10 of this Form 10-K.

Fair Value of Financial Instruments

Our financial instruments consist of receivables, accounts payable and other current liabilities and debt. Except for debt, the carrying amounts of financial instruments approximate fair value due to their short maturities. At December 31, 2003 and 2002, based on rates available for similar types of debt, the fair value of our debt was not materially different from its carrying amount.

Net Parent Investment

The net parent investment represents a net balance as the result of various transactions between the Midstream Business and MarkWest Hydrocarbon. There were no terms of settlement or interest charges associated with this

balance. The balance was the result of the Midstream Business’s participation in MarkWest Hydrocarbon’s central cash management program, wherein all of the Midstream Business’s cash receipts were remitted to MarkWest Hydrocarbon, and all cash disbursements were funded by MarkWest Hydrocarbon. Other transactions included intercompany transportation and terminating revenues and related expenses, administrative and support expenses incurred by MarkWest Hydrocarbon and allocated to the Midstream Business, and accrued interest and income taxes.

Revenue Recognition

Gas gathering and processing, NGL fractionation, transportation and storage revenues are recognized as volumes are processed, fractionated, transported and stored in accordance with contractual terms. Gas volumes received may be different from gas volumes delivered resulting in gas imbalances. The Company records a receivable or payable for such imbalances based upon each imbalance’s contractual terms. Revenues for the transportation of crude are recognized (1) based upon regulated tariff rates and the related transportation volumes and (2) when delivery of crude is made to the shipper or other common carrier pipeline. Revenue for NGL product sales are recognized at the time the title is transferred.

Income Taxes

The Partnership is not a taxable entity. The Midstream Business’s operations were included in MarkWest Hydrocarbon’s consolidated federal and state income tax returns. The Midstream Business’s income tax provisions were computed as though separate returns were filed. The Midstream Business accounted for income taxes in accordance with the provisions of SFAS No. 109, Accounting for Income Taxes. This statement requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in a company’s financial statements or tax returns. Using this method, deferred tax liabilities and assets were determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates.

Unit Compensation

As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, we have elected to continue to measure compensation costs for unit-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. We apply variable accounting for our plan that is more fully described in Note 12. Compensation expense for the variable plan, including restricted unit grants, is measured using the market price of MarkWest Energy Partners’ common units on the date the number of units in the grant becomes determinable and is amortized into earnings over the period of service. Accelerated vesting, at the discretion of the general partner of the Partnership, results in an immediate charge to operations.

Segment Reporting

Our business segments consist of our three principal geographic areas of operations: Appalachia, Michigan and the Southwest. See Note 16.

Recent Accounting Pronouncements

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 was effective for the Partnership as of December 31, 2003, as it relates to special-purpose entities, as defined, and in the first quarter of 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.

3. Acquisitions

Pinnacle Acquisition

On March 28, 2003, we completed the acquisition (the “Pinnacle Acquisition”) of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNG Utility Company and Bright Star Gathering, Inc. (collectively, “Pinnacle” or the “Sellers”). Pinnacle’s results of operations have been included in the Partnership’s consolidated financial statements since that date.

The Pinnacle Acquisition was accomplished through a merger under Texas law of the Sellers and four newly formed wholly owned subsidiaries of the Partnership as buyers. In the merger, most of the assets and liabilities of the Sellers were allocated to the Partnership entities, and all entities survived the merger. The assets acquired from the Sellers, primarily located in the State of Texas, with the balance located in New Mexico, Louisiana, Mississippi and Kansas, are comprised of three lateral natural gas pipelines and twenty gathering systems.

The purchase price was comprised of $23.4 million paid in cash to the Sellers, plus the assumption of specified liabilities, including $16.6 million of bank indebtedness, and was allocated as follows (in thousands):

Acquisition costs:
Long-term debt incurred	$	39,471
Direct acquisition costs	450
Current liabilities assumed	8,945

	$	48,866

Allocation of acquisition costs:
Current assets	$	10,643
Fixed assets (including long-term contracts)	38,223

Total	$	48,866

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the comparable periods presented, as though the Pinnacle Acquisition had occurred on January 1 in each of the periods presented. These unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Year Ended December 31,
	2003		2002
	(in thousands, except per unit amounts)
Revenue	$	135,324	$	113,546
Net income(1)	$	6,493	$	19,656
Basic net income per limited partner unit(1)	$	1.08	$	4.39
Diluted net income per limited partner unit(1)	$	1.07	$	4.36

(1) Includes a one-time impairment charge of $1.7 million for the year ended December 31, 2002.

Western Oklahoma Acquisition

On December 1, 2003, we completed the acquisition (the “western Oklahoma acquisition”) of certain assets of American Central Western Oklahoma Gas Company, L.L.C. (“AWOC”) for approximately $38 million, before transaction costs and subject to certain post-closing adjustments. Western Oklahoma’s results of operations have been included in the Partnership’s consolidated financial statements since that date.

The assets include the Foss Lake gathering system (the “gathering system”) located in the western Oklahoma counties of Roger Mills and Custer. The gathering system is comprised of approximately 167 miles of pipeline, connected to approximately 270 wells, and 11,000 horsepower of compression facilities. The assets also include the Arapaho gas processing plant that was installed during 2000.

The purchase price of approximately $38 million was financed through borrowings under the Partnership line of credit, which was amended at the closing of the acquisition to increase availability under the credit facility from $75 million to $140 million. Substantially all of the acquired assets are pledged to the credit facility lenders to secure the repayment of the outstanding borrowings under the credit facility.

The purchase price was comprised of $38.0 million paid in cash to AWOC, and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	37,850
Direct acquisition costs	101

	$	37,951

Allocation of acquisition costs:
Property, plant and equipment	$	37,951

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the comparable periods presented, as though the western Oklahoma Acquisition had occurred on January 1 in each of the periods presented. These unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Year Ended December 31,
	2003		2002
	(in thousands, except per unit amounts)

Revenue	$	154,553	$	94,897
Net Income (1)	$	10,712	$	21,202
Basic net income per limited partner unit (1)	$	1.81	$	4.73
Diluted net income per limited partner unit (1)	$	1.79	$	4.70

(1) Includes management fee expense of approximately $1.7 million and $1.9 million for the years ended December 31, 2003 and 2002, respectively.

Michigan Crude Pipeline

On December 18, 2003, we completed the acquisition (the “Michigan Crude Pipeline acquisition”) of Shell Pipeline Company, LP’s and Equilon Enterprises, LLC’s, doing business as Shell Oil Products US (“Shell”), Michigan Crude Gathering Pipeline (the “System”), for approximately $21.2 million. The System’s results of operations have been included in the Partnership’s consolidated financial statements since December 18, 2003. The $21.2 million purchase price was financed through borrowings under the Partnership line of credit.

The System extends from production facilities near Manistee, Michigan to a storage facility near Lewiston, Michigan. The trunk line consists of approximately 150 miles of pipe. Crude oil is gathered into the System from 57 injection points, including 52 central production facilities and five truck unloading facilities, and comprises approximately 100 miles of pipe. The System also includes truck-unloading stations at Manistee, Seeley Road and Junction, and the Samaria Truck Unloading Station located in Monroe County, Michigan, near Toledo, Ohio.

The System is a common carrier Michigan intrastate pipeline and gathers light crude oil from wells. The oil is transported for a fee to the Lewiston, Michigan station where it is batch injected into the Enbridge Lakehead Pipeline, which then transports oil to refineries in Sarnia, Ontario, Canada. The pipeline is an alternative form of crude oil transportation to trucking.

The purchase price was comprised of $21.3 million paid in cash to Shell, and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	21,155
Direct acquisition costs	128

	$	21,283

Allocation of acquisition costs:
Property, plant and equipment	$	21,283

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the comparable periods presented, as though the Michigan Crude Pipeline Acquisition had occurred on January 1 in each period presented. These unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Year Ended December 31,
	2003		2002
	(in thousands, except per unit amounts)

Revenue	$	121,755	$	75,255
Net income	$	5,496	$	22,493
Basic net income per limited partner unit	$	0.91	$	5.01
Diluted net income per limited partner unit	$	0.90	$	4.98

Lubbock Pipeline

Effective September 1, 2003, the Partnership, through its wholly owned subsidiary, MarkWest Pinnacle L.P., completed the acquisition (the “Lubbock Pipeline Acquisition”) of a 68-mile intrastate gas transmission pipeline near Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2 million. The transaction was financed through borrowings under our credit facility. The Lubbock Pipeline’s results of operations have been included in the Partnership’s consolidated financial statements since that date. The pro forma results of operations of the Lubbock Pipeline Acquisition have not been presented as they are not significant.

4. Asset Retirement Obligation

In June 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations. The Partnership adopted SFAS No. 143 beginning January 1, 2003. The most significant impact of this standard on the Partnership was a change in the method of accruing for site restoration costs. Under SFAS No. 143, the fair value of asset retirement obligations is recorded as a liability when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets.

The Partnership’s assets subject to asset retirement obligations are primarily certain gas gathering pipelines and processing facilities, a crude oil pipeline and other related pipeline assets.

In connection with the adoption of SFAS No. 143, we reviewed current laws and regulations governing obligations for asset retirements as well as our leases. Based on that review, certain of our properties did not have any legal obligations associated with the retirement of our tangible long-lived assets.

The Partnership has identified certain of its assets as having an indeterminate life in accordance with SFAS No. 143, which does not trigger a requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines and processing plants. A liability for these asset retirement obligations will be recorded if and when a future retirement obligation is identified.

The asset retirement obligation associated with the remaining facilities was immaterial and not recognized in the financial statements.

In October 2003, the board of directors of our general partner approved a plan to shut down our existing Cobb processing facility, contingent upon the construction of a replacement facility. Construction of the new facility is expected to be completed by mid-2004. During the fourth quarter of 2003, we estimated the amount of the asset retirement obligation associated with the shut down of the old Cobb facility to be $450,000, and, accordingly, we recorded a related accrued liability.

At January 1 and December 31, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. We had no estimated asset retirement obligation liability at January 1 and December 31, 2002, respectively.

