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, 2004.

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 1-31239

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware		27-0005456
(State or other jurisdiction of incorporation or organization)		(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 o No ý

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

Indicate by check mark whether the registrant is an accelerated 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, 2004, was approximately $148,543,000.

As of May 31, 2005, the number of the registrant’s Common Units and Subordinated Units were 7,642,697 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 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
Item 9B.	Other Information

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 and Related Stockholder Matters
Item 13.	Certain Relationships and Related Transactions
Item 14.	Principal Accountant Fees and Expenses

PART IV
Item 15.	Exhibits and Financial Statement Schedules

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
Bbl/d		barrels per day
Bcf		one billion cubic feet of natural gas
Btu		one British thermal unit, an energy measurement
Gal/d		gallons per day
Gross Margin		revenues less purchased product costs
Mcf		one thousand cubic feet of natural gas
Mcf/d		one thousand cubic feet of natural gas per day
MMBtu		one million British thermal units, an energy measurement
MMcf		one million cubic feet of natural gas
MMcf/d		one million cubic feet of natural gas per day
NGLs		natural gas liquids, such as propane, butanes and natural gasoline
NA		not applicable
Tcf		one trillion cubic feet of natural gas

Explanatory Note

We have determined that, in certain cases, we did not comply with generally accepted accounting principles in the preparation of our 2002 and 2003 consolidated financial statements and, accordingly, we have restated our 2002 and 2003 annual financial statements in this 2004 Annual Report on Form 10-K. The Partnership has also filed Form 10-Q/A’s for the first three quarters of 2004 to restate its quarterly financial statements for 2003 and 2004. The Partnership has determined that earlier issued financial statements for the years 2002 and 2003 and the first three quarters of 2003 and 2004 should be restated to reflect compensation expense in our financial statements for the sale of subordinated Partnership units and interests by MarkWest Energy GP, LLC, our general partner, to certain employees and directors of the Partnership’s parent company, MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon”) from 2002 through 2004 and for an error in accounting for natural gas inventory in the fourth quarter of 2003. The Partnership is filing contemporaneously with this Form 10-K, its quarterly reports on Form 10-Q/A for the quarterly periods ended March 31, 2004, June 30, 2004 and September 30, 2004.

As discussed more fully in Note 19, “Restatement of Consolidated Financial Statement”, to the consolidated financial statements in Item 8 of this Form 10-K, the restatements have been made to account for the sale by Markwest Hydrocarbon of a portion of its general partnership interests in our general partner to certain employees and directors of the general partner, and the sale by MarkWest Hydrocarbon of its subordinated units of the Partnership to certain employees and directors of MarkWest Hydrocarbon as compensatory arrangements consistent with the guidance in Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”) and Emerging Issues Task Force (“EITF”) No. 95-16, Accounting for Stock Compensation Arrangements with Employer Loan Features under APB Opinion No. 25. This guidance requires MarkWest Hydrocarbon to record compensation expense based on the market value of the subordinated Partnership units and the formula value of the general partner interests held by these employees and directors at the end of each reporting period. Under Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity, a portion of this compensation expense was allocated to the Partnership for services rendered by the employees and directors on its behalf. These transactions were previously reflected as sales of assets.

The Partnership has also restated revenue for 2003 by $0.1 million to record natural gas inventory at cost. Previously the inventory was incorrectly identified as a pipeline imbalance and was recorded at fair value.

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,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements.

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

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

• Our ability to successfully integrate our recent or future acquisitions;

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

• Our substantial debt and other financial obligations could adversely impact our financial condition;

• 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 natural gas, including the effectiveness of any hedging activities;

• Competition from other NGL processors, incl uding major energy companies;

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

• Our ability to identify and complete grass roots projects or acquisitions complementary to our business; and

• Our ability to raise sufficient capital to execute our business plan through borrowing or issuing equity.

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.

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 May 24, 2002, the closing date of our initial public offering (the IPO). We are engaged in the gathering, processing and transmission of natural gas, 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 six acquisitions completed during 2003 and 2004, the Partnership has expanded its natural gas gathering, processing and transmission geographic coverage to the southwest United States. In addition, one of our acquisitions has allowed us to enter 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.”

Our midstream services assets are grouped into five geographically reportable business segments—East Texas, Oklahoma, Other Southwest, Appalachia and Michigan. You should read the following discussion in conjunction with our Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K.

We were formed by MarkWest Hydrocarbon to acquire most of its natural gas gathering, processing and transmission, and NGL transportation, fractionation and storage assets and to acquire similar assets or businesses located across North America. 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 both equity and debt 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. In addition, our limited partnership structure provides tax advantages to our unitholders.

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, 2004, MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 25% interest in the Partnership, consisting of 2,469,496 subordinated limited partner units, which represents a 23% interest in the Partnership, and 90% of the general partner interest, which represents a 2% interest in the Partnership. MarkWest Hydrocarbon also is our largest customer, accounting for 20% of our revenues and 32% of our gross margin for the year ended December 31, 2004. Our reliance on MarkWest Hydrocarbon has diminished over time with our six recent acquisitions and is expected to continue to diminish as we continue to acquire assets and increase our customer and business diversification. Further details on our relationship with MarkWest Hydrocarbon are discussed in this Item 1 under the heading “Our Relationship with MarkWest Hydrocarbon, Inc”.

Overview

We are a 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 limits our commodity price exposure and provides us with a relatively stable base of cash flows. We have five primary geographic areas of operation, three in the Southwest, one in Appalachia and one in Michigan:

• Southwest.

• East Texas. On July 30, 2004, we acquired certain natural gas gathering and processing assets located in east Texas from American Central Eastern Texas Gas Company, Limited Partnership. The assets, which we refer to as our East Texas System, currently consist of natural gas gathering system pipelines, natural gas gathering system pipelines currently under construction, centralized compressor stations and a natural gas processing facility, also currently under construction. The East Texas System is located in Panola County and services the Carthage Field, one of Texas’ largest onshore natural gas fields. Producing formations in Panola County currently consist of the Cotton Valley, Pettit and Travis Peak formations which form one of the largest natural gas producing regions in the United States. The Carthage Field has approximately 18 Tcf of estimated recoverable reserves and cumulative historical production in excess of 12 Tcf.

• Oklahoma. We own the Foss Lake gathering system and the Arapaho gas processing plant located in the western Oklahoma counties of Roger Mills and Custer, respectively. The gathering system is comprised of a pipeline system that is connected to natural gas wells and associated compression facilities. All of the gathered gas is ultimately compressed and delivered to the processing plant. After processing, all residue gas is delivered to a third party pipeline and all natural gas liquids are sold to one customer.

• Other Southwest. We own 17 natural gas gathering systems located in Texas, Louisiana, Mississippi and New Mexico. These systems generally service long-lived natural gas basins that continue to experience drilling activity. We gather a significant portion of the gas produced from fields adjacent to our gathering systems. In many areas, we are the primary gatherer, and in some of the areas served by our smaller systems we are the sole gatherer. In addition, we own four lateral pipelines in Texas and New Mexico.

• Appalachia. We are the largest processor of natural gas in the Appalachian basin with fully integrated processing, fractionation, storage and marketing operations. The Appalachian basin is a large natural gas producing region characterized by long-lived reserves and modest decline rates. Our Appalachian assets include five natural gas processing plants, a NGL pipeline, a NGL fractionation plant and two caverns storing propane.

• Michigan. We own the largest intrastate crude oil pipeline in Michigan. We refer to this system as the Michigan Crude Pipeline. We also own a natural gas gathering system and a natural gas processing plant in Michigan.

We generate a substantial portion of our revenues and cash flows by providing fee-based services to our customers, which limits our commodity price exposure and provides us with a relatively stable base of cash flows. Gross margin from fee-based services depends largely on throughput volume and is typically less affected by short-term changes in commodity prices. For the year ended December 31, 2004, we generated 56% of our gross margin from contracts under which we charge fees for providing midstream services. The remaining 44% of our gross margin for that period was generated from contracts subject to commodity price exposure, consisting of percentage-of-index and other contracts tied to natural gas prices (25%), percentage-of-proceeds and other contracts tied to NGL prices (9%) and keep-whole contracts, which are tied to the prices of both commodities (10%). See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our Contracts”, included in Item 7 of this Form 10-K for further information.

We have grown rapidly through acquisitions, as well as through construction and expansion of our assets. Since our initial public offering in May 2002, we have completed six acquisitions for an aggregate purchase price of $354.4 million while raising approximately $196.6 million in equity through two public and two private offerings and by issuing an aggregate of $204.5 million in debt. The last acquisition in 2004 was our East Texas System for

approximately $240.7 million. In the first quarter of 2005, we completed a seventh acquisition for a 50% non-operating ownership in Starfish for $41.7 million.

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 six acquisitions in 2003 and 2004, 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 to 20% of our revenue and 32% of our gross margin for the year ended December 31, 2004. If we include the results of operations from our 2004 acquisitions for the full year, rather than just for the period that we owned the assets, our dependence on MarkWest Hydrocarbon would have been reduced further to 18% of our pro forma revenue and 27% of our pro forma gross margin for the year ended December 31, 2004.

Competitive Strengths

We believe our competitive strengths include:

• Strategic and growing position with high-quality assets in the Southwest. Our acquisitions have allowed us to establish and expand our presence in several long-lived natural gas basins in the Southwest, particularly in Texas and Oklahoma. Our recently acquired East Texas System and our Pinnacle gathering systems are located in the East Texas and Permian basins in Texas. Our Foss Lake gathering system and our associated Arapaho gas processing plant, which we refer to as our western Oklahoma assets, are located in the Anadarko basin in Oklahoma. We believe the East Texas System and our western Oklahoma assets are located in some of the largest and most prolific natural gas-producing regions in the United States and feature new, low-cost gathering systems that provide producers low-pressure and fuel-efficient service, a significant competitive advantage for us over many competing gathering systems in those areas. We believe this competitive advantage is evidenced by our recently executed contracts for the connection of additional natural gas production of approximately 95 MMcf/d to our East Texas System beginning in the third quarter of 2004 and in the first and second quarters of 2005. Due in part to these contracts, we increased our throughput volumes to over 270 MMcf/d by the end of 2004 by connecting additional volumes currently under contract. In addition, most of our areas of operation in the Southwest are experiencing additional exploration and development activity, which provide us with an opportunity to capture additional supplies of natural gas.

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

• Largest intra state crude oil pipeline in Michigan. We are the largest intrastate pipeline transporter of crude oil in Michigan. We enjoy a competitive advantage over higher cost crude oil transportation alternatives such as trucking. Most of the crude oil we transport in the state is produced from the Niagaran Reef Trend, which is generally characterized by long-lived crude oil reserves. Drilling activity in the Niagaran Reef Trend has remained steady and continues to yield new supplies of crude oil.

• Stable Cash Flows. We believe that the fee-based nature of a significant portion of our business provides us with a relatively stable base of cash flows. For the year ended December 31, 2004, we generated approximately 56% of our gross margin from fee-based services. Our fee-based services depend on throughput volume but are typically not affected by short-term changes in commodity prices. In addition, a portion of our fee-based business is generated by our four lateral pipelines in the Southwest, which typically provide fixed transportation fees independent of the volumes transported.

• Long-term Contracts. We believe long-term contracts, which we define as contracts with remaining terms of four years or more, lend greater stability to our cash flow profile. For the year ended December 31, 2004, approximately 56% of our gross margin was tied to long-term contracts. In East Texas, approximately 73% of our current gathering volumes are under contract until 2010. Two of our Pinnacle lateral pipelines operate under fixed-fee contracts for the transmission of natural gas that expire in approximately 19 and 29 years, respectively. Approximately 46% of our daily throughput in the Foss Lake gathering system and Arapaho processing plant in western Oklahoma is subject to contracts with remaining terms of five years or more. In Appalachia, we have natural gas processing and NGL fractionation contracts, which have remaining terms from 5 to 11 years. In Michigan, our natural gas transportation, treating and processing agreements have terms for the life of the connected wells.

• Experienced management with operational, technical and acquisition expertise. Each member of our executive management team has substantial experience in the energy industry and our facility managers have extensive experience operating our facilities. Our operational and technical expertise has enabled us to upgrade existing facilities and to design and build new facilities. Since our initial public offering in May 2002, our management team has utilized a disciplined approach to analyze and evaluate numerous acquisition opportunities and has completed seven acquisitions. We intend to continue to use our management’s experience and disciplined approach in evaluating and acquiring assets to grow through accretive acquisitions, which are acquisitions expected to increase our distributable cash flow to our unitholders, with a focus on opportunities through which we can increase throughput volumes and cash flows.