The following is a reconciliation of the changes in the asset retirement obligation from January 1, 2003, to December 31, 2003 (in thousands):

Asset retirement obligation as of January 1, 2003	$	—
Obligation arising from adoption of SFAS 143	—
Liabilities settled	—
Changes in estimated asset retirement obligation	450
Accretion expense	—
Asset retirement obligation as of December 31, 2003	$	450

5. Property, Plant and Equipment

The following provides composition of the Partnership’s property, plant and equipment at:

	December 31,
	2003			2002
	(in thousands)
Property, plant and equipment:
Gas gathering facilities	$	73,424		$	34,398
Gas processing plants	55,888			47,403
Fractionation and storage facilities	22,160			22,076
Natural gas pipelines	38,790			—
Crude oil pipelines	18,352			—
NGL transportation facilities	4,415			4,402
Land, building and other equipment	9,664			3,021
Construction in-progress	1,841			348
	224,534			111,648
Less:Accumulated depreciation	(40,320		)	(31,824		)
Total property, plant and equipment, net	$	184,214		$	79,824

Cobb Processing Plant

During 2003, the Partnership entered into an agreement with MarkWest Hydrocarbon for the construction of a new Cobb processing plant. Of the expected $2.1 million to construct the new plant and decommission and dismantle the old plant, $1.7 million will be funded by MarkWest Hydrocarbon, and $0.4 million will be funded by the Partnership. As of December 31, 2003, the $0.7 million funded by MarkWest Hydrocarbon has been reflected in the balance sheet as an increase to property, plant and equipment, and a corresponding credit to partners’ capital, and has been reflected in the statement of changes in capital as other partners’ capital.

The Partnership will continue to operate the existing Cobb processing plant until the scheduled mid-2004 completion date of the new plant. Subsequent thereto, the existing plant will be decommissioned and dismantled at an expected cost of $0.4 million. As of December 31, 2003, the costs have been reflected in the balance sheet as an increase to property, plant and equipment, and a corresponding increase to the asset retirement obligation has been reflected in other liabilities. As of December 31, 2003, and in accordance with SFAS No. 144, we determined that the carrying value of the old processing plant of $1.4 million exceeded its estimated fair value of $0.3 million. Consequently, we have reflected impairment of $1.1 million in the statement of operations.

6. Related Party Transactions

Prior to the IPO, substantially all related party transactions were settled immediately through the net parent investment account. Subsequent to the IPO, normal trade terms apply to transactions with MarkWest Hydrocarbon as contained in various agreements discussed below which were entered into concurrent with the closing of the IPO.

Receivable from Affiliate

Affiliated revenues in the consolidated and combined statements of income consist of service fees and NGL product sales. Concurrent with the closing of the IPO, we entered into a number of contracts with MarkWest Hydrocarbon. Specifically, we entered into:

• A gas processing agreement pursuant to which MarkWest Hydrocarbon delivers to us all natural gas it receives from Columbia Gas Transmission Corporation for processing at our processing plants.

MarkWest Hydrocarbon pays us a monthly fee based on the natural gas volumes delivered to us for processing.

• A transportation agreement pursuant to which MarkWest Hydrocarbon delivers all of its NGLs to us for transportation through our pipelines to our Siloam fractionator. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for transportation.

• A fractionation agreement pursuant to which MarkWest Hydrocarbon delivers all of its NGLs to us for unloading, fractionation, loading and storage at our Siloam facility. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for fractionation, a percentage of the proceeds from the sale of a portion of the NGL products produced, an annual storage fee, and a monthly fee based on the number of gallons of NGLs unloaded.

• A natural gas liquids purchase agreement pursuant to which MarkWest Hydrocarbon receives and purchases, and we deliver and sell, all of the NGL products we produce pursuant to our gas processing agreement with a third party. Under the terms of this agreement, MarkWest Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale to third parties of such NGL products. This contract also applies to any other NGL products we acquire. We retain a percentage of the proceeds attributable to the sale of the NGL products we produce pursuant to our agreement with a third party, and remit the balance from such NGL products sale proceeds to this third party.

Payable to Affiliate

Under the Services Agreement with MarkWest Hydrocarbon, MarkWest Hydrocarbon is continuing to provide centralized corporate functions such as accounting, treasury, engineering, information technology, insurance and other corporate services. We reimburse MarkWest Hydrocarbon monthly for the selling, general and administrative support MarkWest Hydrocarbon allocates to us.

The Partnership is also reimbursing MarkWest Hydrocarbon for the salaries and employee benefits, such as 401(k), pension, and health insurance, of plant operating personnel as well as other direct operating expenses. For the years ended December 31, 2003 and 2002, these costs totaled $6.2 million and $2.6 million, respectively, and appear in facility expenses. The Partnership has no employees.

In Michigan, we assumed the Midstream Business’s existing contracts and gather and process gas directly for those third parties. We receive 100% of all fee and percent-of-proceeds consideration for the first 10,000 Mcf/d that we gather in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and processing income we earn on quarterly Michigan pipeline throughput in excess of 10,000 Mcf/d. For years ended December 31, 2003, and 2002, MarkWest Hydrocarbon’s net profit interest was $0.9 million and $0.4 million, respectively, and is included in facility expenses.

For the years ended December 31, 2003 and 2002, MarkWest Hydrocarbon allocated approximately $2.0 million and $4.1 million, respectively, of selling, general and administrative expenses to us.

Debt Due to Affiliate

Prior to the IPO, the Midstream Business financed its working capital requirements and its capital expenditures through intercompany accounts between the Midstream Business and MarkWest Hydrocarbon. Effective October 12, 2001, MarkWest Hydrocarbon formalized the terms under which certain intercompany accounts would be settled between the Midstream Business and MarkWest Hydrocarbon. Interest on the outstanding balance was charged annually based on MarkWest Hydrocarbon’s average borrowing rate from a third party. Interest charges were settled through the net parent investment account. Interest was charged at a weighted average rate of 6.3% and 6.5% for the period from January 1, 2002, through May 23, 2002, and the year ended December 31, 2001, respectively. On May 24, 2002, debt due to MarkWest Hydrocarbon was assumed by the Partnership and paid in full with proceeds from the IPO.

7. Long-Term Debt

On May 20, 2002, the Operating Company entered into a $60 million credit facility (the “Original Credit Facility”) with various financial institutions that was comprised of both a revolving and term loan. In March 2003, the Original Credit Facility was increased by $15 million to $75 million.

On December 1, 2003, the Operating Company amended the Original Credit Facility, and entered into a $140 million Amended and Restated Credit Agreement (the “Partnership Credit Facility”) with various financial institutions. The Partnership Credit Facility is available to fund capital expenditures and acquisitions, working capital requirements (including letters of credit) and distributions to unit holders. Advances to fund distributions to unit holders may not exceed $0.50 per outstanding unit in any 12-consecutive-month period. At December 31, 2003, $126.2 million was outstanding, and $13.8 million was available, under the Partnership Credit Facility.

The Operating Company may prepay all loans at any time without penalty. During each calendar year, the Partnership Credit Facility requires that there be a 15-consecutive-day period during which there are no distribution loans made or outstanding.

At the Operating Company’s option, indebtedness under the Partnership Credit Facility bears interest at either (i) the higher of the federal funds rate plus 0.50% or the prime rate as announced by lender plus an applicable margin of 0.625% to 2.125% or (ii) at a rate equal to LIBOR plus an applicable margin ranging from 2.00% per annum to 3.50% per annum depending on the Partnership’s ratio of Consolidated Funded Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. For the year ended December 31, 2003, the weighted average interest rate was 4.69%.

The Operating Company incurs a commitment fee on the unused portion of the credit facility at a rate ranging from 37.5 to 50.0 basis points based upon the ratio of our Consolidated Funded Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. The Partnership Credit Facility matures in November 2006. At that time, the Partnership Credit Facility will terminate and all outstanding amounts thereunder will be due and payable.

The Partnership Credit Facility contains various covenants limiting the Partnership’s ability to:

• incur indebtedness;

• grant certain liens;

• make loans, acquisitions and investments;

• amend material agreements, including agreements with MarkWest Hydrocarbon;

• acquire another company;

• enter into a merger, consolidation or sale of assets; or

• make distributions in excess of Available Cash (as defined in the Partnership Agreement) for the preceding fiscal quarter.

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

• a ratio of not less than 3.50:1.00 of Consolidated EBITDA to interest expense for the prior four fiscal quarters;

• a ratio of not more than 4.75:1.00 prior to March 2004 and 3.50 to 1.00 after March 2004 of total debt to Consolidated EBITDA for the prior four fiscal quarters;

• a minimum net worth of $55 million plus 75% of proceeds of equity issued after December 1, 2003; and

• a ratio of not more than 3.00 to 1.00 of Consolidated EBITDA to cash interest payments on indebtedness for the prior fiscal quarter in the event that MarkWest Hydrocarbon has freely available cash reserves of less than $17.5 million.

We and the subsidiaries of the Operating Company have given full, unconditional and joint and several guarantees of any obligation under the credit facility and have pledged substantially all of our assets to secure the credit facility.

Scheduled Debt Maturities

Scheduled debt maturities were as follows (in thousands):

	December 31
2004	$	—
2005	—
2006	126,200
2007	—
2008	—
2009 and thereafter	—
Total debt outstanding	$	126,200

8. Significant Customers and Concentration of Credit Risk

For the years ended December 31, 2003 and 2002, sales to MarkWest Hydrocarbon accounted for 42% and 37% of total revenues, respectively. For the year ended December 31, 2001, sales to two customers accounted for 16% and 10%, respectively, of total revenues.

Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade accounts receivable. Our primary customer is MarkWest Hydrocarbon. Consequently, matters affecting the business and financial condition of MarkWest Hydrocarbon—including its operations, management, customers, vendors and the like—have the potential to impact, both positively and negatively, our credit exposure. Outside of MarkWest Hydrocarbon, our customers are concentrated within the Appalachian Basin, Southwest United States and Michigan geographic areas and are engaged in retail propane, refining, petrochemical industries, utilities municipalities and other large industrial users. Consequently, changes within these regions and/or industries also have the potential to impact, both positively and negatively, our credit exposure.

9. Commodity Risk Management

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

As of December 31, 2003, we have hedged natural gas sales as follows:

	Year Ending December 31,
	2004		2005
Hedged Natural Gas Sales
Natural gas Mmbtu	183,000		182,500
Natural gas sales price per Mmbtu	$	4.57	$	4.26

Natural Gas Puts
Natural gas Mmbtu	366,000		—
Natural gas sales price per Mmbtu	$	4.00	$	NA

Total Hedged Natural Gas
Natural gas Mmbtu	549,000		182,500
Natural gas sales price per Mmbtu	$	4.19	$	4.26

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. Of the $0.5 million reflected as accumulated other comprehensive loss, approximately $0.2 is related to hedging activities that expire within one year and, consequently, may be reflected in 2004 operations.

Interest Rate

10. Adoption of SFAS No. 133

The Midstream Business adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, on January 1, 2001. In accordance with the transition provisions of SFAS No. 133, the Midstream Business recorded on that date a $1.3 million net-of-tax cumulative effect gain to other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments.

SFAS No. 133 establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in the derivative instruments’ fair value are recognized in earnings unless specific hedge accounting criteria are met.

SFAS No. 133 allows hedge accounting for fair-value and cash-flow hedges. A fair-value hedge applies to a recognized asset or liability or an unrecognized firm commitment. A cash-flow hedge applies to a forecasted transaction or a variable cash flow of a recognized asset or liability. SFAS No. 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair-value hedging instrument as well as the offsetting loss or gain on the hedged item be recognized currently in earnings in the same accounting period. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash-flow hedging instrument be reported as a component of other comprehensive income and be reclassified into revenues in the same period during which the hedged forecasted transaction affects revenues. (The remaining gain or loss, “ineffective portion”, on the derivative instrument, if any, must be recognized currently in earnings.) Effectiveness is evaluated by the derivative instrument’s ability to generate offsetting changes in fair value or cash flows to the hedged item. The Partnership and the Midstream Business formally documents, designates and assesses the effectiveness of transactions receiving hedge accounting treatment.

The Midstream Business entered into fixed-price contracts for the sale of NGL products and fixed-price contracts for the purchase of natural gas (designated as cash flow hedges) and NGL products (designated as fair value

hedges). At January 1, 2001, the Midstream Business recorded a risk management asset of $2.1 million and a deferred tax liability of $0.7 million, resulting in a $1.3 million gain reported in other comprehensive income.

11. Income Taxes

The provision (benefit) for income taxes for the year ended December 31, 2002 and 2001 while the business was a taxable entity (in thousands) is comprised of the following:

	2002			2001
Current taxes due from parent:
Federal	$	(1,252	)	$	(1,197	)
State	(283		)	(271		)
Total current due from parent	(1,535		)	(1,468		)
Deferred:
Federal	1,406			2,722
State	190			370
Change in tax status	(17,236		)	—
Total deferred	(15,640		)	3,092
Total provision (benefit) for income taxes	$	(17,175	)	$	1,624

The difference between the provision (benefit) for income taxes at the statutory rate and the actual provision (benefit) for income taxes for the year ended December 31, 2002 and 2001 (in thousands) is summarized as follows:

	2002			2001
Income tax at statutory rate	$	1,569		$	1,432
State income taxes, net of federal benefit	235			192
Partnership income not subject to taxation	(1,743		)	—
Change in tax status	(17,236		)	—
Total provision (benefit) for income taxes	$	(17,175	)	$	1,624

12. Long-Term Incentive Plan

Long-Term Incentive Plan

Our general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of our general partner and employees of its affiliates who perform services for us. The long-term incentive plan consists of two components, restricted units and unit options. The long-term incentive plan currently permits the grant of awards covering an aggregate of 500,000 common units, 200,000 of which may be awarded in the form of restricted units and 300,000 of which may be awarded in the form of unit options. The Compensation Committee of our general partner’s board of directors administers the plan.

Our general partner’s board of directors in its discretion may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

Restricted Units. A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. These restricted units will be entitled to receive distribution equivalents, which represent cash equal to the amount of cash distributions made on common units during the vesting period, from the date of grant and will

vest over a period of four years, with 25% of the grant vesting at the end of each of the second and third years and 50% vesting at the end of the fourth year. In the future, the Compensation Committee may determine to make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine under the plan. The Compensation Committee will determine the period over which restricted units granted to employees and directors will vest. The Committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of us, our general partner or MarkWest Hydrocarbon.

If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The Compensation Committee, in its discretion, may grant distribution rights with respect to any additional restricted unit grants.

We intend the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.

In October 2003, the board of directors of our general partner approved the accelerated vesting of restricted unit grants upon the achievement of specified performance goals. However, the vesting of any restricted units may not occur until at least one year following the date of grant. Consequently, 23,758 restricted units vested effective December 1, 2003. Accordingly, the Partnership recorded a charge in the amount of $1.0 million, equal to the product of 23,758 units and $40.10 per unit, the fair market value at the date of the accelerated vesting, and a corresponding credit to common units.

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

	2003			2002
	(in thousands, except unit data)

Balance, beginning of period	50,230			—
Granted	11,756			55,587
Vesting	(23,758		)	—
Forfeited	(3,732		)	(5,357		)
Balance, end of period	34,496			50,230

Fair value, end of period	$	1,383		$	1,200

Compensation expense	$	1,398		$	73

Unit Options

The long-term incentive plan currently permits the granting of options covering common units. The Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the committee shall determine. Unit options will have an exercise price that, in the discretion of the committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the Compensation Committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner, Markwest Hydrocarbon or upon the achievement of specified financial objectives.

Upon exercise of a unit option, our general partner will acquire common units in the open market or directly from us or any other person or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will pay us the proceeds it received from the optionee upon exercise of the unit option.

As of December 31, 2003, we had not granted common unit options to directors or employees of our general partner, or employees of its affiliates or members of senior management.

13. Commitments and Contingencies

Legal

The Partnership, 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.

Lease Obligations

We have various non-cancelable operating lease agreements for equipment expiring at various times through fiscal 2015. Annual rent expense under these operating leases was $1.1 million, $0.6 million and $0.6 million for the years ended December 31, 2003, 2002, and 2001, respectively. Our minimum future lease payments under these operating leases as of December 31, 2003, are as follows (in thousands):

2004	$	1,125
2005	722
2006	604
2007	362
2008	238
2009 and thereafter	421
Total	$	3,472

14. Partners’ Capital

As of December 31, 2003, partners’ capital consists of 2,813,758 common limited partner units, representing a 47.4% partnership interest, 3,000,000 subordinated limited partner units, representing a 50.6% partnership interest, and a 2% general partner interest. Affiliates of MarkWest Hydrocarbon, in the aggregate, owned a 43.8% interest in the Partnership consisting of 2,479,762 subordinated limited partner units and a 2% general partner interest.

The Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P. (the Partnership Agreement) contains specific provisions for the allocation of net income and losses to each of the partners for the purposes of maintaining the partner capital accounts.

Distributions of Available Cash

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

Subordination Period

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

The subordination period ends on the first day of any quarter beginning after June 30, 2009, when certain financial tests (defined in the Partnership Agreement) are met. Additionally, a portion of the subordinated units may convert earlier into common units on a one-for-one basis if additional financial tests (defined in the Partnership Agreement) are met. Generally, the earliest possible date by which all subordinated units may be converted into common units is June 30, 2007. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

Distributions of Available Cash During the Subordination Period

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

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

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

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

• Thereafter, in the manner described in “—Incentive Distribution Rights” below.

Distributions of Available Cash After the Subordination Period

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

• First, 98% to all unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

• Thereafter, in the manner described in “—Incentive Distribution Rights” below.

Incentive Distribution Rights

If for any quarter:

• We have distributed available cash to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

• We have distributed available cash on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

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

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Unitholders	General Partner

Minimum Quarterly Distribution	$0.50	98%	2%
First Target Distribution	up to $0.55	98%	2%
Second Target Distribution	above $0.55 up to $0.625	85%	15%
Third Target Distribution	above $0.625 up to $0.75	75%	25%
Thereafter	above $0.75	50%	50%

The quarterly cash distributions applicable to 2003 and 2002 were as follows:

Quarter Ended	Record Date	Payment Date	Amount Per Unit

March 31, 2003	May 5, 2003	May 15, 2003	$	0.58
June 30, 2003	August 4, 2003	August 14, 2003	$	0.58
September 30, 2003	November 4, 2003	November 14, 2003	$	0.64
December 31, 2003	January 31, 2004	February 13, 2004	$	0.67

June 30, 2002	August 13, 2002	August 15, 2002	$	0.21
September 30, 2002	October 31, 2002	November 14, 2002	$	0.50
December 31, 2002	January 31, 2003	February 14, 2003	$	0.52

Private Placement

The Partnership sold 375,000 common units in two installments at a price of $26.23 per unit in a private placement to certain accredited investors. The first installment of 300,031 units was completed on June 27, 2003, and grossed approximately $7.9 million. The second installment of 74,969 units was completed on July 10, 2003, and grossed approximately $1.9 million. Transaction costs for both installments were less than $0.1 million. The Partnership’s general partner paid its pro rata contribution in July 2003 after the second installment was completed. We used the net proceeds from both installments to pay down debt under our credit facility.

Subsequent Event

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.

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.

15. Employee Benefit Plan

All employees dedicated to, or otherwise principally supporting, the Partnership are employees of MarkWest Hydrocarbon and substantially all of these employees are participants in MarkWest Hydrocarbon’s defined contribution plan. MarkWest Energy Partners’ costs related to this plan were $0.2 million, $0.1 million and $0.1 million for the years ended December 31, 2003, 2002 and 2001, respectively. The plan is discretionary, with annual contributions determined by MarkWest Hydrocarbon’s Board of Directors.

16. Segment Information

In accordance with the manner in which we manage our business, including the allocation of capital and evaluation of business segment performance, we report our operations in the following geographical segments: (1) Appalachia, through MarkWest Energy Appalachia, L.L.C., (2) Michigan, through Basin Pipeline, L.L.C and West Shore Processing Company, L.L.C. (gas gathering and processing) and MarkWest Michigan Pipeline Company, L.L.C. (crude oil transportation) and (3) Southwest, through MarkWest Texas GP, L.L.C. and MW Texas Limited, L.L.C, and their affiliates (the Appleby and 18 other gathering systems) and MarkWest Western Oklahoma Gas Company, L.L.C. (the Foss Lake Gathering System and Arapaho processing plant). Our direct investment in natural gas gathering and processing, and crude oil transportation, has increased as a result of three acquisitions in the Southwest and one acquisition in Michigan, respectively.

The accounting policies we apply in the generation of business segment information are generally the same as those described in Note 1 to the accompanying Consolidated and Combined Financial Statements, except that certain items below the “Operating Income” line are not allocated to business segments as they are not considered by management in their evaluation of business unit performance. In addition, general and administrative expenses are not allocated to individual business segments. Management evaluates business segment performance based on operating income, as adjusted, in relation to capital employed. To derive capital employed, certain Partnership assets are allocated based on relative segment assets. We have no intersegment sales or asset transfers.

We had revenues from MarkWest Hydrocarbon, reflected as “Affiliates”, that represented 42% and 37% of our consolidated operating revenues for the years ended December 31, 2003 and 2002, respectively.