• Financial strength and flexibility. During 2004, we substantially strengthened our balance sheet through the issuance of $187.0 million of equity. We also issued $225.0 million of long-term fixed rate debt, the funds from which were used to pay down outstanding borrowings under our credit facility. This marked our initial entry into the debt capital markets, which we believe will be an important source of new capital for us in the future. We have a stated goal of maintaining a capital structure with approximately equal amounts of debt and equity on a long-term basis.

As of December 31, 2004, we have available borrowing capacity of approximately $63.3 million under our $200.0 million credit facility. This amount is determined on a quarterly basis and is further adjusted to take into consideration the cash flow contribution of an acquisition at the time of its closing. 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 business strategy is to grow our business, increase distributable cash flow to our common unitholders, improve financial flexibility and increase our ability to access capital to fund our growth. We plan to accomplish this through the following:

• Increasing utilization of our facilities. We seek to capture additional natural gas and crude oil supplies from existing customers and to provide services to other natural gas and crude oil producers in our areas of operation. Increased drilling activity in our core areas of operation, particularly within certain fields in the Southwest, should also produce increasing natural gas and crude oil supplies and a corresponding increase in utilization of our transportation, gathering, processing and fractionation facilities. We have developed additional capacity at certain of our facilities, which enables us to increase throughput with minimal incremental costs.

• Expanding operations through new construction. By expanding our existing infrastructure and customer relationships, we intend to continue growing our asset base in our primary areas of operation to meet the

anticipated need for additional midstream services. In East Texas, we have 18 miles of natural gas gathering pipeline under construction to accommodate contractually committed volumes and expect to complete a new 200 MMcf/d processing plant and an associated NGL pipeline by December 2005. In addition, we are adding compression and gathering capacity to support increasing throughput volumes in the fields associated with our Appleby gathering system in Texas and our Foss Lake gathering system in Oklahoma. In the first quarter of 2005, we completed a new, more efficient processing plant to replace our Cobb processing plant in Appalachia.

• Expanding operations through strategic acquisitions. We intend to continue to pursue strategic and conservatively financed acquisitions of assets and businesses in our existing areas of operation in order to leverage our current asset base, personnel and customer relationships. For example, our East Texas System, Hobbs, Pinnacle, Lubbock and western Oklahoma acquisitions have enabled us to establish and develop a new primary area of operation in the Southwest. In addition, we seek to acquire assets in certain regions outside of our current areas of operation.

• 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 in order to further minimize our exposure to short-term changes in commodity prices.

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. Prior to our formation, these assets generated revenues pursuant to keep-whole and percent-of-proceeds contracts. Upon the formation of the Partnership, MarkWest Hydrocarbon retained these contracts and subcontracted the services to the Partnership under fee-based arrangements. By entering into these fee-based contracts with MarkWest Hydrocarbon, the Partnership was able to eliminate the commodity price volatility from the revenue generated from these assets. MarkWest Hydrocarbon remains our largest customer and, for the year ended December 31, 2004, accounted for 20% of our revenues and 32% of our gross margin. This represents a decrease from the year ended December 31, 2003, during which MarkWest Hydrocarbon accounted for 42% of our revenues and 59% of our gross margin. These percentages are likely to continue to decrease in the future as we expand our existing operations, continue to acquire assets and increase our customer base or diversify our business. At December 31, 2004, MarkWest Hydrocarbon and its subsidiaries owned 23% of our limited partnership interests and 90% of the general partner interest, which represents a 2% interest in the Partnership. MarkWest Hydrocarbon continues to direct our business operations through their ownership and control of our general partner. It also markets a portion of our NGLs. MarkWest Hydrocarbon employees are responsible for conducting our business and operating our assets on our behalf.

Overview of the Industry and our Business

The following diagram illustrates the natural gas gathering, processing and fractionation process:

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, natural gasoline and inert substances that may be removed by any number of processing methods.

Most natural gas produced at the wellhead is not suitable for long-haul pipeline transportation or commercial use and must be gathered, compressed and 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 includes these necessary services for either a fee or a percentage of the NGLs removed or gas units processed.

The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.

Natural gas processing and treating 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.”

After being separated from natural gas at the processing plant, the mixed NGL stream is typically transported to a centralized facility for fractionation. Fractionation is the process by which NGLs are further separated into individual, more marketable components, consisting of ethane, propane, normal butane, isobutane and natural gasoline. 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.

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 East Texas and 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 areas.

• 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. In Appalachia, we sell the majority of our normal butane to a specialty chemical manufacturer.

• 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 Southwest Assets

Gathering and Processing Facilities

East Texas

The table below describes our East Texas gathering and processing assets:

Year Ended December 31, 2004

Design

Natural

Year of

Throughput

Gas

Utilization

NGL

Initial

Capacity

Throughput

of Design

Throughput

Facility

Location

Construction

(Mcf/d)

(Mcf/d)(1)

Capacity

(gal/day)

East Texas gathering system(2)(3)

Panola County, TX

1990

350,000

259,300

East Texas processing plant(4)

Panola, County, TX

2005, anticipated

200,000

(1) Throughput volumes are for the calendar year ended December 31, 2004, and not just for the period of time we owned each facility.

(2) We acquired the East Texas gathering system on July 30, 2004.

(3) The design throughput capacity for the East Texas gathering system includes the throughput capacity upon completion of the 18 miles of natural gas pipeline under construction.

(4) Construction is anticipated to be completed in 2005.

East Texas gathering system. We acquired the East Texas System in July 2004. The system is a low-pressure regional gathering system consisting of approximately 210 miles of natural gas gathering pipeline connected to approximately 1,730 upstream well connections, with approximately 20 additional miles of pipeline currently under construction, and includes 15 centralized compressor stations with an aggregate of approximately 74,000 horsepower of compression, with an additional 16,000 horsepower of new compression and processing plant recompression currently being installed. The system gathers natural gas from the Carthage Field in east Texas from approximately 20 producers.

East Texas processing plant and NGL transportation. In conjunction with our East Texas System acquisition in July 2004, we are currently constructing a 200 MMcf/d skid-mounted cryogenic processing plant in east Texas designed to recover ethane and heavier hydrocarbons. The plant is designed to operate efficiently in an ethane recovery or rejection mode. Plant residue natural gas is expected to be delivered to a third party. We are constructing a NGL pipeline to deliver the recovered plant products to Mount Belvieu for fractionation and sale. The plant and related pipeline are scheduled for completion by the end of December 2005.

We generate revenues in East Texas through fixed fee gathering and compression, settlement margin and condensate sales contracts, which are described in more detail under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our Contracts”.

Oklahoma

The table below describes our Oklahoma gathering and processing assets:

Year Ended December 31, 2004

Design

Natural

Year of

Throughput

Gas

Utilization

NGL

Initial

Capacity

Throughput

of Design

Throughput

Facility

Location

Construction

(Mcf/d)

(Mcf/d)(1)

Capacity

(gal/day) (1)

Foss Lake Gathering System(2)

Roger Mills and Custer County, OK

1998

70,000

60,900

Arapaho Processing Plant(2)

Custer County, OK

2000

75,000

60,900

124,000

(1) Throughput volumes are for the calendar year ended December 31, 2004.

(2) We acquired the Foss Lake gathering system and the Arapaho processing plant on December 1, 2003.

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 240 miles of four to 20-inch pipeline connected to approximately 310 wells and includes approximately 16,000 horsepower of owned-compression and approximately 3,000 horsepower of leased-compression. The system gathers natural gas from the Anadarko Basin in western Oklahoma from approximately 75 producers. We generate revenues by charging fixed-fees per Mcf of natural gas gathered and through settlement margin arrangements. All of the natural gas gathered into the system is dehydrated at our Butler compression station for delivery to our Arapaho processing plant.

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 completed 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 (“PEPL”) and recovered NGLs are sold into the Conway, Kansas NGL market via a pipeline system owned by a third-party. We generate revenues 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 stream 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. 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.

Other Southwest

The table below describes our Other Southwest gathering and processing assets:

Year Ended December 31, 2004

Design

Natural

Year of

Throughput

Gas

Utilization

NGL

Initial

Capacity

Throughput

of Design

Throughput

Facility

Location

Construction

(Mcf/d)

(Mcf/d)(1)

Capacity

(gal/day)

Appleby Gathering System(2)

Nacogdoches County, TX

1990

40,000

27,100

Other Gathering Systems(2)

Various in TX, LA, MS, NM

Various

53,000

17,000

(1) Throughput volumes are for the calendar year ended December 31, 2004.

(2) We acquired the Appleby gathering system, along with 20 other gathering systems, as part of our March 28, 2003 Pinnacle acquisition.

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 100 miles of three to eight-inch pipeline connected to approximately 160 wells and includes approximately 4,000 horsepower of leased-compression and 4,000 horsepower of owned compression. The system gathers natural gas from the Travis Peak basin in 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, which are described in more detail under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our Contracts”.

Other Gathering Systems. As part of the Pinnacle acquisition, we acquired 20 other natural gas gathering systems, primarily located in Texas, one of which was disposed of in December 2003 for an insignificant amount and two of which have been subsequently sold in 2004 for proceeds of approximately $0.1 million. The systems typically gather natural gas from mature producing wells. We generate revenues from these systems through percent-of-index, percent-of-proceeds and fixed-fee contracts, which are described in more detail under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our Contracts”.

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. We acquired our Lubbock lateral in September 2003 and our Hobbs lateral in April 2004. The Lubbock and Hobbs lateral pipelines are the only laterals we own that produce revenue on a per-unit-of-throughput basis. The other lateral pipelines operate on a fixed-fee contract basis, under which our customer pays us a fixed monthly fee for the dedicated volume on that pipeline, independent of the volume of gas we transport.

• The Lake Whitney lateral, constructed in 2000, is a 30-mile intrastate natural gas pipeline that transports natural gas to a third party’s 560-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 our largest customer in this region 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 approximately 30 miles in length. The laterals transport natural gas to a third party’s Rio Nogales power plant, located near Seguin, Texas. We have a 20-year fixed-fee contract with this customer. This contract expires in 2022.

• The Blackhawk lateral is a six-mile intrastate natural gas pipeline that serves as a back-up natural gas supply source for a third party’s 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 to operate

the pipeline through September 2005. Prior to the transfer of the ownership of the lateral to a third party in April 2004, we leased the facility to the third party under a financing lease arrangement.

• We acquired the Lubbock lateral from the Power-Tex Joint Venture in September 2003. It consists of one 12-inch, 50-mile pipeline and one six-inch, 20-mile pipeline serving several industrial users and municipalities in and around Lubbock, Texas. We have fixed-fee contracts with terms ranging from one to five years. The lateral has a capacity of 100 MMcf/d and throughput was approximately 54 MMcf/d for the year ended December 31, 2004.

• We acquired the Hobbs lateral pipeline in April 2004. The Hobbs lateral consists of a four-mile segment of 10-inch and 12-inch natural gas pipeline connecting the Northern Natural Gas interstate pipeline to Southwestern Public Service’s Cunningham and Maddox power generating stations in Hobbs, New Mexico. We have a fixed-fee contract through 2008. The Hobbs lateral was recently expanded to a capacity of approximately 170 MMcf/d and throughput was approximately 42 MMcf/d for the nine months ended December 31, 2004 (since its acquisition).

Our Appalachian Assets

Appalachian Gathering and Processing Facilities

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

			Design	Year Ended December 31, 2004
			Throughput	Natural Gas	Utilization of
		Year	Capacity	Throughput	Design
Facility	Location	Constructed	(Mcf/d)	(Mcf/d)	Capacity
Kenova Processing Plant(1)	Wayne County, WV	1996	160,000	138,000	86	%
Boldman Processing Plant(1)	Pike County, KY	1991	70,000	41,000	59	%
Maytown Processing Plant	Floyd County, KY	2000	55,000	57,500	105	%
Cobb Processing Plant(2)	Kanawha County, WV	1968	35,000	23,000	66	%
Kermit Processing Plant(1)(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) In 2004, we began construction of a new 24 MMcf/d processing plant. This new plant replaces our existing Cobb plant. It was completed in the first quarter of 2005.

(3) The Kermit processing plant is operated by a third party producer 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 a third party producer. 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 natural gas from Columbia Gas’ transmission pipeline and processes gas from adjoining counties. NGLs extracted at this facility are transported to our Siloam fractionator via 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. This facility receives all of its intake of natural gas from Columbia Gas’ transmission pipelines 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 via pipeline to our Siloam fractionator.

Maytown Processing Plant. Pursuant to contract, a third party producer provides certain operating services at our Maytown facility, a straight refrigeration plant, on our behalf. While providing operating services, this third party is responsible for the day-to-day operation of the Maytown plant. Under our Gas Processing Agreement with this third

party, we have the right to assume the role of operator upon providing them with a 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 natural gas from the third party’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.

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 absorbs the NGLs, which are then separated from the lean oil by distillation. This facility receives its entire intake of 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 2004, we began replacing our existing Cobb facility with a newly constructed 24 MMcf/d processing plant. We completed the new processing plant in the first quarter of 2005.