	Appalachia		Michigan			Southwest		Total
Year Ended December 31, 2003:
Revenues:
Affiliates	$	49,850	$	—		$	—	$	49,850
Unaffiliated parties	1,278		11,778			54,631		67,687
Depreciation	2,870		2,394			2,284		7,548
Impairment	1,148		—			—		1,148
Operating income (1)	12,407		841			4,298		17,546
Capital expenditures	1,799		60			1,085		2,944
Total segment assets	49,168		58,022			105,788		212,978

Year Ended December 31, 2002:
Revenues:
Affiliates	$	26,093	$	—		$	—	$	26,093
Unaffiliated parties	35,161		8,992			—		44,153
Depreciation	2,647		2,333			—		4,980
Operating income (loss)(1)	12,692		(1,433		)	—		11,259
Capital expenditures	2,110		35			—		2,145
Total segment assets	50,131		37,578			—		87,709

Year Ended December 31, 2001:
Revenues:
Affiliates	$	—	$	—		$	—	$	—
Unaffiliated parties	86,600		7,075			—		93,675
Depreciation	2,151		2,339			—		4,490
Operating income (loss)(1)	11,401		(837		)	—		10,564
Capital expenditures	9,651		—			—		9,651
Total segment assets	67,486		37,405			—		104,891

(1) The following is a reconciliation of operating income, as stated above, to the statements of operations, as selling, general and administrative expenses are not allocated to our Appalachia, Michigan and Southwest operations, and a reconciliation to net income:

	Year Ended December 31,
	2003			2002			2001

Total operating income	$	17,546		$	11,259		$	10,564
Selling, general and administrative expenses	7,686			5,283			5,047

Operating income	9,860			5,976			5,517

Interest expense, net	(4,057		)	(1,414		)	(1,307		)
Miscellaneous income (expense)	(25		)	52			—
Provision (benefit) for income taxes	—			(17,175		)	1,624

Net income	$	5,778		$	21,789		$	2,586

17. Quarterly Results of Operations (Unaudited)

The following summarizes certain quarterly results of operations:

	Three Months Ended
	March 31		June 30		September 30		December 31
	(in thousands, except per unit amounts)
2003
Revenue	$	17,693	$	29,636	$	31,412	$	38,796
Income from operations	$	2,366	$	2,508	$	3,597	$	1,389
Net income (loss)	$	1,625	$	1,538	$	2,767	$	(152	)(1)
Limited partner share of net income (loss)	$	1,593	$	1,482	$	2,685	$	(241	)
Net income (loss) per limited partner unit:
Basic	$	0.29	$	0.28	$	0.47	$	(0.08	)
Diluted	$	0.29	$	0.28	$	0.46	$	(0.07	)

	Three Months Ended
	March 31		June 30		September 30		December 31
	(in thousands, except per unit amounts)
2002
Revenue	$	27,440	$	14,463	$	13,868	$	14,475
Income from operations	$	1,422	$	137	$	2,906	$	1,511
Net income	$	690	$	17,452	$	2,526	$	1,121
Limited partner share of net income	$	690	$	17,436	$	2,475	$	1,099
Net income per limited partner unit:
Basic	$	0.23	$	4.35	$	0.46	$	0.20
Diluted	$	0.23	$	4.34	$	0.45	$	0.20

(1) Included in the net loss for the fourth quarter ended December 31, 2003, is impairment of $1,148 associated with the Cobb Processing Plant. See note 4.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Attached as exhibits 31.1, 31.2 and 31.3 to this Annual Report are certifications of the Company’s principal executive and accounting officers (who we refer to in this periodic report as our Certifying Officers) required in accordance with Section 302 of the Sarbanes-Oxley Act of 2002 (the “Section 302 Certifications”). This portion of our Annual Report on Form 10-K discloses the results of our evaluation of our disclosure controls and procedures as of December 31, 2003 referred to in paragraphs (4) and (5) of the Section 302 Certifications and should be read in conjunction with the Section 302 Certifications for a more complete understanding of the topics presented.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to our management, including our Certifying Officers, as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2003, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that as of December 31, 2003, our disclosure controls and procedures were effective.

Nevertheless, we are currently conducting a further review of our internal controls over financial reporting as a result of a report (the “PwC Report”) delivered to our Audit Committee of our Board of Directors on March 10, 2004, by PricewaterhouseCoopers LLC (“PwC”), our independent accountants who audited our financial statements for the year ended December 31, 2003, in connection with the completion of its audit of, and the issuance of an unqualified report on, our financial statements for the years ended December 31, 2001, 2002 and 2003. In the PwC Report, PwC identified to management and the Audit Committee certain deficiencies in our internal accounting controls which, considered collectively, may constitute a material weakness in our internal controls pursuant to standards established by the American Institute of Certified Public Accountants. Deficiencies identified by PwC included a possible insufficiency in the personnel resources available to adequately maintain our financial reporting obligations as a public company; inadequate implementation of uniform controls over certain acquired entities and operations; inadequate control over classification of certain fixed asset balances and processes for accrual of certain accounts payable; and the potential need for separation of certain duties between payroll and other accounting personnel. PwC concluded that these deficiencies required PwC to increase the scope of its audit procedures in order to issue its unqualified report on our financial statements.

As a result of the PwC Report, we are in the process of carrying out a further internal review under the supervision and with the participation of our management and our Certifying Officers of the effectiveness of the design and operation of our disclosure controls and procedures. Such evaluation will consider all of the deficiencies noted in the PwC Report with the aim of supplementing our internal controls in order to mitigate the effect of the weaknesses and deficiencies identified in the PwC Report and to prevent any potential misstatements or omissions in our consolidated financial statements resulting from such factors. Our management has assigned a high priority to the short-term and long-term correction of the internal control weaknesses and deficiencies identified by PwC and will implement any necessary changes to our policies, procedures, systems and personnel to address these issues and any other matters identified by our review.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Management of MarkWest Energy Partners, L.P.

MarkWest Energy GP, L.L.C., as our general partner, manages our operations and activities on our behalf. Our general partner is not elected by our unitholders and will not be subject to reelection on a regular basis in the future. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. However, whenever possible, our general partner intends to incur indebtedness or other obligations that are non-recourse.

Two members of the board of directors of our general partner serve on a Conflicts Committee to review specific matters that the board believes may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by the American Stock Exchange and certain other requirements. Any matters approved by the Conflicts Committee are conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The current members of the Conflicts Committee are Charles K. Dempster and William P. Nicoletti. Three members of the board of directors serve on the Compensation Committee, which oversees compensation decisions for the officers of our general partner as well as the compensation plans described below. Three members of the board of directors serve on the Audit Committee that review our external financial reporting, recommends engagement of our independent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. The members of the Compensation and Audit Committees are Charles K. Dempster, William A. Kellstrom and William P. Nicoletti.

Some officers of our general partner spend a substantial amount of time managing the business and affairs of MarkWest Hydrocarbon and its other affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of MarkWest Hydrocarbon. Our general partner intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Directors and Executive Officers of MarkWest Energy GP, L.L.C.

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

Name	Age	Position with our General Partner

John M. Fox	63	Chairman of the Board of Directors
Frank M. Semple	52	President and Chief Executive Officer
Charles K. Dempster	61	Director
Arthur J. Denney	55	Director
Donald C. Heppermann	60	Director
William A. Kellstrom	62	Director
William P. Nicoletti	58	Director
John C. Mollenkopf	42	Senior Vice President, Southwest Business Unit
Randy S. Nickerson`	42	Senior Vice President, Corporate Development
Andrew L. Schroeder	45	Vice President, Treasurer, Secretary
Ted S. Smith	54	Vice President, Chief Accounting Officer
David L. Young	44	Senior Vice President, Northeast Business Unit

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

Frank M. Semple was appointed as President of both our general partner and MarkWest Hydrocarbon on November 1, 2003. Mr. Semple also became Chief Executive Officer of both our general partner and MarkWest Hydrocarbon on January 1, 2004. Prior to his appointment, Mr. Semple served as Chief Operating Officer of WilTel Communications, formerly Williams Communications. Prior to his tenure at WilTel Communications, he was the Senior Vice President/General Manager of Williams Natural Gas from 1995 to 1997 as well as Vice President of Marketing and Vice President of Operations and Engineering for Northwest Pipeline and Director of Product Movements and Division Manager for Williams Pipeline during his 22-year career with the Williams Companies. During his tenure at Williams Communications, he served on the board of directors for PowerTel Communications and the Competitive Telecommunications Association (Comptel). He currently serves on the board of directors for the Tulsa Zoo and the Children’s Medical Center. Mr. Semple holds a bachelor’s degree in mechanical engineering from the United States Naval Academy.

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

Arthur J. Denney has served as a member of our general partner’s Board of Directors since its inception in January 2002, and as a member of MarkWest Hydrocarbon’s Board of Directors since June 1996. Mr. Denney has served as Executive Vice President, Chief Operating Officer and Assistant Secretary of our general partner since January 2003 until his resignation in March 2004. Prior to that, Mr. Denney served as Executive Vice President of our

general partner since its inception in May 2002 and has served in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Denney served as MarkWest Hydrocarbon’s Senior Vice President of Engineering and Project Development since January 1997, as a member of its Board of Directors since June 1996 and as its Vice President of Engineering and Business Development since January 1990. Mr. Denney has more than 29 years of experience in gas gathering, gas processing and NGL businesses. From 1987 to 1990, Mr. Denney served as Manager of Business Development for Lair Petroleum, Inc. From 1974 to 1987, Mr. Denney was employed by Enron Gas Processing Co. and predecessor companies in a variety of positions, including seven years as its Rocky Mountain Regional Manager of its midstream businesses. Mr. Denney holds a bachelor’s degree in mechanical engineering and a master of business administration degree from the University of Nebraska.

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

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

William P. Nicoletti has served as a member of the Board of Directors of our general partner since its inception in May 2002. Mr. Nicoletti is Managing Director of Nicoletti & Company Inc., a private banking firm serving clients in the energy and transportation industries. In addition, Mr. Nicoletti has served as a Senior Advisor to the Energy Investment Banking Group of McDonald Investments Inc. From March 1998 until July 1999, Mr. Nicoletti was a Managing Director and co-head of Energy Investment Banking for McDonald Investments Inc. Prior to forming Nicoletti & Company Inc. in 1991, Mr. Nicoletti was a Managing Director and head of Energy Investment Banking for PaineWebber Incorporated. Previously, he held a similar position at E.F. Hutton & Company Inc. Mr. Nicoletti is a director and Chairman of the Audit Committee of Star Gas LLC, the general partner of Star Gas Partners, L.P, a retail propane and heating oil master limited partnership. He is also a director of Southwest Royalties, Inc., an oil and gas exploration and production company and Russell-Stanley Holdings, Inc., a manufacturer and marketer of steel and plastic industrial containers. Mr. Nicoletti is a graduate of Seton Hall University and received an MBA degree from Columbia University Graduate School of Business.