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. 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 a third party’s’ 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.

Appalachian NGL Pipelines

Our Appalachia liquids pipeline includes the following segments:

				Design	Year Ended December 31, 2004
				Throughput	NGL	Utilization of
			Year	Capacity	Throughput	Design
Pipeline	Location	Miles	Constructed	(gal/day)	(gal/day)	Capacity
Maytown to Institute(1)	Floyd County, KY to Kanawha County, WV	100	1956	250,000	152,000	61	%
Ranger to Kenova(2)	Lincoln County, WV to Wayne County, WV	40	1976	831,000	152,000	18	%
Kenova to Siloam	Wayne County, WV to South Shore, KY	40	1957	831,000	425,000	51	%

(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.

We earn fees for transporting the NGLs recovered from the Kenova, Maytown, and Boldman plants to Siloam via our Appalachian pipeline. Prior to 2000, we owned and operated the line between Kenova and Siloam. This pipeline system was expanded in 2000 by leasing from a third party the 100 mile segment from Maytown to Ranger to Institute and purchasing the 40 mile segment from Ranger to Kenova and the 40 mile segment from Kenova to Siloam. These segments provide a contiguous pipeline system from our Maytown plant to Kenova and Kenova to Siloam. The segment from Ranger to Institute is not required for the NGL pipeline operation and is currently idle.

NGLs extracted from our Maytown and Kenova plants are injected directly into this pipeline system and transported to our Siloam fractionator. NGLs extracted from our Boldman plant are trucked to the Maytown plant and transported via the NGL pipeline to Siloam.

In November of 2004, a failure and ensuing explosion and fire occurred on the section of leased pipeline from Maytown to Ranger. The Office of Pipeline Safety (“OPS”) issued an order requiring among other things,

hydrostatic testing of the line prior to its return to service. Until the pipeline is returned to service, Maytown and Boldman NGLs are being trucked to Siloam for fractionation resulting in an increase to our NGL transportation costs. The Partnership has submitted claims for and is pursuing Business Interruption Insurance to cover the increased transportation costs incurred and lost income due to the pipeline being out of service as a result of the fire and explosion and OPS order. From November 2004 through December 31, 2004, our interruption loss was estimated to be approximately $0.5 million. We expect to incur these additional costs until the pipeline is returned to service.

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. 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:

			Design	Year Ended December 31, 2004
			Throughput	NGL	Utilization
		Year	Capacity	Throughput	of Design
Facility	Location	Constructed	(gal/day)	(gal/day)	Capacity
Siloam Fractionation Plant	South Shore, KY	1957	600,000	475,000	79	%

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 an annual fee.

Our Michigan Assets

Michigan Gathering and Processing Facilities

The table below describes our Michigan gathering and processing assets:

Design

Year Ended December 31, 2004

Throughput

Natural Gas

Utilization of

NGL

Year

Capacity

Throughput

Design

Throughput

Facility

Location

Constructed

(Mcf/d) (1)

(Mcf/d)

Capacity

(gal/day)

90-mile Gas Gathering Pipeline

Manistee, Mason and Oceana Counties, MI

1994 –1998

35,000

12,300

Fisk Processing Plant

Manistee County, MI

1998

35,000

12,300

26,900

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

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 one of our customers. Our

Fisk processing plant is located adjacent to our customer’s treatment plant. Our gathering pipeline serves approximately 30 wells and four 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. Fee arrangements represent approximately one-half of our gathering and processing gross margin in Michigan.

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

The Michigan Crude Pipeline consists of approximately 150 miles of eight to 16-inch main pipeline, approximately 100 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. We generate operating margins by charging a pipeline transportation fee based on volumes. The pipeline has a capacity of 60,000 bbl/d and transported approximately 14,700 bbl/d of crude oil for the year ended December 31, 2004.

The following is a summary of the percentage of our revenue and gross margin generated by our assets by geographic region for the year ended December 31, 2004:

	East Texas
	Gas		Oklahoma Gas						Appalachia NGL		Michigan
	Gathering,		Gathering,		Other Southwest				Transportation,		Gas
	Processing,		Processing,		Gas Gathering,		Appalachia		Fractionation &		Gathering		Michigan Crude
	Condensate		Condensate		Processing and		Gas		Storage		and		Oil
	Settlement		Settlement		Transportation		Processing		Services		Processing		Transportation		Total
Revenue	7	%	44	%	23	%	17	%	3	%	4	%	2	%	100	%
Gross margin	20	%	17	%	16	%	23	%	11	%	8	%	5	%	100	%

Due to our acquisitions during 2004, the above percentages are likely to change in the future as the results of our operations only include the acquired assets from the date that they were purchased.

External Customers and Contracts

Producers of crude oil and natural gas may be either our customers or our suppliers, depending on the type of contract under which we provide midstream services.

Southwest

East Texas

In East Texas, our primary sources of revenues are gathering fee agreements with the producers we service in the region. We generate gathering revenue in three complementary manners. Under fixed gathering and compression fee arrangements, producers pay us a fixed rate per unit to transport their natural gas through the gathering system. Under settlement margin contracts, we are allowed to retain a fixed percentage of the natural gas volume gathered to cover the compression fuel charges and deemed line losses. To the extent the East Texas System is operated more efficiently than the specified contract allowance, we are entitled to retain the difference for our own account. We also sell drip condensate, a pipeline operation by-product at a monthly crude oil indexed-based price. We have three primary customers in East Texas, who collectively accounted for 82% of the gross revenue generated in this area for the year ended December 31, 2004.

Oklahoma

In Oklahoma, we generate revenues by charging fixed fees per Mcf of natural gas gathered. We also generate revenues through keep-whole processing contracts. In addition, approximately 45% of our Foss Lake gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low-processing-margin environment. These contracts, and our ability to operate the Arapaho plant in several recovery modes, including shutting down the plant, limit our exposure to a portion of the operating costs of the plant. We have two primary customers in Oklahoma and they collectively accounted for 68% of the revenue generated in this area for the year ended December 31, 2004.

Other Southwest

On the Appleby gathering system, we generate a majority of our operating margin through percent-of-index contracts, with the remaining margin generated through fee-based contracts. In our other gathering systems in the Southwest, we generate operating margins through percent-of-index, percent-of-proceeds and fixed-fee contracts. We have three primary customers on these gathering systems that collectively accounted for 46% of the revenue generated in this area for the year ended December 31, 2004.

Appalachia

In Appalachia, our primary sources of revenues are our processing, transportation, fractionation and storage agreements with MarkWest Hydrocarbon, which are described under “Our Contracts with MarkWest Hydrocarbon” included herein, and under “Agreements with MarkWest Hydrocarbon” included in Item 13 of this Form 10-K and our agreement with a producer relating to processing services at our Maytown facility. Under the terms of this gas processing agreement, the producer 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 the producer’s gathering system (to the extent the producer has the right to process such third-party gas). The producer 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 the producer and must deliver residue gas to the producer at a specified gas delivery point. The parties have agreed that the producer will provide certain operating services 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 the producer’s behalf. A portion of the transportation and fractionation fee is subject to annual adjustment in proportion to the annual average percentage change in the Producer Price Index for Oil and Gas Field Services. 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 initial term of our gas processing agreement with the producer 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 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.

Under a Gas Treating and Processing Agreement between our subsidiary, West Shore Processing Company, LLC and a third party, the third party operates our Fisk natural gas processing plant. Under the terms of this agreement, the third party 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. The third party 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 a third party a set monthly treating fee and a volumetric treating fee based on the amount of gas we deliver to the third party. Both of these fees are adjusted annually in proportion to the change in a government reported index. In addition, the third party 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.

Our Michigan Crude Pipeline generates operating margins by charging a pipeline transportation fee based on volumes. Approximately 62% of the crude oil transported through the pipeline was shipped for one customer.

Our Contracts with MarkWest Hydrocarbon

For the year ended December 31, 2004, MarkWest Hydrocarbon was our largest contract counterparty, accounting for 32% of our gross margin. MarkWest Hydrocarbon controls our operations through its ownership of our general partner as well as its significant limited partner interest in us. 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, 2004.

			Pipeline Liquids
			Transportation Agreement,
	Gas Processing		Fractionation, Storage and		NGL Purchase
	Agreement		Loading Agreement		Agreement		Total
Revenue	5	%	3	%	12	%	20	%
Gross margin	16	%	11	%	5	%	32	%

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 pipeline throughput in excess of 10,000 Mcf/d, calculated quarterly.

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 a third party producer 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 transported to our Siloam fractionator, while all residue gas is redelivered to a producer’s 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, a portion of which will be adjusted on January 1^st of each year 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 based on the number of gallons delivered to us for fractionation. A portion of the fee is 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 a third party producer. 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 a third party producer, and remit the balance from such NGL product sales to that producer. 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.

Competition

We face competition for natural gas and crude oil 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 the 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;

• medium and large sized independent E&P companies;

• major interstate and intrastate pipelines;

• other large 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 operate as master limited partnerships and enjoy a cost of capital comparable, and in some cases lower, than ours. Other 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. Many of these permits are revocable at the election of the grantor. 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 does not believe that any of these 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 our assets to secure the debt of our subsidiary MarkWest Energy Operating Company, L.L.C. (the “Operating Company”) as discussed in Note 8 of the accompanying Notes to Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K.

Regulatory Matters

Our activities are subject to various federal, 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 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. Applicable 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.

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 and consequently should not be subject to regulation by the Federal Energy Regulatory Commission, (“FERC”). However, we cannot provide assurance that FERC would not determine that such transportation is within its jurisdiction. 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. 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. Moreover, the likelihood of other entities seeking to utilize our Appalachian pipeline is remote. However, we cannot predict whether an assertion of FERC jurisdiction might be made with respect to this pipeline, nor provide assurance that such an assertion would not adversely affect our results of operations. With respect to the Michigan Crude Pipeline, one shipper recently contacted FERC to inquire about a transportation rate increase and the pipeline’s regulatory rate structure. In response, FERC requested that we contact the shipper to initiate a discussion regarding the shipper’s questions. We are presently in discussions with all shippers regarding rate structures and are attempting to resolve any issues they may have. FERC also requested that we file a tariff. While the Michigan Crude Pipeline operations are entirely within the state of Michigan and have been regulated by the State of Michigan, we have calculated and determined that our current and proposed rate structures are well below rates that would be allowed under FERC’s cost of service rate-making structure. However, we cannot predict whether a FERC jurisdictional challenge might be made with respect to the Michigan Crude Pipeline, nor provide assurance that such a development 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.

Safety Regulation. Our pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act (“HLPSA”), as amended 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 efforts associated 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 U.S. Department of Transportation Office of Pipeline Safety (“OPS”), in particular, with respect to operator qualifications programs, natural mapping system and safe excavation practices. Management of the Partnership believes that compliance efforts associated with the Pipeline Safety Improvement Act of 2002 will not have a material effect on its operations.

On November 8, 2004, a leak and release of vapors occurred in a pipeline transporting NGLs from the Maytown gas processing plant to our Siloam fractionator. This pipeline is owned by a third party, and leased and operated by our subsidiary, MarkWest Energy Appalachia, LLC. A subsequent ignition and fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The exact cause of the leak and resulting fire is unknown and is being investigated by the OPS, the owner and us. Pursuant to a Corrective Action

Order issued by the OPS on November 18, 2004 and amended November 24, 2004, pipeline and valve integrity evaluation, testing and repair efforts are required and are being conducted on the affected pipeline segment before service can be resumed. Both the pipeline owner and we are working with OPS to assure compliance with the Order.

Environmental Matters

General. Our processing and fractionization plants, pipelines and associated facilities in connection with the gathering and processing of natural gas, the transportation, fractionation and storage of NGLs and the storage and gathering and transportation of crude oil are subject to multiple environmental obligations and potential liabilities under a variety of federal, state and local laws and regulations, including without limitation, the Comprehensive Environmental Response, Compensation, and Liability Act, the Resource Conservation and Recovery Act, the Clean Air Act, the Federal Water Pollution Control Act or the Clean Water Act, the Oil Pollution Act, and analogous state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, solid and hazardous waste management. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. If an accidental leak, spill or release of hazardous substances occurs from our lines or facilities, in the process of transporting natural gas, or at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean up costs. Likewise, 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 for properties owned, leased or acquired by us which may have been previously operated by third parties and who may have released or disposed of hazardous substances or wastes, all of which could materially affect our results of operations and cash flows.

Nevertheless, 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. However, we cannot ensure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have material adverse effect on our business, financial condition, results of operations and cash flow.