John C. Mollenkopf has served as Vice President, Business Development of our general partner since January 2003. Prior to that, he served as Vice President—Michigan Business Unit of our general partner since its inception in May 2002 and in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Mollenkopf was General Manager of the Michigan Business Unit of MarkWest Hydrocarbon since 1997. He joined MarkWest Hydrocarbon in 1996 as Manager, New Projects. From 1983 to 1996, Mr. Mollenkopf worked for ARCO Oil and Gas Company, holding various positions in process and project engineering, as well as operations

supervision. Mr. Mollenkopf holds a bachelor’s degree in mechanical engineering from the University of Colorado at Boulder.

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

Andrew L. Schroeder has served as Vice President and Treasurer of our general partner since February 2003. Prior to his appointment, he was Director of Finance/Business Development at Crestone Energy Ventures from 2001 through 2002. Prior to that Mr. Schroeder worked at Xcel Energy for two years as Director of Corporate Financial Analysis. Prior to that, he spent seven years working with various energy companies. He began his career with Touche, Ross & Co. and spent eight years in public accounting. Mr. Schroeder holds a master’s of taxation from the University of Denver and a bachelor’s degree in business from the University of Colorado. He is a Certified Public Accountant licensed in the state of Colorado.

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

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

Audit Committee Financial Expert

Each of the individuals serving on our Audit Committee satisfies the standards for independence of the AMEX and the SEC as they relate to audit committees. Our board of directors believes each of the members of the Audit Committee is financially literate. In addition, our board of directors has determined that Mr. Kellstrom is financially sophisticated and qualifies as an “audit committee financial expert” within the meaning of the regulations of the SEC.

Audit Committee Pre-Approval Policy

The Audit Committee pre-approves all audit and permissible non-audit services provided by the independent auditors on a case-by-case basis. These services may include audit services, audit-related services, tax services and other services. Our Chief Accounting Officer is responsible for presenting the Audit Committee with an overview of all proposed audit, audit-related, tax or other non-audit services to be performed by the independent auditors. The presentation must be in sufficient detail to define clearly the services to be performed. The Audit

Committee does not delegate its responsibilities to pre-approve services performed by the independent auditor to management or to an individual member of the Audit Committee. The Audit Committee may, however, from time to time delegate its authority to the Audit Committee Chairman, who reports on the independent auditor services approved by the Chairman at the next Audit Committee meeting.

Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics applicable to the persons serving as our directors, officers and employees, which includes the prompt disclosure to the SEC of a Current Report on Form 8-K of any waiver of the code for executive officers or directors approved by the board of directors. A copy of our Code of Business Conduct and Ethics, is available free of charge in print to any unitholder who sends a request to the office of the Secretary of MarkWest Energy Partners, L.P. at 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112-5000.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our general partner’s directors and executive officers, and persons who own more than 10% of any class of our equity securities registered under Section 12 of the Exchange Act, to file with the Securities and Exchange Commission (SEC) initial reports of ownership and reports of changes in ownership in such securities and other equity securities of our Company. SEC regulations also require directors, executive officers and greater than 10% unitholders to furnish us with copies of all Section 16(a) reports they file.

To our knowledge, based solely on review of the copies of such reports furnished to us and written representations that no other reports were required, we believe our directors, executive officers and greater than 10% unitholders complied with all Section 16(a) filing requirements during the year ended December 31, 2003, except for the following:

	No. of Late Reported Transactions	No. of Late Form 3 Filings	No. of Late Form 4 Filings
Mr. Fox	6	0	2
Mr. Semple	3	1	2
Mr. Heppermann	2*	0	2
Mr. Denney	1	0	1
Mr. Dempster	2	1	1
Mr. Mollenkopf	1	0	1

* Mr. Heppermann filed a late Form 4 related to a December 2002 grant of phantom units.

ITEM 11. EXECUTIVE COMPENSATION

Executive Compensation

The Partnership has no employees. It is managed by the officers of our general partner. Aside from restricted unit awards (discussed later), the executive officers of our general partner are compensated by MarkWest Hydrocarbon and do not receive compensation from our general partner or us for their services in such capacities. We reimburse MarkWest Hydrocarbon for a portion of their salaries.

The following table sets forth the cash and non-cash compensation earned for fiscal years 2003, 2002 and 2001 by each person who served as Chief Executive Officer of our general partner in 2003 and the three other highest paid officers, whose salary and bonus exceeded $100,000 for services rendered during 2003.

Our general partner was created in January 2002 and our initial public offering closed in May 2002, at which point we commenced reimbursing MarkWest Hydrocarbon for general and administrative expenses, including a portion of the Named Executive Officers’ compensation. Information included in the following table for the periods ended prior to May 24, 2002 is provided for comparability purposes.

Summary Compensation Table

	Annual Compensation					Long-Term Compensation
Name and Principal Positions	Fiscal Year	Salary ($) (1)		Bonus ($) (2)		Restricted Unit Awards ($) (3)		Other Compensation ($) (4)

John M. Fox	2003	$	190,515	$	27,148	$	26,875	$	15,674
Former President and Chief Executive Officer	2002	190,515		3,199		110,000		15,241
	2001	186,213		9,595		—		12,900

Frank M. Semple	2003	$	36,346	$	6,413	$	279,000	$	623
President and Chief Executive Officer	2002	—		—		—		—
	2001	—		—		—		—

Arthur J. Denney	2003	$	185,948	$	26,574	$	59,475	$	16,276
Former Senior Executive Vice President, Chief Operating, Officer and Assistant Secretary	2002	176,096		2,957		110,000		14,088
	2001	172,120		8,868		—		12,692

Randy S. Nickerson	2003	$	164,743	$	23,515	$	26,875	$	13,193
Senior Vice President, Corporate Development	2002	154,943		2,601		110,000		12,395
	2001	147,628		7,602		—		10,948

John C. Mollenkopf	2003	$	144,354	$	20,684	$	59,475	$	12,331
Senior Vice President, Business Development	2002	129,322		2,171		110,000		10,346
	2001	124,892		5,991		—		9,056

Donald C. Hepperman	2003	$	182,576	$	26,017	$	33,188	$	14,893
Former Chief Financial Officer	2002	23,173		—		—		843
	2001	—		—		—		—

(1) Represents actual salary earned in each respective fiscal year for services rendered on behalf of both the Partnership and MarkWest Hydrocarbon.

(2) Represents actual bonus earned in each respective fiscal year for services rendered on behalf of both the Partnership and MarkWest Hydrocarbon. Bonuses are paid to all employees in quarterly installments based on year-to-date performance in May, August, and December with the balance paid in March of the following year in accordance with provisions of MarkWest Hydrocarbon’s Incentive Compensation Plan.

(3) Represents the value of the executive officer’s restricted unit award (calculated by multiplying the closing market price of our common units on the date of grant by the number of units awarded). Messrs. Fox, Semple, Denney, Nickerson, Mollenkopf and Hepperman had unvested restricted units of 1,250, 7,500, 2,250, 1,250, 2,250 and 1,500, respectively at February 29, 2004. The restricted units vest over a period of four years, with 25% of the grant vesting at the end of each of the second and third years and 50% vesting at the end of the fourth year. The vesting may be accelerated upon achievement of certain goals.

(4) Represents actual MarkWest Hydrocarbon contributions under MarkWest Hydrocarbon’s 401(k) Savings and Profit Sharing Plan.

Non-Competition, Non-Solicitation and Confidentiality Agreement and Severance Plan

Except for Frank Semple, each of our general partner’s named executive officers is a party to a Non-Competition, Non-Solicitation and Confidentiality Agreement. As a result of signing the Non-Competition, Non-Solicitation and Confidentiality Agreement, the named executive officers are eligible for the 1997 Severance Plan. The Severance Plan provides for payment of benefits in the event that (i) the employee terminates his or her employment for “good reason” (as defined), (ii) the employee’s employment is terminated “without cause” (as defined), (iii) the employee’s employment is terminated by reason of death or disability or (iv) the employee voluntarily resigns. In the case of (i), (ii) and (iii) above, the employee shall be entitled to receive base salary and continued medical benefits for a period ranging from six months to twenty-four months, depending upon the employee’s status at the time of the termination. In the case of (iv) above, the employee shall be entitled to receive base salary for a period ranging from one month to six months and continued medical benefits for a period ranging from one month to six months. In either case, the aggregate amount of benefits paid to an employee shall in no event exceed twice the employee’s annual compensation during the year immediately preceding the termination.

Employment Agreement

Frank M. Semple

Mr. Semple entered into an executive employment agreement with Markwest Hydrocarbon on November 1, 2003, pursuant to which Mr. Semple serves as MarkWest Hydrocarbon’s President and Chief Executive Officer and pursuant to which the Board of Directors of MarkWest Hydrocarbon appointed Mr. Semple to serve as the President and Chief Executive Officer of our general partner. The employment agreement my be terminated by either Mr. Semple or Markwest Hydrocarbon at any time.

Under the employment agreement, Mr. Semple receives an annual base salary and is entitled to receive benefits for which employees and/or executive officers are generally eligible. In addition, Mr. Semple was awarded phantom units in our general partner under the general partner’s long term incentive plan and was awarded stock options under the MarkWest Hydrocarbon incentive stock option plan. Mr. Semple also agreed to purchase from MarkWest Hydrocarbon an interest in each of our general partner and the Partnership, subject to certain repurchase rights by MarkWest Hydrocarbon following the termination of his employment.

Under his employment agreement, in the event Mr. Semple’s employment is terminated without cause, or if he resigns for good reason, he is entitled to severance payments equal to his base salary for a period of thirty-six months. In addition, Mr. Semple is entitled to COBRA benefits for a period of twenty-four months. In the event Mr. Semple voluntarily resigns, he is entitled to receive severance payments equal to his base salary and COBRA benefits for a period of six months. In the event Mr. Semple is terminated for cause, he shall not be entitled to receive any severance or COBRA benefits.

Long-Term Incentive Plan

You should read Note 12 of the accompanying Notes to Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K for a complete description of our Long-Term Incentive Plan, which is incorporated herein by reference.

Reimbursement of Expenses of our General Partner

Prior to December 31, 2003 our general partner did not receive any management fee or other compensation for its management of MarkWest Energy Partners, L.P. Our general partner and its affiliates were reimbursed for expenses incurred on our behalf. These expenses included the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, us.

Effective January 1, 2004, we entered into a Services Agreement whereby MarkWest Hydrocarbon, Inc., will act in a management capacity rendering day-to-day business operations and administrative services to the Partnership. For such management services, MarkWest Hydrocarbon, Inc. will receive a $5,000 annual management fee.