Ongoing Remediation and Indemnification from a Third Party. The previous owner/operator of our Boldman and Cobb facilities has been or is currently involved in investigatory or remedial activities with respect to the real property underlying these facilities pursuant to an “Administrative Order by Consent for Removal Actions” with EPA Regions II, III, IV, and V in September 1994 and an “Agreed Order” entered into with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The previous owner/operator 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 or purchased the real property. In addition, the previous owner/operator 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 this indemnity from the previous owner/operator. To date, the previous owner/operator has been performing all actions required under these agreements, and, accordingly, we do not believe that the remediation obligation of these properties will have a material adverse impact on our financial condition or results of 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, (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and citizens. We believe that we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

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

Employees

We do not have any employees. To carry out our operations, our general partner or its affiliates employ approximately 166 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 15 employees at our Siloam fractionation facility in South Shore, Kentucky. The collective bargaining agreement with this Union expired on June 28, 2004; MarkWest Hydrocarbon is currently negotiating a new contract with the union. The agreement covers only hourly, non-supervisory employees. We consider labor relations to be satisfactory at this time.

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 defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. 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.

The Partnership and several of our affiliates were recently served with two lawsuits captioned as follows:

Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al., (Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00137), filed February 2, 2005, as Removed to the U.S. District Court for the Eastern District of Kentucky, Pikeville Division, Civil Action No. 7: 5-CV-67-DLB, on February 24, 2005.

Charles C. Reid, et al. v. MarkWest Hydrocarbon, Inc. et al., (Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00156, filed February 8, 2005.

These actions seek recovery of property or personal injury damages sustained as a result of a leak and ensuing explosion and fire occurring November 8, 2004 in a NGLs line owned by a third party and leased and operated by our subsidiary, MarkWest Energy Appalachia, LLC. The four-inch pipeline transported NGLs from the Maytown gas processing plant to our Siloam fractionator. The ensuing ignition and fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The exact cause of the leak,

explosion and resulting fire is unknown and is being investigated by the OPS, the pipeline owner and us. Pursuant to a Corrective Action Order issued by the OPS, pipeline and valve integrity evaluation, testing and repair efforts are required and are being conducted on the affected pipeline segment before service can be resumed. Until repairs are completed and service is resumed on the line, NGLs from our Boldman and Maytown plants will be trucked directly to the Siloam fractionator, resulting in an increase in our NGL transportation costs. The Partnership has submitted claims for and is pursuing Business Interruption Insurance to cover the increased transportation costs incurred and lost income.

While investigation into the incident continues, at this time we believe that we have adequate insurance coverage for property damage and personal injury liability, resulting from the incident. The deductible for the insurance is $0.3 million, which has been accrued for as a charge to operations in 2004.

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, 2004.

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 2004 and 2003.

Quarter Ended	High		Low		Per Common Unit		Per Subordinated Unit		Record Date	Payment Date

December 31, 2004	$	48.69	$	42.50	$	0.78	$	0.78	February 2, 2005	February 11, 2005
September 30, 2004	$	45.80	$	37.73	$	0.76	$	0.76	November 3, 2004	November 12, 2004
June 30, 2004	$	40.07	$	33.50	$	0.74	$	0.74	July 30, 2004	August 13, 2004
March 31, 2004	$	41.66	$	37.70	$	0.69	$	0.69	April 30, 2004	May 14, 2004

December 31, 2003	$	40.90	$	34.05	$	0.67	$	0.67	January 31, 2004	February 13, 2004
September 30, 2003	$	35.98	$	29.55	$	0.64	$	0.64	November 4, 2003	November 14, 2003
June 30, 2003	$	32.50	$	25.30	$	0.58	$	0.58	August 4, 2003	August 14, 2003
March 31, 2003	$	26.00	$	22.95	$	0.58	$	0.58	May 5, 2003	May 15, 2003

As of May 31, 2005, there were approximately 114 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. There were approximately 11 holders of record of our subordinated units.

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 our 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.

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 unitholders and 2% to our general partner, until each common unitholder has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters.

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

• Third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder 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, as described below, 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 unitholder 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. We are presently distributing in excess of $0.75 per unit per quarter.

There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility. The subordination period generally will not end earlier than June 30, 2007. However, a portion of the subordinated units may be converted into common units at an earlier date on a one-for-one basis based upon the achievement of certain financial goals (defined in the Partnership Agreement). As a result of achieving those goals in May 2005, 600,000 subordinated units will convert into common units on June 30, 2005. An additional 600,000 of the outstanding subordinated units will also convert into common units on September 30, 2005.

The indenture governing our outstanding senior notes contains restrictions on our ability to make cash distributions. Under the indenture, we are restricted from making distributions (a “Restricted Payment”) if at the time of making the Restricted Payment, a default or an event of default has occurred and is continuing. The Partnership’s failure to file this Annual Report on Form 10-K for year ended December 31, 2004 and its Quarterly Report on Form 10-Q for the first quarter of 2005 within the time periods specified in the Securities and Exchange Commission’s rules and regulations constituted a default under the indenture and the failure to file the Form 10-K within thirty days after the April 8, 2005 notice from the indenture trustee constituted an event of default under the

indenture. On May 16, 2005, the Partnership paid a cash distribution to unitholders for the first quarter of 2005. This cash distribution, made while the event of default for failure to file its Form 10-K had occurred and was continuing, constituted a default under the indenture, and this default matured into an event of default thirty days after such Restricted Payment was made, or June 15, 2005. Both of these events of default are cured through the filing of this Form 10-K and the Quarterly Report on Form 10-Q for the first quarter of 2005 prior to any declaration of acceleration of the senior notes by the trustee as a result of such events of default. In addition, as the Partnership was unable to deliver its audited consolidated financial statements within 90 days of December 31, 2004, the Partnership is not in compliance with its debt covenants for the credit facility. The lending institutions of our credit facility have waived the 90 days delivery requirement until June 30, 2005.

ITEM 6. SELECTED FINANCIAL DATA

On May 24, 2002, the Partnership completed its initial public offering and thereafter 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, 2004, 2003 and 2002. The selected historical financial information of the Midstream Business as of and for the years ended December 31, 2001 and 2000 are derived from the audited combined 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”.

On May 5, 2005, management, after discussion with the Audit Committee of our Board of Directors, determined that previously issued financial statements for the years ended December 31, 2002 and 2003 and for each of the first three quarters of 2003 and 2004 should be restated to reflect compensation expense allocated to us attributable to the sale of subordinated Partnership units and interests in the Partnership’s general partner to certain employees and directors of MarkWest Hydrocarbon that occurred during 2002, 2003 and 2004.

Refer to Note, 19, “Restatement of Consolidated Financial Statement,” to the consolidated financial statements in Item 8 of this Form 10-K for further information regarding the restatement of our previously issued financial statements.

	Partnership									MarkWest Hydrocarbon Midstream Business
	Year Ended December 31,
	2004			2003			2002			2001			2000
	(in thousands, except per unit amounts)
				(as restated) (1)			(as restated) (1)
Statement of Operations:
Revenues	$	301,314		$	117,430		$	70,246		$	93,675		$	109,810
Operating expenses:
Purchased product costs	211,534			70,832			38,906			65,483			71,341
Facility expenses	29,911			20,463			15,101			13,138			13,224
Selling, general and administrative expenses	16,133			8,598			5,411			5,047			4,733
Depreciation	15,556			7,548			4,980			4,490			4,341
Amortization of intangible assets	3,640			—			—			—			—
Impairments	130			1,148			—			—			—
Accretion of asset retirement obligation	13			—			—			—			—
Total operating expenses	276,917			108,589			64,398			88,158			93,639
Income from operations	24,397			8,841			5,848			5,517			16,171
Interest income	87			14			5			—			—
Interest expense	(9,236		)	(3,087		)	(1,128		)	(1,307		)	(1,697		)
Amortization of deferred financing costs	(5,236		)	(984		)	(291		)	—			—
Miscellaneous income (expense)	(50		)	(25		)	52			—			—
Income before income taxes	9,962			4,759			4,486			4,210			14,474
Provision (benefit) for income taxes	—			—			(17,175		)	1,624			5,693
Net income	$	9,962		$	4,759		$	21,661		$	2,586		$	8,781
Net income per limited partner unit:
Basic	$	1.31		$	0.95		$	4.86		$	0.86		$	2.93
Diluted	$	1.31		$	0.94		$	4.83		$	0.86		$	2.93
Cash distributions declared per limited partner unit	$	2.97		$	2.47		$	1.23		NA			NA

Balance Sheet Data (at period end):
Working capital	$	10,547		$	2,457		$	1,762		$	18,240		$	6,047
Property, plant and equipment, net	280,635			184,214			79,824			82,008			77,501
Total assets	529,422			212,871			87,709			104,891			95,520
Total debt, including debt due to parent	225,000			126,200			21,400			19,179			20,782
Partners’ capital/Net parent investment	241,142			64,944			60,863			65,429			50,751

Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	42,616		$	21,229		$	33,502		$	(524	)	$	13,997
Investing activities	(273,517		)	(112,893		)	(2,056		)	(8,997		)	(12,147		)
Financing activities	246,411			97,641			(28,670		)	9,521			(1,850		)

Other Financial Data:
Sustaining capital expenditures (2)	$	1,163		$	1,041		$	511		$	576		$	955
Expansion capital expenditures(2)	29,304			1,903			1,634			9,075			11,192
Total capital expenditures	$	30,467		$	2,944		$	2,145		$	9,651		$	12,147

(1) See Note 19 in Notes to Consolidated and Combined Financial Statements.

(2) 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. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition.

Operating Data

				MarkWest Hydrocarbon
	Partnership			Midstream Business
	Year Ended December 31,
	2004	2003	2002	2001	2000

Operating Data:
*Southwest:*
East Texas (1)
Gathering systems throughput (Mcf/d)	259,300	NA	NA	NA	NA
NGL product sales (gallons)	41,478,000	NA	NA	NA	NA

Oklahoma
Foss Lake gathering systems throughput (Mcf/d) (2)	60,900	57,000	NA	NA	NA
Arapaho NGL product sales (gallons) (3)	45,273,000	2,910,000	NA	NA	NA

Other
Appleby gathering systems throughput (Mcf/d) (4)	27,100	23,800	NA	NA	NA
Other gathering systems throughput (Mcf/d) (4)	17,000	20,500	NA	NA	NA
Lateral throughput volumes (Mcf/d) (5)	75,500	32,100	NA	NA	NA

*Appalachia:*
Natural gas processed for a fee (Mcf/d) (6)	203,000	202,000	202,000	192,000	196,000
NGLs fractionated for a fee (Gal/day)	475,000	458,000	476,000	423,000	406,000
NGL product sales (gallons)	42,105,000	40,305,000	38,813,000	—	—

*Michigan:*
Natural gas processed for a fee (Mcf/d)	12,300	15,000	13,800	8,800	11,000
NGL product sales (Mcf/d)	9,818,000	11,800,000	11,100,000	8,000,000	9,200,000
Crude oil transported for a fee (Bbl/d) (7)	14,700	15,100	—	—	—

(1) We acquired our East Texas System in late July 2004. Volumes are for the period of time we owned the facility during 2004.

(2) We acquired our Foss Lake gathering system in December 2003.

(3) We acquired our Arapaho processing plant in December 2003.

(4) We acquired our Pinnacle gathering systems in late March 2003.

(5) We acquired our Lubbock pipeline (a/k/a the Power-tex Lateral Pipeline) in September 2003 and our Hobbs lateral pipeline in April 2004. The Lubbock and Hobbs pipelines are the only laterals we own that produce revenue on a per-unit-of-throughput basis. We receive a flat fee from our other lateral pipelines and, consequently, the throughput data from these lateral pipelines is excluded from this statistic.

(6) Includes throughput from our Kenova, Cobb, and Boldman processing plants.

(7) We acquired our Michigan Crude Pipeline in December 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 three factors:

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

• the difficulty in comparing our results of operations across periods, both because of our recent acquisition activity; and

• the nature of our relationship with MarkWest Hydrocarbon.

Our Contracts

We generate the majority of our revenues and gross margin from natural gas gathering, processing and transmission, NGL transportation, fractionation and storage, and crude oil gathering and transportation. In our current areas of operations, we have a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. While all of these services constitute midstream energy operations, we provide services under the following five 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 rising 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 energy content 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.

• East Texas System gathering arrangements. We gather volumes on the East Texas System under contracts with fee arrangements that are unique to that system. These contracts typically contain one or more of the following revenue components:

• Fixed gathering and compression fees. Typically, gathering and compression fees are comprised of a fixed-fee portion in which producers pay a fixed rate per unit to transport their natural gas through the gathering system. Under the majority of these arrangements, fees are adjusted annually based on the Consumer Price Index.

• Settlement margin. Typically, the terms of our East Texas System gathering arrangements specify that we are allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed line losses. To the extent the East Texas System is operated more efficiently than specified per contract allowance, we are entitled to retain the difference for our own account.

• Condensate sales. During the gathering process, thermodynamic forces contribute to changes in operating conditions of the natural gas flowing through the pipeline infrastructure. As a result, hydrocarbon dew points are reached, causing condensation of hydrocarbons in the high-pressure pipelines. The East Texas System sells the condensate collected in the system at a monthly crude-oil index based price.

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.

At December 31, 2004, our primary exposure to keep-whole contracts was limited to our Arapaho (Oklahoma) processing plant and our East Texas processing contracts. At the Arapaho plant inlet, the Btu content of the natural gas meets the downstream pipeline specifications; however, we have the option of extracting NGLs when the processing margin environment is favorable. In addition, approximately half, as measured in volumes, of the related gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low processing margin environment. Because of our ability to operate the plant in several recovery modes, including turning it off, coupled with the additional fees provided for in the gas gathering contracts, our overall keep-whole contract exposure is limited to a portion of the operating costs of the plant. In East Texas approximately 21% of the inlet volumes are processed pursuant to keep-whole contracts.

For the year ended December 31, 2004, we generated the following percentages of our revenue and gross margin from the following types of contracts:

	Fee-Based		Percent-of- Proceeds(1)		Percent-of- Index(2)		Keep-Whole(3)		Total
Revenue	17	%	14	%	27	%	42	%	100	%
Gross Margin	56	%	9	%	25	%	10	%	100	%

(1) Includes other types of contracts tied to NGL prices.

(2) Includes other types of contracts tied to natural gas prices.

(3) Includes other types of contracts tied to both NGL and natural gas prices.

Impact of Recent Acquisitions on Comparability of Financial Results

In reading the discussion of our historical results of operations, you should be aware of the impact of our recent acquisitions. Since our initial public offering, we have completed six acquisitions for an aggregate purchase price of $354.4 million. These six acquisitions include:

• the Pinnacle acquisition, which closed on March 28, 2003, for consideration of $39.9 million;

• the Lubbock pipeline acquisition (also known as the Power-Tex Lateral pipeline), 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;

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

• the Hobbs acquisition, which closed April 1, 2004, for consideration of $2.3 million; and

• the East Texas acquisition, which closed on July 30, 2004, for consideration of $240.7 million.

Our historical results of operations for the year ended December 31, 2003, do not reflect the impact of these acquisitions on our operations for the full year. Our results of operations for the year ended December 31, 2004, reflect the impact of our four 2003 acquisitions, as well as nine months of operations for our Hobbs Lateral acquisition and five months of results from our East Texas System acquisition.

Our Relationship with MarkWest Hydrocarbon, Inc.

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 consisted of the MarkWest Hydrocarbon Appalachian operations. Our results of operations after our initial public offering changed 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 in contrast to 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. Upon the formation of the Partnership, MarkWest Hydrocarbon retained these contracts and subcontracted the services to the Partnership under fee-based arrangements. By entering into these fee-based contracts with MarkWest Hydrocarbon, the Partnership was able to reduce the commodity price volatility from the revenue generated from these assets, which significantly impacted our financial statements before and after the date of our initial public offering. The major difference 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’ 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 these contracts, along with a small portion of 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 required to operate our facilities, including applicable personnel costs, fuel, plant utility costs and maintenance expenses. However, MarkWest Hydrocarbon continues to incur the producer plant fuel reimbursement obligations, as was the case prior to the Partnership’s formation.

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

Restatement Of Financial Statements

The restatements result from an allocation of compensation expense from MarkWest Hydrocarbon attributed to its sale of a portion of its subordinated Partnership units and interests in our general partner to certain employees and directors from 2002 through 2004. MarkWest Hydrocarbon had historically recorded the sale of the subordinated Partnership units and interests in our general partner to certain of MarkWest Hydrocarbon’s employees and directors as a sale of an asset. These arrangements are referred to as the Participation Plan. However, MarkWest Hydrocarbon determined that these transactions should be accounted for as compensatory arrangements, consistent with the guidance in APB 25, Accounting for Stock Issued to Employees. This guidance requires MarkWest Hydrocarbon to record compensation expense based on the market value of the subordinated Partnership units and the formula value of the general partner interests held by the employees and directors at the end of each reporting period. The formula value is the amount MarkWest Hydrocarbon would pay to repurchase the interests if the employee exercises its put option or if MarkWest Hydrocarbon exercises its call option for the interests held by the employees or directors. In the process of determining the ultimate accounting treatment for these transactions a conclusion was reached by the Partnership that the compensation expense related to services provided by MarkWest Hydrocarbon’s employees and directors recognized under APB 25 should be allocated to the Partnership pursuant to Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses And Related Disclosure In Financial Statements of Subsidiaries, Divisions Or Lesser Business Components of Another Entity, based on the amount of time each employee devotes to the Partnership. Compensation attributable to interests that were sold to individuals who serve on both our board of directors and on the board of directors of MarkWest Hydrocarbon is allocated equally. The charge is a non-cash item that did not affect management’s determination of the Partnership’s distributable cash flow for any period, and did not affect net income attributed to the limited partners. Under the Partnership Agreement, the general partner is deemed to have made a capital contribution equal to the compensation expense recorded under the Participation Plan, and the compensation expense is allocated 100% to the general partner. As a result, there is no impact on the consolidated

balance sheet. In addition to these adjustments, we have also made an adjustment to record natural gas inventory at cost in the fourth quarter of 2003. The impact of these restatements was to reduce net income by $1.0 million for the year ended December 31, 2003 and $0.1 million for the year ended December 31, 2002. In addition, the Partnership has restated its financial position by reducing its originally reported assets and liabilities and equity by $0.1 million at December 31, 2003, the major details of which are shown in Note 19, “Restatement of Consolidated Financial Statement”, to the consolidated financial statements in Part II, Item 8 of this
Form 10-K. The information contained in this Managements Discussion and Analysis of Financial Condition and Results of Operations has been changed to reflect these restatement adjustments. All amounts reported in this Managements Discussion and Analysis of Financial Condition and Results of Operations are as restated, unless otherwise stated.

Results of Operations

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

	Year Ended December 31						Change
	2004			2003			$			%
	(in thousands)
				(as restated)(1)
Revenues	$	301,314		$	117,430		$	183,884		157	%

Operating expenses:
Purchased product costs	211,534			70,832			140,702			199	%
Facility expenses	29,911			20,463			9,448			46	%
Selling, general and administrative expenses	16,133			8,598			7,535			88	%
Depreciation	15,556			7,548			8,008			106	%
Amortization of intangible assets	3,640			—			3,640			NA
Impairment	130			1,148			(1,018		)	(89	)%
Accretion of asset retirement obligation	13			—			13			NA
Total operating expenses	276,917			108,589			168,328			155	%

Income from operations	24,397			8,841			15,556			176	%

Other expense:
Interest expense, net	(9,149		)	(3,073		)	(6,076		)	198	%
Amortization of deferred financing costs	(5,236		)	(984		)	(4,252		)	432	%
Miscellaneous expense	(50		)	(25		)	(25		)	100	%

Net income	$	9,962		$	4,759		$	5,203		109	%

(1) See Note 19 in Notes to Consolidated and Combined Financial Statements.

Revenues. Our 2004 revenues were higher than our 2003 revenues primarily due to our 2003 and 2004 acquisitions, which increased our revenues by $168.6 million. The increase was also due to higher Appalachia NGL product sales prices and volumes, which increased revenue by $9.5 million. In addition, higher margins due to higher gas prices in the Southwest, along with increased Southwest processing margins from an increase in liquid prices, contributed $6.3 million. These increases were partially offset by a reduction in our Michigan pipeline throughput volumes, which decreased revenue by $0.5 million.

Purchased Product Costs. Purchased product costs were higher in 2004 primarily due to our late 2003 and 2004 acquisitions, which increased our purchased product costs by $128.3 million. The remainder of the increase is primarily attributable to price and volume increases for our Appalachia NGL product sales. Price increases contributed $7.8 million and volume increases contributed an additional $4.6 million to purchased product costs.

Facility Expenses. Facility expenses increased approximately $9.4 million during 2004 relative to the same period in 2003 primarily due to our 2003 and 2004 acquisitions.

Selling, General and Administrative Expenses (“SG&A”). SG&A expenses increased during the year ended December 31, 2004 compared to 2003 because MarkWest Hydrocarbon was contractually limited in the amount it could charge us to $4.9 million annually, from May 24, 2002, the date of our initial public offering, through May 23, 2003. In addition, selling, general and administrative expenses have increased due to increased administrative costs of $2.1 million associated with our acquisitions, increased Sarbanes-Oxley compliance related expenses and audit fees of $1.4 million, an increase in bonus and severance expense of $1.0 million and professional services costs of $0.8 million. In addition, the allocation of compensation expense to the Partnership resulting from the sale of the subordinated Partnership units and interests in the general partner to certain of MarkWest Hydrocarbon’s employees and directors from 2002 through 2004 increased SG&A by $1.4 million. The charge is a non-cash item that did not affect management’s determination of the Partnership’s distributable cash flow for any period, and did not affect net income attributed to the limited partners.

Depreciation. Depreciation expense increased during 2004 primarily due to our 2003 and 2004 acquisitions, which increased depreciation by approximately $5.4 million. Additionally, commencing January 1, 2004, we accelerated the rate of depreciation of our Michigan gathering pipeline and processing plant by reducing the estimated useful lives of the related assets from 20 years to 15 years to more closely match expected lives of contractually dedicated reserves behind our facilities.

Amortization of intangible assets. Amortization expense increased during 2004 primarily due to the East Texas System acquisition in July 2004. On July 30, 2004, we completed the acquisition of American Central Eastern Texas’ Carthage gathering system and gas processing assets located in east Texas for approximately $240.7 million. Of the total purchase price, $165.4 million was allocated to customer contracts, of which $3.4 million was amortized during 2004.

Impairment. During the fourth quarter of 2004, we recorded a write-off of $0.1 million of costs associated with an isomerization unit taken out of service. 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. Consequently, in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long Lived Assets, we wrote down the carrying value of the current Cobb facility by $1.1 million to its estimated fair value.

Interest Expense. Interest expense increased during 2004 relative to 2003 primarily due to increased debt levels resulting from the financing of our 2003 and 2004 acquisitions. A significant amount of our 2004 acquisitions were financed through additional borrowings under our credit facility and the issuance of our senior notes.

Amortization of Deferred Financing Costs. The increase in amortization of deferred financing costs in 2004 relative to 2003 is attributable to the debt re-financings completed in 2004 as well as an increase in deferred financing cost as a result of the issuance of the senior notes. During 2004, we amortized approximately $5.2 million of deferred financing costs related to debt issuance costs incurred to finance our 2004 acquisitions, of which $1.5 million represented accelerated amortization due to the refinancing of our credit facility in July and again in October 2004. Deferred financing costs are being amortized over the estimated term of the related obligations, which approximates the effective interest method.

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.

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

	Year Ended December 31						Change
	2003			2002			$			%
	(in thousands)
	(as restated)(1)			(as restated)(1)
Revenues	$	117,430		$	70,246		$	47,184		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 expenses	8,598			5,411			3,187			59	%
Depreciation	7,548			4,980			2,568			52	%
Impairment	1,148			—			1,148			NA
Total operating expenses	108,589			64,398			44,191			69	%

Income from operations	8,841			5,848			2,993			51	%

Other income and (expense):
Interest expense, net	(3,073		)	(1,123		)	(1,950		)	(174	)%
Amortization of deferred financing costs	(984		)	(291		)	(693		)	(238	)%
Miscellaneous income (expense)	(25		)	52			(77		)	(148	)%
Income before income taxes	4,759			4,486			273			6	%

Benefit for income taxes	—			(17,175		)	17,175			(100	)%

Net income	$	4,759		$	21,661		$	(16,902	)	(78	)%

(1) See Note 19 in Notes to Consolidated and Combined Financial Statements.

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”). 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. In addition, the allocation of compensation expense to the Partnership resulting from the sale of subordinated Partnership units and interests in the general partner to certain of MarkWest Hydrocarbon’s employees and directors from 2002 through 2003 increased SG&A by $0.8 million.

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. Consequently, in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long Lived Assets, we wrote down the carrying value of the current Cobb facility to its estimated fair 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.

Amortization of Deferred Financing Costs. We amortized $1.0 million in deferred financing costs related to the issuance of our debt in 2003 to finance our 2003 acquisitions. The increase in amortization of deferred financing costs in 2003 relative to the same period in 2002 was due to an increase in deferred financing costs as a result of the increase in the size of our credit facility. Deferred financing costs are being amortized over the estimated term of the related obligations, which approximates the effective interest method.

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 deferred tax benefit 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 83% and 71% of our revenues and 44% and 26% of our gross margin for the year ended December 31, 2004 and 2003, respectively, we are dependent upon the sales prices of commodities, such as oil, natural gas and NGL products, which can fluctuate with winter weather conditions, and other changes in supply and demand.