Director Compensation

Officers or employees of our general partner who also serve as directors will not receive additional compensation. Each independent director receives an annual retainer of $12,000 and 500 restricted units per year. In addition, each independent director will receive compensation of $1,500 for in-person attendance and $700 for telephonic attendance at meetings of the board of directors or committees of the board of directors. The members of the audit and conflicts committees receive compensation of $1,000 for each committee meeting. Additionally, members of the audit and conflict committees receive an annual retainer of $3,000. Each independent director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

Compensation Committee Report

MarkWest Energy GP, L.L.C. has engaged MarkWest Hydrocarbon, Inc. and its employees to provide all necessary service for MarkWest Energy Partners, L. P. The board of directors for MarkWest Energy GP, L.L.C., in the exercise of its fiduciary duties, reviews and determines the terms on which such services rendered to MarkWest Energy Partners, L.P. are “fair and reasonable”. The compensation committee of MarkWest Energy GP, L.L.C is charged with the management and oversight of any incentive plan established by MarkWest Energy Partners, L.P., as well as the compensation (if any) paid by MarkWest Energy Partners, L.P. or MarkWest Energy GP, L.L.C. to any of their officers or employees (if any).

Commencing in 2004, reasonably necessary business operating and administrative expenses incurred by MarkWest Hydrocarbon on behalf of the Partnership will be reimbursed pursuant to the terms and conditions of the Services Agreement.

Compensation Committee of MarkWest Energy GP, L L.C.
Mr. Charles K. Dempster, Chairman
Mr. William A. Kellstrom
Mr. William P. Nicoletti

PERFORMANCE GRAPH

Source: FactSet.

(a) Peer group companies include Crosstex Energy, L.P., and Atlas Pipeline Partners, L.P. Crosstex Energy, L.P., began trading on 12/12/02. The index is weighted based on market capitalization. Peer group companies were selected based on their business mix and market capitalization.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information, as of December 31, 2003, regarding our common units that may be issued upon conversion of outstanding restricted units granted under our Long-Term Incentive Plan to employees and directors of our general partner and employees of its affiliates who perform services for us. For more information about this plan, which did not require approval by the Partnership’s limited partners, you should read Note 12 of the accompanying Notes to Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference.

Equity Compensation Plan Information(1)

	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Plan category	(a)	(b)		(c)
Equity compensation plans approved by security holders	—	$	—	—
Equity compensation plans not approved by security holders	34,496	—		441,746

Total	34,496	$	—	441,746

(1) The amount in column (a) of this table reflects only restricted units granted but not vested as of December 31, 2003. No unit options have been granted. No value is shown in column (b) of the table, since the restricted units do not have an exercise price.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units as of February 29, 2004 held by beneficial owners of 5% or more of the units, by directors of our general partner, by each named executive officer listed in the summary compensation table included in this Form 10-K and by all directors and officers of our general partner as a group.

Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Units Beneficially Owned
MarkWest Energy GP, L.L.C.	—	—		—	—		—
MarkWest Hydrocarbon, Inc.(1)	—	—		2,469,496	82.3	%	35.3	%
John M. Fox(2)	24,750		*	2,489,122	83.0	%	35.9	%
Tortoise MWEP, L.P.	—	—		500,000	16.7	%	7.1	%
Frank M. Semple.	—	—		5,000		*		*
Arthur J. Denney	3,250		*	4,626		*		*
Donald C. Heppermann	6,000		*	4,000		*		*
Randy S. Nickerson	5,625		*	4,626		*		*
John C. Mollenkopf	1,250		*	4,626		*		*
William A. Kellstrom	3,125		*	—	—			*
William P. Nicoletti	2,750		*	—	—			*
Charles K. Dempster	750		*	—	—		—
All directors and executive officers as a group (9 persons)	47,500	1.2	%	2,512,000	83.7	%	36.6	%
Other(3)	188		*	3,000		*		*

* Less than 1%

(1) Includes securities owned directly and indirectly through subsidiaries.

(2) Includes 4,626 subordinated units owned directly by Mr. Fox, 2,473,129 subordinated units owned by MarkWest Hydrocarbon and its subsidiaries, and approximately 15,000 subordinated units owned by Tortoise MWEP, L.P. in which Mr. Fox owns an equity interest. As of December 31, 2003, Mr. Fox beneficially owned approximately 50% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’s Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003 and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the subordinated units owned by MarkWest Hydrocarbon.

(3) Held by two key officers of MarkWest Hydrocarbon and one key officer of our general partner.

The following table sets forth the beneficial ownership of our general partner as of February 29, 2004, held by MarkWest Hydrocarbon, the directors of our general partner, each named executive officer and by all directors and officers of our general partner as a group.

Name of Beneficial Owner	Percentage of Limited Liability Company Interests Owned
MarkWest Hydrocarbon, Inc.	90.2	%
John M. Fox(1)	91.8
Frank M. Semple	2.0
Arthur J. Denney	1.6
Donald C. Heppermann	1.0
Randy S. Nickerson	1.6
John C. Mollenkopf	1.6
William A. Kellstrom	0.0
William P. Nicoletti	0.0
Charles K. Dempster	0.0
All directors and executive officers as a group (9 persons)	9.4
Other(2)		*

* Less than 1%

(1) Includes a 1.6% ownership interest held directly by Mr. Fox and a 89.7% ownership interest held by MarkWest Hydrocarbon. As of December 31, 2003, Mr. Fox beneficially owned approximately 50% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’s Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003, and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the ownership interests owned by MarkWest Hydrocarbon.

(2) Held by two key officers of MarkWest Hydrocarbon and of our general partner.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

MarkWest Hydrocarbon controls our operations through its ownership of our general partner, as well as a significant limited partner ownership interest in us through its ownership of a majority of our subordinated units. As of January 12, 2004, affiliates of MarkWest Hydrocarbon, in the aggregate, owned a 44.1% interest in the Partnership, consisting of 2,500,000 subordinated units and a 2% general partner interest.

Distributions and Payments to our General Partner and its Affiliates

Our general partner owns the 2% general partner interest and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts we distribute in excess of $0.55 per unit, 23% of the amounts we distribute in excess of $0.625 per unit and 48% of amounts we distribute in excess of $0.75 per unit.

For 2003, our general partner did not receive any management fee or other compensation in connection with its management of our business, but was reimbursed for all direct and indirect expenses incurred on our behalf.

Agreements with MarkWest Hydrocarbon

We entered into various agreements with MarkWest Hydrocarbon on May 24, 2002, the closing of our initial public offering. Specifically, we entered into:

• an Omnibus Agreement;

• a Gas Processing Agreement;

• a Pipeline Liquids Transportation Agreement;

• a Fractionation, Storage and Loading Agreement;

• a Natural Gas Liquids Purchase Agreement; and

Effective January 1, 2004, we entered into a Services Agreement whereby MarkWest Hydrocarbon, Inc. will act in a management capacity rendering day-to-day business operations and administrative services to the Partnership.

These agreements were not the result of arm’s-length negotiations.

Omnibus Agreement

Concurrently with the closing of our initial public offering, we entered into an agreement with MarkWest Hydrocarbon, our general partner and our operating company that governs potential competition and indemnification obligations among us and the other parties to the agreement.

Services. Pursuant to the omnibus agreement, we have designated each current or future employee of MarkWest Hydrocarbon who fulfills a job function on our behalf as our agent, with full power and authority to perform such job function.

Non-Competition Provisions. MarkWest Hydrocarbon agreed, and caused its affiliates to agree, for so long as MarkWest Hydrocarbon controls the general partner, not to engage in, whether by acquisition, construction or otherwise, the business of processing natural gas and transporting, fractionating and storing NGLs. This restriction will not apply to:

• the gathering of natural gas;

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

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

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

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

Indemnification Provisions. Under the omnibus agreement, MarkWest Hydrocarbon has agreed to indemnify us for three years after the closing of our initial public offering against certain environmental and toxic tort liabilities associated with the operation of the assets contributed to us by MarkWest Hydrocarbon and occurring before the closing date of our initial public offering. However, MarkWest Hydrocarbon will have no obligation to indemnify us until our losses exceed $0.5 million and MarkWest Hydrocarbon’s maximum liability will not exceed $5 million. MarkWest Hydrocarbon will also specifically indemnify us against environmental and toxic tort liabilities to the extent that MarkWest Hydrocarbon is entitled to and receives indemnification from any third party. Please read “Business—Environmental Matters—Ongoing Remediation and Indemnification from Columbia Gas” included in Item 1 of this Form 10-K, which is incorporated herein by reference.

MarkWest Hydrocarbon will also indemnify us for liabilities relating to:

• certain specified legal actions pending against MarkWest Hydrocarbon or its affiliates at the closing of our initial public offering;

• certain defects in title to the assets contributed to us and failure to obtain certain consents and permits necessary to conduct our business that arise within three years after the closing of our initial public offering;

• events and conditions associated with any assets retained by MarkWest Hydrocarbon or its affiliates; and

• certain income tax liabilities attributable to the operation of the assets contributed to us prior to the time that they were contributed.

License Provisions. Pursuant to the omnibus agreement, MarkWest Hydrocarbon granted us nontransferable, nonexclusive, royalty-free right to use the name and mark “MarkWest.”

The omnibus agreement may not be amended without the concurrence of the conflicts committee. The omnibus agreement, other than the indemnification provisions, will terminate if:

• a change of control of MarkWest Hydrocarbon occurs; or

• we are no longer an affiliate of MarkWest Hydrocarbon.

Gas Processing Agreement

Concurrently with the closing of our initial public offering, we entered into a Gas Processing Agreement with MarkWest Hydrocarbon that governs the parties’ obligations with respect to the processing of natural gas at our Kenova, Boldman and Cobb processing plants.

Gas Processing Services. Under the Gas Processing Agreement, until 2012 and on a year-to-year basis thereafter, MarkWest Hydrocarbon has agreed to:

• commit to deliver, at specified locations, all of the natural gas that MarkWest Hydrocarbon has the right to process or have processed at our Kenova, Boldman or Cobb processing plants under its operating agreements with Columbia Gas; and

• furnish all of the natural gas used as fuel in the operation of our Kenova, Boldman and Cobb processing plants.