Liquidity and Capital Resources

Overview

Our primary source of liquidity to meet operating expenses and fund capital expenditures (other than for larger acquisitions) is cash flow from operations. The public and institutional markets have been our principal source of capital to finance a majority of our growth (including acquisitions). During 2004, we increased our capital through the issuance of $187.0 million of additional equity and $225.0 million of long-term fixed rate debt. Since we have sold debt and equity in both public and private offerings in the past, we expect that these sources of capital will continue to be available to us in the future as we continue to grow and expand our operations. However, we caution that ready access to capital on reasonable terms and the availability of desirable acquisition targets at attractive prices are subject to many uncertainties.

The Partnership’s objective is to maintain a capital structure with approximately equal amounts of debt and equity. At December 31, 2004, we had long-term debt outstanding of $225.0 million. Total partners’ capital at that date was $241.1 million, which resulted in a long-term debt –to –total capital ratio of 48%.

Equity

During January 2004, we completed a secondary public offering of 1,100,444 common units, at $39.90 per unit for gross proceeds of $43.9 million. In addition, of the 172,200 common units available to underwriters to cover over-allotments, 72,500 were sold for gross proceeds of $2.9 million. To maintain its 2% interest, the general partner of the Partnership contributed $0.9 million. Total gross proceeds were $47.7 million less associated offering costs of $3.8 million, netting us approximately $43.9 million. As approximately $0.4 million of the offering costs had been incurred during fiscal 2003, net cash generated from the offering during 2004 was approximately $44.3 million. The funds were used to repay a portion of the outstanding indebtedness under our credit facility.

During July 2004, we completed a private placement of 1,304,438 common units, at $34.50 per unit for gross proceeds of $45.0 million. To maintain its 2% interest, the general partner of the Partnership contributed $0.9 million. Total gross proceeds were $45.9 million less associated offering costs of $0.9 million netting us approximately $45.0 million, which were used to finance our East Texas System acquisition.

On September 21, 2004, we completed a secondary public offering of 2,323,609 common units at $43.41 per unit for gross proceeds of $100.9 million and 157,395 common units were sold by certain selling unitholders. Of the 2,323,609 common units sold by us, 323,609 common units were sold pursuant to the underwriter’s over-allotment option. We did not receive any proceeds from the common units sold by the selling unitholders. Our total net proceeds from the offering, after deducting transaction costs of $5.2 million and including our general partner’s capital contribution of $2.1 million to maintain its 2% interest, were $97.8 million, which were used to repay a portion of the outstanding indebtedness under our amended and restated credit facility.

The inability of the Partnership to file its Annual Report on Form 10-K for the year ended December 31, 2004 and its quarterly report on Form 10-Q for the quarter ending March 31, 2005 on time may impact the timing of the Partnership’s efforts to raise equity in the future. We will no longer have the ability to incorporate by reference information from our filings into a new registration statement for one-year following the later of the filing of this Form 10-K, and the Form 10-Q for the quarter ending March 31, 2005 should the Partnership choose to raise capital through a public offering registered on Form S-3. If the Partnership raises additional capital through public debt or equity offerings, the Partnership will be required to file a Form S-1 registration statement, which is a long form type of registration statement. The requirement to file a Form S-1 registration statement may effect our ability to access the capital markets on a timely basis and will increase the costs of doing so.

The Partnership has the ability to issue an unlimited number of units to fund immediately accretive acquisitions. Under the provisions of the Partnership Agreement an immediately accretive acquisition is one that in the general partner’s good faith determination would have, if acquired by the Partnership as of the date that is one year prior to the first day of the quarter in which such acquisition is consummated, resulted in an increase to the amount of operating surplus generated by the Partnership on a per-unit basis (for all outstanding units) with respect to each of the four most recently completed quarters (on a pro forma basis) as compared to the actual amount of operating surplus generated by the Partnership on a per-unit basis (for all outstanding units), excluding operating surplus attributable to the acquisition with respect to each of such four most recently completed quarters. During 2003 and 2004, the Partnership consummated six acquisitions aggregating approximately $354.4 million that were partially funded by equity and debt offerings. For acquisitions that are not immediately accretive, the Partnership has the ability to issue up to 1,207,500 common units without unitholder approval.

Debt

Credit Facility. The Operating Company amended and restated its credit facility in July 2004, increasing the maximum lending limit from $140.0 million to $315.0 million. The proceeds from the secondary public offering and borrowings under the credit facility were used to finance the East Texas System acquisition. The credit facility included a $265.0 million revolving facility and a $50.0 million term-loan facility. The term-loan portion of the amended and restated credit facility was scheduled to mature in December 2004 and the revolving-portion was scheduled to mature in May 2005.

On October 25, 2004, the credit facility was, once again, amended and restated decreasing the maximum lending limit from $315.0 million to $200.0 million and increasing the term of the facility to five years. The credit facility includes a revolving facility up to $200.0 million (subject to the restrictive covenants discussed below) with the potential to increase the maximum lending limit to $300.0 million. The credit facility is guaranteed by the Partnership and all of our present and future subsidiaries and is collateralized by substantially all of our existing and future assets and those of our subsidiaries, including stock and other equity interests. At the Partnership’s option, the borrowing under the credit facility bears interest at a variable interest rate based on either (i) LIBOR plus an applicable margin, which is fixed at a rate of 2.75% for the first two quarters following the closing of the credit facility or (ii) Base Rate (as defined for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus ½ of 1% or (b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent of the debt as its “prime rate”) plus an applicable margin, which is fixed at a rate of 2.00% for the first two quarters following the closing of the credit facility. After that period, the applicable margin adjusts quarterly based on our ratio of funded debt to EBITDA (as defined in the agreement). For the years ended December 31, 2004, the weighted average interest rate was 4.48%.

In connection with the credit facility, we are subject to a number of restrictions on our business, including restrictions on our ability to grant liens on assets; merge, consolidate or sell assets; incur indebtedness (other than subordinated indebtedness); make acquisitions; engage in other businesses; enter into capital or operating leases; engage in transactions with affiliates; make distributions on equity interests and other usual and customary covenants. In addition, we are subject to certain financial maintenance covenants, including our ratios of total debt to EBITDA, total senior secured debt to EBITDA, EBITDA to interest and a minimum net worth requirement. Failure to comply with the provisions of any of these covenants could result in acceleration of our debt and other financial obligations. There was no debt outstanding under the facility at December 31, 2004 and, based on the covenants below, we had available borrowing capacity of approximately $63.3 million. The covenants are used to calculate the available borrowing capacity on a quarterly basis.

The credit facility contains covenants requiring the Partnership to maintain:

• a ratio of not less than 3.00 to 1.00 of consolidated EBITDA to consolidated interest expense for the prior four fiscal quarters;

• a ratio of not more than 5.0 to 1.00 of total consolidated debt to consolidated EBITDA for the prior four fiscal quarters;

• a minimum net worth of $200.0 million plus 50% of proceeds of equity issued subsequent to October 25, 2004; and

• a ratio of not more than 3.5 to 1.00 of consolidated senior debt to consolidated EBITDA for the prior four fiscal quarters.

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 agreement) to consolidated EBITDA (as defined in the agreement) for the four most recently completed fiscal quarters. The credit facility matures on October 23, 2009. At that time, the credit facility terminates and all outstanding amounts thereunder will be due and payable.

As the Partnership was unable to deliver its 2004 audited consolidated financial statements within 90 days of December 31, 2004, the Partnership was not in compliance with its debt covenants. The lending institutions of our credit facility have waived the 90 days delivery requirement until June 30, 2005.

Senior Notes. On October 25, 2004, we and our subsidiary MarkWest Energy Finance Corporation issued $225.0 million of senior notes at a fixed rate of 6.875% and with a maturity date of November 1, 2014. Subject to compliance with certain covenants, we may issue additional notes from time to time under the indenture. Interest on the notes accrues at the rate of 6.875% per year and is payable semi-annually in arrears on May 1 and November 1, commencing on May 1, 2005. We may redeem some or all of the notes at any time on or after November 1, 2009 at certain redemption prices together with accrued and unpaid interest to the date of redemption, and we may redeem all of the notes at any time prior to November 1, 2009 at a make-whole redemption price. In addition, prior to November 1, 2007, we may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a specified redemption price. If we sell certain assets and do not reinvest the proceeds or repay senior indebtedness, or if we experience specific kinds of changes in control, we must offer to repurchase notes at a specified price. Each of our existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and severally, fully and conditionally and for so long as such subsidiary guarantees any of our other debt. Not all of our future subsidiaries will be required to become guarantors. The notes are senior unsecured obligations equal in right of payment with all of our existing and future senior debt. These notes are senior in right of payment to all of our future subordinated debt but effectively junior in right of payment to our secured debt to the extent of the assets securing the debt, including our obligations in respect of our bank credit facility. The proceeds from these notes were used to pay down the remaining outstanding debt under our credit facility.

The indenture governing the senior notes limits the activity of the Partnership and certain of our subsidiaries, which we refer to as the restricted subsidiaries. The provisions of such indenture places limits, to a degree, on the ability of the Partnership and the restricted subsidiaries to incur additional indebtedness; declare or pay dividends or redeem, repurchase or retire such equity interest or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the restricted subsidiaries to pay dividends, make loans

or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interest of the Partnership’s subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. The debt incurrence covenants do not presently restrict our ability to borrow under or expand our credit facility. Currently, all of our subsidiaries are restricted subsidiaries.

The Partnership has agreed to file an exchange offer registration statement, or under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2004 senior notes. On February 22, 2005, the Partnership filed the exchange offer registration statement relating to the 2004 senior notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements and as a consequence is incurring an interest rate penalty of 0.5% until such time as the exchange offer is completed.

In addition, the indenture governing our outstanding senior notes contains restrictions on our ability to make cash distributions. Under the indenture, we are restricted from making a Restricted Payment if at the time of making the Restricted Payment, a default or an event of default has occurred and is continuing. The Partnership’s failure to file this Annual Report on Form 10-K for year ended December 31, 2004 and its Quarterly Report on Form 10-Q for the first quarter of 2005 within the time periods specified in the Securities and Exchange Commission’s rules and regulations constituted a default under the indenture, and the failure to file the Form 10-K within thirty days after the April 8, 2005 notice from the indenture trustee constituted an event of default under the indenture. On May 16, 2005, the Partnership paid a cash distribution to unitholders for the first quarter of 2005. This cash distribution, made while the event of default for failure to file its Form 10-K had occurred and was continuing, constituted a default under the indenture, and this default matured into an event of default thirty days after such Restricted Payment was made, or June 15, 2005. Both of these events of default are cured upon the filing of this Form 10-K and the Quarterly Report on Form 10-Q for the first quarter of 2005 prior to any declaration of acceleration of the senior notes by the trustee as a result of such events of default.

Liquidity Requirements

The Partnership has budgeted $47.8 million for capital expenditures for the year ending December 31, 2005, exclusive of any acquisitions, consisting of $46.3 million for expansion capital and $1.5 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. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations.

We believe that our available cash, cash provided by operating activities and funds available under our credit facility will be sufficient to fund our operating, interest and general and administrative expenses, our capital expenditure budget, our short-term contractual obligations and distribution payments at current levels for the foreseeable future. However, our ability to finance additional acquisitions will likely require the issuance of additional common units, the expansion of our credit facility, additional debt financing or a combination thereof. In the event that we desire or need to raise additional capital, we cannot guarantee that additional funds will be available at times or on terms favorable to us, if at all.

Our ability to pay distributions to our unitholders 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 largest 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 our liquidity.

Subsequent Events

On March 31, 2005, we acquired a 50% non-operating membership interest in Starfish Pipeline Company, LLC, from an affiliate of Enterprise Products Partners, L.P. for $41.7 million. Starfish owns the FERC regulated Stingray natural gas pipeline and the unregulated Triton natural gas gathering system and West Cameron dehydration facility, all located in the Gulf of Mexico and southwestern Louisiana. The acquisition was financed through the Partnership’s existing credit facility and will be accounted for under the equity method of accounting beginning in the first quarter of 2005.

On April 27, 2005, the board of directors of the general partner of MarkWest Energy Partners, L.P., declared the Partnership’s quarterly cash distribution of $0.80 per unit for the first quarter of 2005. This distribution represents an increase of $0.02 per unit, or 3%, over the previous quarterly distribution. The indicated annual rate is $3.20 per unit. The first quarter distribution of approximately $9.8 million was paid on May 16, 2005, to unitholders of record on May 6, 2005.

Cash Flow

	December 31,
	2004			2003
	(in thousands)

Net cash provided by operating activities	$	42,275		$	21,229
Net cash used in investing activities	(273,176		)	(112,893		)
Net cash provided by financing activities	246,411			97,641

Net cash provided by operating activities was higher in 2004 than in 2003 by $21.0 million, primarily due to an increase in operating income contributed by our 2003 and 2004 acquisitions before certain non-cash charges. We expect that overall our 2005 NGL volumes will be higher than in 2004, principally due to a full year of activity for our July 2004 East Texas acquisition, and that cash provided by operating activities in 2005 will exceed 2004 levels. However a precipitous decline in natural gas or NGL prices in 2005 would significantly affect the amount of cash flow that would be generated from operations.

Net cash used in investing activities was higher in 2004 than 2003 by $160.3 million because of our two 2004 acquisitions, which aggregated approximately $243.0 million. Total expenditures for our 2003 acquisitions were approximately $110.0 million. In addition, the Partnership used cash of $30.5 million in 2004 for capital expenditures, primarily as a result of the construction of new processing plants and gathering systems in East Texas to handle our future contractual commitments and for the new Cobb replacement processing facility. We had capital expenditures of $2.9 million in 2003. In 2005, we expect to use cash of $47.8 million for capital expenditures and we anticipate expanding our operations in 2005 through acquisitions provided the right opportunity and financing is available. As previously discussed, in the first quarter of 2005, we acquired a 50% non-operating membership interest in Starfish Pipeline Company, LLC for $41.7 million.

Net cash provided by financing activities during the year ended December 31, 2004 was $246.4 million. Our equity financings and borrowings under our credit facility and bond offering were primarily responsible for the inflow. The Partnership raised funds through two public offerings and one private offering of partnership units generating net proceeds of $187.0 million. In addition, the Partnership issued a net of $83.4 million of debt to finance its two acquisitions in 2004. The general partner of the Partnership provided funds of $0.6 million to fund construction activities at the Cobb processing plant. Distributions to unitholders were $24.6 million, representing an 84% increase over the $13.4 million paid in 2003.

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 in 2003. Additional funds were provided by a private placement of common units for $9.6 million, and a contribution by the general partner of $0.7 million to fund construction activities at the Cobb Processing Plant. Distributions to unitholders in 2003 were $13.4 million.

Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of December 31, 2004, is as follows, in thousands:

	Payment Due by Period
Type of obligation	Total obligation		Due in 2005		Due in 2006-2007		Due in 2008-2009		Thereafter

Long-term debt (1)	$	377,111	$	15,469	$	30,938	$	30,938	$	299,766
Operating leases	7,383		3,096		3,193		648		446
Purchase obligations	6,122		6,122		—		—		—
Total contractual cash obligations	$	390,616	$	24,687	$	34,131	$	31,586	$	300,212

(1) Includes interest on our 6.875% senior notes through 2014 of $152.1 million on our senior notes.

Annual rent expense under these operating leases was $3.3 million, $1.1 million and $0.6 million for the years ended December 31, 2004, 2003, and 2002, respectively.

Critical Accounting Policies

A summary of the significant accounting policies that we have adopted and followed in the preparation of our consolidated financial statements is presented in Note 2 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K. Certain of these accounting policies require the use of estimates. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment, and involve complex analysis. These estimates are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations.

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, the amount of impairment recognized is determined by estimating the fair value of the assets and recording a provision for the amount by which the carrying value exceeds fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is 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:

• 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 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; and

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

Any significant negative 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.

Valuation of Intangibles

Significant judgment is required in establishing the fair value and determining appropriate amortization periods for our intangible assets. Intangible assets acquired in a business combination are recorded under the purchase method of accounting at their estimated fair values at the date of acquisition, in accordance with SFAS No. 141, Business Combinations. The fair values of acquired intangible assets are determined by management using relevant information and assumptions. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate, which requires significant management judgment with respect to revenue and expense growth rates, and the selection and use of an appropriate discount rate. Amortization of intangible assets with finite useful lives is recorded over the estimated useful life of the asset. We assess the impairment of identifiable intangible assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable. At December 31, 2004, we had $162.0 million of net intangible assets. An impairment of our intangible assets could result in a material, non-cash expense in our consolidated statement of operations.

The Partnership applies SFAS No. 142 Goodwill and Other Intangible Assets in determining the life of its intangible assets. In establishing the amortization period for the customer contract intangible asset for the East Texas acquisition, which accounts for $161.9 million of the intangible assets, the Partnership considered the life of the assets to which the contracts relate, anticipated drilling activity in the area, likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs. As a result of an analysis of these factors, the customer contracts are expected to have an average life of 20 years, including anticipated renewals. Based on an independent third party analysis of the reserves in the area and the pertinent terms of the customer contracts, the Partnership has determined that a straight-line amortization method is appropriate and representative of the economic benefits of the intangible asset.

Because of the significant judgment required in determining the fair value and life and related method of amortization of customer contract intangible assets, actual cash flows could differ significantly from estimated amounts used to determine the fair value, life and amortization method of these intangible assets.

Recent Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise, or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement. The revised Statement requires that an entity account for those transactions using the fair-value-based method, and eliminates the intrinsic value method of accounting in APB 25, Accounting for Stock Issued to Employees, which was permitted under SFAS No. 123, as originally issued. The revised Statement requires entities to disclose information about the nature of the share-based payment transactions and the effects of those transactions on the financial statements. SFAS 123(R) is effective for public companies for the first fiscal year beginning after December 31, 2005. All public companies must use either the modified prospective or the modified retrospective transition method. We have not yet evaluated the impact of the adoption of this pronouncement on our financial statements. On March 29, 2005, the SEC staff issued SAB No. 107, Share-Based Payment, to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. The Partnership will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123(R).

In March 2005, the FASB issued FIN No. 47, Accounting for Conditional Asset Retirement Obligations,

which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. FIN 47 permits, but does not require, restatement of interim financial information. The provisions of FIN 47 are effective for reporting periods ending after December 15, 2005. The Partnership is currently evaluating the impact of adopting FIN 47 on its consolidated financial statements.

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.

Risks Inherent in Our Business

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

Our future growth will depend in part on our ability to integrate our recent acquisitions and our ability to make future acquisitions of assets and businesses at attractive prices. We recently completed the East Texas System, western Oklahoma and Michigan Crude Pipeline acquisitions, which geographically expanded our operations in the Southwest, particularly East Texas and Oklahoma, and expanded our operations in Michigan. We cannot assure you that we will successfully integrate these or any other acquisitions into our operations, or that we will achieve the desired profitability from such acquisitions. Failure to successfully integrate these substantial or future acquisitions could adversely affect our financial condition and results of operations.

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

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

• difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographical area;

• the loss of customers or key employees from the acquired businesses;

• the diversion of management’s attention from other business concerns;

• the failure to realize expected synergies and cost savings;

• coordinating geographically disparate organizations, systems and facilities;

• integrating personnel from diverse business backgrounds and organizational cultures; and

• consolidating corporate and administrative functions.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired assets that will be subject to the same stringent environmental laws and regulations relating to releases of pollutants into the environment and environmental protection as our existing plants, pipelines and facilities. Thus, our operation of these new assets could cause us to incur increased costs to attain or maintain compliance with such laws and regulations. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

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

A significant decrease in natural gas production in our areas of operation due to the decline in production from existing wells, depressed commodity prices, reduced drilling activities or other factors otherwise could adversely affect our revenues and operating income and cash flow.

Our profitability is materially impacted by the volume of natural gas we gather, transmit and process and NGLs we transport and fractionate at our facilities. A material decrease in natural gas production in our areas of operation would result in a decline in the volume of natural gas delivered to our pipelines and facilities for gathering, transporting and processing and NGLs delivered to our pipelines and facility for fractionation and transportation. The effect of such a material decrease would be to reduce our revenue and operating income. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the “decline rate.” In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. Failure to connect new wells to our gathering systems would, therefore, result in the amount of natural gas we gather, transmit and process and the amount of NGLs we transport and fractionate being reduced substantially over time and could, upon exhaustion of the current wells, cause us to abandon our gathering systems and, possibly, cease gathering operations. Our ability to connect to new wells will be dependent on the level of drilling activity in our areas of operations and competitive market factors. As a consequence of such declines, our revenues would be materially adversely affected.

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

We have substantial indebtedness and other financial obligations.

Subject to the restrictions governing our indebtedness and other financial obligations and the indenture governing the notes, we may incur significant additional indebtedness and other financial obligations, which may be secured and/or structurally senior to the notes.

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

• make it more difficult for us to satisfy our obligations with respect to the notes;

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

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

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

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

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

These restrictions could limit our ability and the ability of our subsidiaries to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. Our existing credit facility contains covenants requiring us to maintain specified financial ratios and satisfy other financial conditions. We may be unable to meet those ratios and conditions. Any future breach of any of these covenants or our failure to meet any of these ratios or conditions could result in a default under the terms of our credit facility, which could result in acceleration of our debt and other financial obligations. If we were unable to repay those amounts, the lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against the collateral.

A material decrease in the supply of crude oil available for transport through our Michigan Crude Pipeline, or a significant decrease in demand for refined products in the markets served by this pipeline, could adversely affect our revenues and cash flow.

The volume of crude oil we transport through our Michigan Crude Pipeline depends on the availability of crude oil produced in the areas accessible to our crude oil pipeline. If there were a material decrease in the volume of crude oil shipped on the pipeline due to reduced production from our shippers, less expensive supplies of crude oil available to the markets served by our pipeline, competition from trucks or reduced demand for refined product, such events may adversely affect our revenues and cash flow from the pipeline operations.

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

Although we obtain our supply of natural gas and NGLs from numerous third party producers, a significant portion is supplied by a limited number of key producers/suppliers who are committed to us under processing contracts. However, pursuant to many of these contracts or other supply arrangements, the producers are under no obligation to deliver a specific quantity of natural gas or NGLs to our facilities. If these key suppliers or a significant number of other producers were to decrease materially the supply of natural gas or NGLs to our systems and facilities for any reason, we could experience difficulty in replacing those lost volumes. Because our operating costs are primarily fixed, a reduction in the volumes of natural gas or NGLs delivered to us would result not only in a reduction of revenues but also a decline in net income and cash flow of similar or greater magnitude.

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

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

The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation and storage agreements may not escalate sufficiently to cover increases in costs and the agreements may not be renewed or may be suspended in some circumstances.

Our costs may increase at a rate greater than the rate that the fees we charge to third parties increase pursuant to our contracts with them. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of either natural gas, NGLs or crude oil are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of equipment or facilities of the Partnership or third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with us or if any third party suspends or terminates its contracts with us, our financial results would be negatively impacted.

We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could reduce our revenues and cash flow.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any increase in the nonpayment and nonperformance by our customers could reduce our revenues and cash flow.

We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines, and the price of, and demand for, natural gas, NGLs and crude oil in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of whom have greater financial resources and access to natural gas and NGL supplies than we do. Additionally, our customers who gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services. Certain of our competitors may also have advantages in competing for acquisitions or other new business opportunities because of their financial resources and access to natural gas and NGL supplies.

As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability. For more information regarding the competition that we have, please see Item 1 “Competition”, which is incorporated herein by reference.

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

The profitability of our natural gas processing and NGL fractionation operations is affected by volatility in prevailing NGL product and natural gas prices. Changes in the prices of NGL products have historically correlated closely with changes in the price of crude oil. Crude oil, NGL product and natural gas prices have been subject to significant volatility in recent years in response to relatively minor changes in the supply and demand for NGL products and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including:

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

• imports of crude oil, natural gas and NGLs;

• seasonality;

• the condition of the U.S. economy;

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

• domestic government regulation, legislation and policies.

The gross margins we realize under percent-of-proceeds and percent-of-index contracts, as well as our keep-whole contracts, are directly affected by changes in NGL product prices and natural gas prices, and are therefore more sensitive to volatility in commodity prices than our fee-based contracts. Additionally, changes in natural gas prices may indirectly impact our profitability since prices can influence drilling activity and well operations and thus the volume of gas we gather and process. In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue.

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

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

• damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;

• inadvertent damage from construction and farm equipment;

• leakage of crude oil, natural gas, NGLs and other hydrocarbons;

• fires and explosions; and

• other hazards, including those associated with high-sulfur content, or sour gas that could also result in personal injury and loss of life, pollution and suspension of operations.

As a result, we may be a defendant in various legal proceedings and litigation arising from our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, certain insurance premiums and deductibles could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

Transportation on certain of our pipelines may be subject to federal or state rate and service regulation, and the imposition and/or cost of compliance with such regulation could adversely affect our profitability.