We have agreed to:

• accept and process, at our sole risk and expense, all of the natural gas that MarkWest Hydrocarbon delivers to our Kenova, Boldman or Cobb processing plants up to the then-existing design capacity of each processing plant;

• redeliver, for the account of MarkWest Hydrocarbon, or for the parties designated by MarkWest Hydrocarbon, the residue gas to Columbia Gas’ transmission facilities;

• deliver all NGLs recovered or extracted at each processing plant to MarkWest Hydrocarbon for further transportation to our Siloam fractionator facility;

• in the event the volumes delivered to any processing plant exceed the then-existing plant design capacity, use our reasonable, diligent efforts to process all the natural gas delivered by MarkWest Hydrocarbon to, or as near as possible to, the residue gas quality specifications; and

• if at any time the volumes delivered to a processing plant exceed by 5% the daily average of volume that can be processed to residue gas for 60 days within a 90 day period, promptly begin and diligently complete the necessary work to increase the capacity of a processing plant.

As compensation for providing these services, MarkWest Hydrocarbon pays us a monthly gas processing fee based on the natural gas volumes delivered at our Kenova, Boldman and Cobb processing plants. A portion of this gas-processing fee is annually adjusted on each anniversary of the effective date to reflect changes in the Producers Price Index for Oil and Gas Field Services.

Indemnification Provisions. Under the Gas Processing Agreement, MarkWest Hydrocarbon has agreed to indemnify us from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the natural gas (except to the extent caused by our gross negligence or willful conduct). MarkWest Hydrocarbon will be in possession and control of the natural gas until it is delivered to one of our processing facilities and after our operating company redelivers the residue gas to MarkWest Hydrocarbon.

We have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the natural gas (except to the extent caused by MarkWest Hydrocarbon’s gross negligence or willful conduct). We will be in possession and control of the natural gas after it is delivered to one of our processing facilities and until we redeliver the residue gas to MarkWest Hydrocarbon.

We will also pay MarkWest Hydrocarbon a penalty of $5,000 per day (unless MarkWest Hydrocarbon can establish actual damages in excess of $5,000 per day) if we fail to process the natural gas at any of our processing

plants to meet the agreed specifications or interrupt the NGL production process, unless the reason for the failure or interruption is:

• the suspension of operations necessary for turnaround time, maintenance or repair time, not to exceed 30 days per year;

• conditions of force majeure; or

• reasons related to safety considerations and the integrity of our processing plants.

If we interrupt processing at any of our processing plants for any reason for 30 consecutive days without making a good faith effort to resume processing as soon as reasonably possible, or, after notification from MarkWest Hydrocarbon, we are otherwise in default of any of the terms of the Gas Processing Agreement for 25 days, then MarkWest Hydrocarbon, in its sole discretion and in addition to any other available legal or equitable remedies, may:

• satisfy any and all of our obligations and be reimbursed by us the amount paid, attorneys fees and annual interest;

• seek interlocutory equitable relief and perform or have performed our obligations at our sole risk, liability, cost and expense; or

• require us to specifically perform our obligations.

Pipeline Liquids Transportation Agreement

Concurrently with the closing of our initial public offering, we entered into a Pipeline Liquids Transportation Agreement with MarkWest Hydrocarbon that governs the parties’ obligations with respect to the transportation of mixed NGLs to our Siloam fractionation facility.

Transportation Services. Under this Transportation Agreement, until 2012 and on a year-to-year basis thereafter, MarkWest Hydrocarbon delivers, at specified locations, all of its NGLs acquired from our Kenova processing facility, and any of its NGLs it desires to deliver from our Boldman extraction facility, or from other extraction plants or sources in the Appalachian region.

We maintain and operate our pipeline system, at our sole risk and expense, to transport all of the NGLs that MarkWest Hydrocarbon delivers from our extraction facilities to our Siloam fractionation facility.

As compensation for providing these services, MarkWest Hydrocarbon pays us a monthly transportation fee based on the number of gallons of the NGLs transported to our Siloam fractionation facility. A portion of this transportation fee is annually adjusted on January 1 of each year to reflect changes in the Producers Price Index for Oil and Gas Field Services. Under the agreement, MarkWest Hydrocarbon will incur all of the incidental losses incurred at our facilities, or the losses or gains due to variations in measurement equipment.

Indemnification Provisions. Under the Transportation Agreement, MarkWest Hydrocarbon has agreed to indemnify us from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the NGLs (except to the extent caused by our gross negligence or willful conduct). MarkWest Hydrocarbon will be in possession and control of the NGLs until they are delivered to our pipeline system.

We have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the NGLs (except to the extent caused by MarkWest Hydrocarbon’s gross negligence or willful conduct). We will be in possession and control of the NGLs after they are delivered to our pipeline system.

Fractionation, Storage and Loading Agreement

Concurrently with the closing of our initial public offering, we entered into a Fractionation, Storage and Loading Agreement with MarkWest Hydrocarbon that governs the parties’ obligations with respect to the unloading and fractionation of NGLs, and the storage of the NGL products at our Siloam facility.

Services. Under the Fractionation, Storage and Loading Agreement, until 2012 and on a year-to-year basis thereafter, MarkWest Hydrocarbon has agreed to commit to deliver, at specified locations, all of the mixed NGLs produced at our Kenova, Boldman or Cobb processing plants for fractionation at our Siloam fractionation facility.

We have agreed to:

• unload any NGLs that MarkWest Hydrocarbon delivers to our Siloam facility by railcar;

• accept and fractionate into NGL products all of the NGLs that MarkWest Hydrocarbon delivers;

• furnish and be responsible for all of the fuel needed in the operation of our Siloam facility;

• operate, maintain and, if necessary, replace all facilities for loading the NGL products for shipment;

• lease tracking rights on our Siloam railroad siding to MarkWest Hydrocarbon for no additional charge;

• be, at our sole risk, responsible for loading the finished NGL products for shipments, as directed by MarkWest Hydrocarbon; and

• at the direction of MarkWest, store the finished NGL products in underground storage caverns at our Siloam facility and, if also directed by MarkWest Hydrocarbon, withdraw the products from such storage caverns.

As compensation for providing our fractionating, loading and above ground storage services, MarkWest Hydrocarbon pays us a monthly fractionation fee based on the number of gallons delivered to us for fractionation. As compensation for our storage of the NGL products in underground storage caverns, MarkWest Hydrocarbon pays us an annual storage fee. And, as compensation for unloading any NGLs that MarkWest Hydrocarbon delivers to us by railcar, MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons unloaded. A portion of each of the above fees is annually adjusted on January 1 of each year to reflect changes in the Producers Price Index for Oil and Gas Field Services. Under the agreement, MarkWest Hydrocarbon incurs all of the incidental losses incurred at our facilities, or the losses or gains due to variations in measurement equipment.

Indemnification Provisions. Under the Fractionation, Storage and Loading Agreement, MarkWest Hydrocarbon has agreed to indemnify us from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the NGLs or NGL products (except to the extent caused by our gross negligence or willful conduct). MarkWest Hydrocarbon will be in possession and control of the NGLs until they are delivered to our Siloam facility, and of the NGL products after we load them into transportation facilities provided by MarkWest Hydrocarbon.

We have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the NGLs or NGL products (except to the extent caused by MarkWest Hydrocarbon’s gross negligence or willful conduct). We will be in possession and control of the NGLs after they are delivered to our Siloam facility and of the NGL products until we load them into transportation facilities provided by MarkWest Hydrocarbon.

Natural Gas Liquids Purchase Agreement

Concurrently with the closing of our initial public offering, we entered into a Natural Gas Liquids Purchase Agreement with MarkWest Hydrocarbon that governs the parties’ obligations with respect to the sale and purchase of NGL products we acquire under the Gas Processing (Maytown) Agreement between Equitable and MarkWest Hydrocarbon, which were assigned to us, as well as any other NGL products we acquire.

Purchase and Sale. Under the Natural Gas Liquids Purchase Agreement, until 2012, we have agreed to commit to deliver to MarkWest Hydrocarbon all of the NGL products produced from the NGLs we acquire under the Maytown Agreement together with such other NGLs to be sold at our facility. MarkWest Hydrocarbon has agreed to receive and purchase all of these NGL products.

As consideration for the sale of NGL products, MarkWest Hydrocarbon pays us a monthly fee equal to the Net Sales Price per gallon (determined under the Maytown Agreement), times the numbers of gallons of NGL products contained in our NGLs.

Indemnification Provisions. Under the Natural Gas Liquids Purchase Agreement, MarkWest Hydrocarbon has agreed to indemnify us from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the NGL products (except to the extent caused by our gross negligence or willful misconduct). As between the parties, MarkWest Hydrocarbon will be in possession and control of the NGL products after they are delivered to MarkWest Hydrocarbon at the designated delivery point.

We have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the NGL products (except to the extent caused by MarkWest Hydrocarbon’s gross negligence or willful misconduct). As between the parties, we will be in possession and control of the NGL products until we deliver them to MarkWest Hydrocarbon at the designated delivery point.

Services Agreement

MarkWest Hydrocarbon agreed to act in a management capacity rendering day-to-day operational, business and asset management, accounting, personnel and related administrative services to the Partnership.

The Partnership is obligated to reimburse MarkWest Hydrocarbon for all documented expenses incurred on behalf of the Partnership and which are expressly designated as reasonably necessary for the performance of the prescribed duties and specified functions.

Relationship of a Director of our General Partner with MarkWest Hydrocarbon

William P. Nicoletti, who serves as a member of our general partner’s board of directors, is a member of the board of directors of Star Gas LLC, the general partner of Star Gas Partners, L.P., a retail propane and heating oil master limited partnership. Star Gas is a significant customer of MarkWest Hydrocarbon, and accounted for approximately 7% of its revenues for the year ended December 31, 2003.

PART IV

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

For the year ended December 31, 2003 and 2002, PricewaterhouseCoopers LLP’s accounting fees and services (in thousands) were as follows:

	2003	2002
Audit fees	$167	$116
Audit-related fees:
Pinnacle acquisition	218	—
Michigan Crude Pipeline acquisition	183	—
Sarbanes-Oxley	6	—
401(k) Plan	13	—
Risk management review	50	—
Review of Registration Statement on Form S-1, including comfort letter procedures	283	248
	753	248

Tax fees	259	185
All other fees	1	—
Total accounting fees and services	$1,180	$549

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) The following documents are filed as part of this report:

(1) Financial Statements:

You should read the Index to Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K for a list of all financial statements filed as a part of this report, which is incorporated herein by reference.

(2) Financial Statement Schedules: None required.

(3) Exhibits:

Exhibit Number		Description

2.1 (3)		Purchase Agreement dated as of March 24, 2003, among PNG Corporation, Energy Spectrum Partners LP, MarkWest Energy GP, L.L.C., MW Texas Limited, L.L.C. and MarkWest Energy Partners, L.P.

2.2 (3)		Plan of Merger entered into as of March 28, 2003, by and among MarkWest Blackhawk L.P., MarkWest Pinnacle L.P., MarkWest PNG Utility L.P., MarkWest Texas PNG Utility L.P., Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company and Bright Star Gathering, Inc.

2.3 (4)		Asset Purchase and Sale Agreement dated as of November 18, 2003, by and between American Central Western Oklahoma Gas Company, L.L.C., MarkWest Western Oklahoma Gas Company, L.L.C. and American Central Gas Technologies, Inc.

2.4 (5)		Purchase and Sale Agreement, dated as of November 7, 2003, by and between Shell Pipeline Company, LP and Equilon Enterprises L.L.C., dba Shell Oil Products US, and MarkWest Michigan Pipeline Company, L.L.C.

3.1 (1)		Certificate of Limited Partnership of MarkWest Energy Partners, L.P.

3.2 (6)		Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated as of May 24, 2002.

3.3 (1)		Certificate of Formation of MarkWest Energy Operating Company, L.L.C.

3.4 (6)		Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C., dated as of May 24, 2002.

3.5 (1)		Certificate of Formation of MarkWest Energy GP, L.L.C.

3.6 (6)		Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of May 24, 2002.

4.1 (7)		Purchase Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.

4.2 (7)		Registration Rights Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.

Exhibit Number		Description

10.1 (4)		Credit Agreement dated as of May 20, 2002, among MarkWest Energy Operating Company, L.L.C (as the Borrower), MarkWest Energy Partners, L.P. (as a Guarantor), and various lenders.

10.2 (4)		Amended and Restated Credit Agreement dated as of December 1, 2003, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, RoyalBank of Canada, as Administrative Agent, Bank One, NA, as Syndication Agent, and Fortis Capital Corp., as Documentation Agent, to the $140,000,000 Senior Credit Facility.

10.3 (6)		Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002, among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C.; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy Appalachia, L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc.

10.4 (6)		MarkWest Energy GP, L.L.C. Long-Term Incentive Plan.

10.5 (6)		First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan.

10.6 (6)		Omnibus Agreement dated of May 24, 2002, among MarkWest Hydrocarbon, Inc.; MarkWest Energy GP, L.L.C.; MarkWest Energy Partners, L.P.; and MarkWest Energy Operating Company, L.L.C.

10.7 (6)+		Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.8 (6)+		Gas Processing Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.9 (6)+		Pipeline Liquids Transportation Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.10 (6)		Natural Gas Liquids Purchase Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.11 (6)+		Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.

10.12 (6)		Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.

10.13 *		Services Agreement

21.1 (8)		List of subsidiaries

23.1*		Consent of PricewaterhouseCoopers LLP

31.1*		Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act

31.2*		Chief Accounting Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act

Exhibit Number		Description

31.3*		Vice President, Treasurer and Secretary Certification Pursuant to Section 13a-14 of the Securities Exchange Act

32.1*		Certification of Chief Executive Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Certification of Chief Accounting Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.3*		Certification of Vice President, Treasurer and Secretary of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1) Incorporated by reference to the Registration Statement (No. 33-81780) on Form S-1, filed January 31, 2002.

(2) Incorporated by reference to previously filed with Amendment No. 6 to Form S-1, (No. 33-81780) filed May 14, 2002.

(3) Incorporated by reference to the Current Report on Form 8-K filed April 14, 2003.

(4) Incorporated by reference to the Current Report on Form 8-K filed December 16, 2003.

(5) Incorporated by reference to the Current Report on Form 8-K filed December 31, 2003.

(6) Incorporated by reference to the Current Report on Form 8-K filed June 7, 2002.

(7) Incorporated by reference to the Current Report on Form 8-K filed June 19, 2003.

(8) Incorporated by reference to the Current Report on Form 8-K, Post Effective Amendment No. 1 to Form S-1 (No. 333-111339) filed January 12, 2004.

+ Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.

* Filed herewith.

(b) Reports on Form 8-K

• A Current Report on Form 8-K was filed with the SEC under item 5 of Form 8-K on October 23, 2003 to announce the resignation of John M. Fox, the then Chairman, President and Chief Executive Officer of MarkWest Hydrocarbon and of MarkWest Energy GP, L.L.C., the general partner of the Partnership, as President, effective November 1, 2003, and as Chief Executive Officer effective December 31, 2003, and the appointment of Frank M. Semple in those positions subsequent to Mr. Fox’s resignation.

• A Current Report on Form 8-K was filed with the SEC under item 12 of Form 8-K on November 5, 2003 to announce the Partnership’s consolidated financial results of operations for the quarter ended September 30, 2003.

• A Current Report on Form 8-K was furnished with the SEC under item 2 of Form 8-K on December 16, 2003 to announce the Partnership’s acquisition of certain assets of American Central Western Oklahoma Gas Company, L.L.C.

• A Current Report on Form 8-K was furnished with the SEC under item 9 of Form 8-K on December 19, 2003 to announce the Partnership’s filing of a Registration Statement on Form S-1 containing financial information with respect to its recent acquisitions of (i) substantially all of the assets of American Central Western Oklahoma Gas Company, L.L.C., which closed on December 1, 2003, and (ii) the Michigan crude gathering pipeline assets from a subsidiary of Shell, which closed on December 18, 2003.

• A Current Report on Form 8-K/A was filed with the SEC under items 2 and 7 of Form 8-K on December 16, 2003 to announce the Partnership’s acquisition of certain assets of American Central Western Oklahoma Gas Company, L.L.C. Included with the Form 8-K were certain audited financial statements of American Central Western Oklahoma Gas Company, L.L.C. and related pro forma financial information.

• A Current Report on Form 8-K was filed with the SEC under items 2 and 7 of Form 8-K on December 31, 2003 to announce the Partnership’s acquisition of certain assets of the Michigan Crude Oil Pipeline System from Shell Pipeline Company, LP and Equilon Enterprises, LLC (dba Shell Oil Products US). Included with the Form 8-K were certain audited financial statements of the Michigan Crude Oil Pipeline System and related pro forma financial information..

SIGNATURES

Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	MarkWest Energy Partners, L.P.
	(Registrant)

	By: MarkWest Energy GP, L.L.C.,
	Its General Partner

Date: March 15, 2004	By:	/s/Frank M. Semple
		Frank M. Semple
		President and Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities with MarkWest Energy GP, L.L.C., the General Partner of MarkWest Energy Partners, L.P., the Registrant, and on the dates indicated.

Date: March 15, 2004	By:	/s/Frank M. Semple
		Frank M. Semple
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: March 15, 2004	By:	/s/Ted S. Smith
		Ted S. Smith
		Chief Accounting Officer
		(Principal Accounting Officer)

Date: March 15, 2004	By:	/s/Andrew L. Schroeder
		Andrew L. Schroeder
		Vice President, Treasurer and Secretary
		(Principal Financial Officer)

Date: March 15, 2004	By:	/s/John m. Fox
		John M. Fox
		Chairman of the Board and Director

Date: March 15, 2004	By:	/s/Charles K. Dempster
		Charles K. Dempster
		Director

Date: March 15, 2004	By:	/s/Arthur J. Denney
		Arthur J. Denney
		Director

Date: March 15, 2004	By:	/s/ William A. Kellstrom
		William A. Kellstrom
		Director

Date: March 15, 2004	By:	/s/ Donald C. Heppermann
		Donald C Heppermann
		Director

Date: March 15, 2004	By:	/s/William P. Nicoletti
		William P. Nicoletti
		Director

Exhibit Number		Exhibit Index

2.1 (3)		Purchase Agreement dated as of March 24, 2003, among PNG Corporation, Energy Spectrum Partners LP, MarkWest Energy GP, L.L.C., MW Texas Limited, L.L.C. and MarkWest Energy Partners, L.P.

2.2 (3)		Plan of Merger entered into as of March 28, 2003, by and among MarkWest Blackhawk L.P., MarkWest Pinnacle L.P., MarkWest PNG Utility L.P., MarkWest Texas PNG Utility L.P., Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company and Bright Star Gathering, Inc.

2.3 (4)		Asset Purchase and Sale Agreement dated as of November 18, 2003, by and between American Central Western Oklahoma Gas Company, L.L.C., MarkWest Western Oklahoma Gas Company, L.L.C. and American Central Gas Technologies, Inc.

2.4 (5)		Purchase and Sale Agreement, dated as of November 7, 2003, by and between Shell Pipeline Company, LP and Equilon Enterprises L.L.C., dba Shell Oil Products US, and MarkWest Michigan Pipeline Company, L.L.C.

3.1 (1)		Certificate of Limited Partnership of MarkWest Energy Partners, L.P.

3.2 (6)		Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated as of May 24, 2002.

3.3 (1)		Certificate of Formation of MarkWest Energy Operating Company, L.L.C.

3.4 (6)		Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C., dated as of May 24, 2002.

3.5 (1)		Certificate of Formation of MarkWest Energy GP, L.L.C.

3.6 (6)		Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of May 24, 2002.

4.1 (7)		Purchase Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.

4.2 (7)		Registration Rights Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.

Exhibit Number		Exhibit Index

10.1 (4)		Credit Agreement dated as of May 20, 2002, among MarkWest Energy Operating Company, L.L.C (as the Borrower), MarkWest Energy Partners, L.P. (as a Guarantor), and various lenders.

10.2 (4)		Amended and Restated Credit Agreement dated as of December 1, 2003, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, RoyalBank of Canada, as Administrative Agent, Bank One, NA, as Syndication Agent, and Fortis Capital Corp., as Documentation Agent, to the $140,000,000 Senior Credit Facility.

10.3 (6)		Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002, among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C.; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy Appalachia, L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc.

10.4 (6)		MarkWest Energy GP, L.L.C. Long-Term Incentive Plan.

10.5 (6)		First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan.

10.6 (6)		Omnibus Agreement dated of May 24, 2002, among MarkWest Hydrocarbon, Inc.; MarkWest Energy GP, L.L.C.; MarkWest Energy Partners, L.P.; and MarkWest Energy Operating Company, L.L.C.

10.7 (6)+		Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.8 (6)+		Gas Processing Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.9 (6)+		Pipeline Liquids Transportation Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.10 (6)		Natural Gas Liquids Purchase Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.11 (6)+		Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.

10.12 (6)		Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.

10.13 *		Services Agreement

21.1 (8)		List of subsidiaries

23.1*		Consent of PricewaterhouseCoopers LLP

31.1*		Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act

31.2*		Chief Accounting Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act

Exhibit Number		Exhibit Index

31.3*		Vice President, Treasurer and Secretary Certification Pursuant to Section 13a-14 of the Securities Exchange Act

32.1*		Certification of Chief Executive Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Certification of Chief Accounting Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.3*		Certification of Vice President, Treasurer and Secretary of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.