Some of our gas, liquids and crude oil transmission operations may be subject to jurisdiction and rate and service regulations of the FERC or of various state regulatory bodies, depending upon the factual circumstances upon which each pipeline’s jurisdictional status is based. FERC generally regulates the transportation of natural gas and oil in interstate commerce, and FERC’s regulatory authority also extends to: facilities construction; acquisition, extension or abandonment of services or facilities; accounts and records; and depreciation and amortization policies. Intrastate natural gas pipeline operations are generally not subject to regulation by FERC, and some gathering systems are specifically exempted from FERC regulation by the Natural Gas Act (“NGA”), but such operations are often subject to regulation by various agencies of the states in which they are located. The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services, and FERC rate cases can involve complex and expensive proceedings.

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 and consequently should not be subject to regulation by the Federal Energy Regulatory Commission, or FERC. However, we cannot provide assurance that FERC would not determine that such transportation is within its jurisdiction. In such a case, we would be required to file a tariff for such transportation with FERC and provide a cost justification for the transportation charge. 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. Moreover, the likelihood of other entities seeking to utilize our Appalachian pipeline is remote. However, we cannot predict whether an assertion of FERC jurisdiction might be made with respect to this pipeline, nor provide assurance that such an assertion would not adversely affect our results of operations. With respect to the Michigan Crude Pipeline, one shipper recently contacted FERC to inquire about a transportation rate increase and the pipeline’s regulatory rate structure. In response, FERC requested that we contact the shipper to initiate a discussion with the shipper regarding its questions. We are presently in discussions with all shippers regarding rate structures and are attempting to resolve any issues they may have. FERC also requested that we file a tariff. While the Michigan Crude Pipeline operations are entirely within the state of Michigan and have been regulated by the State of Michigan, we have calculated and determined that our current and proposed rate structures are well below rates which would be allowed under FERC’s cost of service rate making structure. However, we cannot predict whether a FERC jurisdictional challenge might be made with respect to the Michigan Crude Pipeline, nor provide assurance that such a development would not adversely affect our results of operations or cash flow.

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.

Our business is subject to the jurisdiction of numerous governmental agencies that enforce complex and stringent laws and regulations with respect to a wide range of environmental, safety and other regulatory matters. We could be adversely affected by increased costs due to more strict pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental laws and regulations might adversely impact our products and activities, including the gathering, processing, transportation, fractionation, and storage of natural gas and NGLs and the transportation and storage of crude oil. Federal, state and local agencies also could impose additional safety requirements, any of which could affect our profitability. In addition, we face the risk of accidental releases or spills associated with our operations, which could result in material costs and liabilities, including those relating to claims for damages to property and persons. Failure by us to comply with environmental or safety related laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and even the issuance of injunctions that restrict or prohibit the performance of our operations. For more information regarding the environmental, safety and other regulatory matters that could affect our business, please see Item 1 “Regulatory Matters” and “Environmental Matters”, which is incorporated herein by reference.

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

The previous owner/operator of our Boldman and Cobb facilities has been or is currently involved in investigatory or remedial activities with respect to the real property underlying these facilities pursuant to an “Administrative Order by Consent for Removal Actions” with EPA Regions II, III, IV, and V in September 1994 and an “Agreed Order” entered into with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The previous owner/operator 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 or purchased the real property. In addition, the previous owner/operator 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 this indemnity from the previous owner/operator. Our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if in the future either the previous owner/operator or MarkWest Hydrocarbon fails to perform under the indemnification provisions of which we are the beneficiary.

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

All of the natural gas we process, gather and transmit is delivered into pipelines for further delivery to end-users. If these pipelines cannot or will not accept delivery of the gas due to downstream constraints on the pipeline, we will be forced to limit or stop the throughput of gas through our pipelines and processing systems. In addition, interruption of pipeline service upstream of our processing facilities would likewise limit or stop throughput through our processing facilities. Likewise, if the pipelines into which we deliver crude oil are interrupted, we will be limited in, or prevented from, conducting our crude oil transportation operations. Such interruptions or constraints on pipeline service may be caused by any number of factors beyond our control, including necessary and scheduled maintenance as well as unexpected damage to the pipeline. Since our revenues and gross margin depend upon the volumes of natural gas we process, gather and transmit, the throughput of NGLs through our transportation, fractionation and storage facilities and the volume of crude oil we gather and transport, any such limitation or reduction of volumes could result in a material reduction in our gross margin.

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

Our operations are dependent upon the infrastructure that we have developed, including processing and fractionation plants, storage facilities and various means of transportation. Any significant interruption at these facilities or pipelines or our inability to transmit natural gas or NGLs, or transport crude oil to or from these facilities or pipelines for any reason would adversely affect our results of operations. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:

• unscheduled turnarounds or catastrophic events at our physical plants;

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

• a disruption in the supply of crude oil to our crude oil pipeline, natural gas to our processing plants or gathering pipelines, or a disruption in the supply of NGLs to our transportation pipeline and fractionation facility.

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

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

Risks Related to Our Partnership Structure

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

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

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

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

Conflicts Relating to Control:

• employees of MarkWest Hydrocarbon who provide services to us also devote significant time to the businesses of MarkWest Hydrocarbon and are compensated by MarkWest Hydrocarbon for these services;

• neither our Partnership Agreement nor any other agreement requires MarkWest Hydrocarbon to pursue a future business strategy that favors us or utilizes our assets for processing, transportation or fractionation services we provide. MarkWest Hydrocarbon’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of MarkWest Hydrocarbon;

• our general partner is allowed to take into account the interests of parties other than us, such as MarkWest Hydrocarbon, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

• our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

• our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the processing, transportation and fractionation agreements with MarkWest Hydrocarbon;

• our general partner decides whether to retain separate counsel, accountants or others to perform services for us;

• in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units or to make incentive distributions or to hasten the conversion of subordinated units; and

• our Partnership Agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.

Conflicts Relating to Costs:

• our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to our unitholders;

• our general partner determines which costs incurred by MarkWest Hydrocarbon and its affiliates are reimbursable by us; and

• our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

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

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

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

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. First, our general partner generally may not be removed except upon the vote of the holders of at least 66 ²/₃% of the outstanding units voting together as a single class. Also, if our general partner is removed without cause during the subordination period and units held by MarkWest Hydrocarbon and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal under these circumstances would adversely affect the common units by prematurely eliminating their contractual right to distributions over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

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

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

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

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

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

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

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

Our Partnership Agreement contains provisions, which reduce the remedies available to unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.

Our Partnership Agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. The Partnership Agreement also restricts the remedies available to unitholders for actions that would otherwise constitute breaches of our general partner’s fiduciary duties. If you choose to purchase a common unit, you will be treated as having consented to the various actions contemplated in the Partnership Agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law.

MarkWest Hydrocarbon and its affiliates may engage in competition with us.

MarkWest Hydrocarbon and its affiliates may engage in competition with us. Pursuant to the Omnibus Agreement, MarkWest Hydrocarbon and its affiliates have agreed not to engage in, whether by acquisition, construction or otherwise, the business of processing natural gas and transporting, fractionating and storing NGLs. These restrictions, however, do 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 the conflicts committee of our general partner; 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 acquired or constructed; provided, however, that following completion of such acquisition or construction, we are provided the opportunity to purchase such restricted business, and we decline to do so with the concurrence of the conflicts committee of our general partner.

Upon a change of control of MarkWest Hydrocarbon or a sale of the general partner by MarkWest Hydrocarbon, the non-competition provisions of the Omnibus Agreement will terminate.

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

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

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

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

• the issuance of common units in connection with acquisitions or capital improvements that increase cash flow from operations per unit on a pro forma basis;

• the conversion of subordinated units into common units;

• the conversion of units of equal rank with the common units into common units under some circumstances;

• the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner;

• issuances of common units under our long-term incentive plan; or

• issuances of common units to repay indebtedness, the cost of which to service is greater than the distribution obligations associated with the units issued in connection with the debt’s retirement.

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

• our unitholders’ proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each unit may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

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

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

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

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

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

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

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

We have found material weaknesses in our internal controls that require remediation and concluded, pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, that our internal control over financial reporting at December 31, 2004 were not effective.

As we disclose in our Management’s Report on Internal Control over Financial Reporting in Part II, Item 9A, “Controls and Procedures”, of this Form 10-K, we have discovered deficiencies, including material weaknesses, in our internal control over financial reporting. While we are taking immediate steps to correct our internal control weaknesses, the material weaknesses that have been discovered will not be considered remediated until the new and improved internal controls operate for a period of time, are tested and it is concluded that such new and improved internal controls are operating effectively. Pending the successful completion of such testing and the hiring of additional personnel, we will perform mitigating procedures relating to our internal control weaknesses. If we fail to remediate any material weaknesses, we could be unable to provide timely and reliable financial information, which could have a material adverse effect on our business, results of operations or financial condition.

The inability of the Partnership to file this Annual Report on Form 10-K for the year ended December 31, 2004 and our Quarterly Report for the quarter ended March 31, 2005 on time has impacted the Partnership in various ways. The indenture governing our outstanding senior notes contains restrictions on our ability to make cash distributions. Under the indenture, we are restricted from making a Restricted Payment if at the time of making the Restricted Payment, a default or an event of default has occurred and is continuing. The Partnership’s failure to file this Annual Report on Form 10-K for year ended December 31, 2004 and its Quarterly Report on Form 10-Q for the first quarter of 2005 within the time periods specified in the Securities and Exchange Commission’s rules and regulations constituted a default under the indenture, and the failure to file the Form 10-K within thirty days after the April 8, 2005 notice from the indenture trustee constituted an event of default under the indenture. On May 16, 2005, the Partnership paid a cash distribution to unitholders for the first quarter of 2005. This cash distribution, made while the event of default for failure to file its Form 10-K had occurred and was continuing, constituted a default under the indenture, and this default matured into an event of default thirty days after such Restricted Payment was made, or June 15, 2005. Both of these events of default are cured upon the filing of this Form 10-K and the Quarterly Report on Form 10-Q for the first quarter of 2005 prior to any declaration of acceleration of the senior notes by the trustee as a result of such events of default.

In addition, as the Partnership was unable to deliver its audited consolidated financial statements within 90 days of December 31, 2004, the Partnership is not in compliance with its debt covenants for the credit facility. The lending institutions of our credit facility have waived the 90 days delivery requirement until June 30, 2005.

In addition, the inability of the Partnership to file this Annual Report on Form 10-K for the year ended December 31, 2004 on time may impact the timing of the Partnership’s ability to raise equity in the future. We will no longer have the ability to incorporate by reference into the registration statements for one-year following the filing of this Form 10-K should the Partnership choose to raise capital through a public offering registered on Form S-3. In effect, if the Partnership raises additional capital through public debt or equity offerings, the Partnership will be required to file a Form S-1 registration statement, which is a long form type of registration statement. The requirement to file a Form S-1 registration statement may effect our ability to access the capital markets on a timely basis and will increase the costs of doing so.

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 changes and to a lesser extent interest rate changes.

Commodity Price

Our primary risk management objective is to reduce volatility in our cash flows. A committee, which includes members of senior management of our general partner, oversees all of our hedging activity.

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

We enter into OTC swaps with financial institutions and other energy company counterparties. We conduct a standard credit review on counterparties and have agreements containing collateral requirements where deemed necessary. We use standardized swap agreements that allow for offset of positive and negative exposures. We are subject to margin deposit requirements under OTC agreements (with non-bank counterparties) and NYMEX positions.

As of December 31, 2004, we have hedged natural gas price risk in Texas (part of our Pinnacle acquisition) by entering into fixed-for-floating price swaps that settle monthly through December 31, 2005 as follows:

MMBtu	182,500
$/MMBtu	$	4.26

Interest Rate

Although we had no debt outstanding with a floating interest rate at year end, we would be exposed to changes in interest rates in the future if we were to draw on our Partnership Credit Facility. We may make use of interest rate swap agreements in the future, to adjust the ratio of fixed and floating rates in our debt portfolio.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated and Combined Financial Statements

Report of KPMG LLP, Independent Registered Public Accounting Firm

Report of PricewaterhouseCoopers, LLP, Independent Registered Public Accounting Firm

Consolidated Balance Sheets at December 31, 2004 and 2003

Consolidated and Combined Statements of Operations for each of the three years in the period ended December 31, 2004

Consolidated and Combined Statements of Comprehensive Income for each of the three years in the period ended December 31, 2004

Consolidated and Combined Statements of Changes in Capital for each of the three years in the period ended December 31, 2004

Consolidated and Combined Statements of Cash Flows for each of the three years in the period ended December 31, 2004

Notes to Consolidated and Combined Financial Statements

Report of Independent Registered Public Accounting Firm

The Board of Directors

MarkWest Energy GP, L.L.C.:

We have audited the accompanying consolidated balance sheet of MarkWest Energy Partners, L.P. and its subsidiaries as of December 31, 2004, and the related consolidated statements of operations, comprehensive income, changes in capital, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of MarkWest Energy Partners, L.P. and subsidiaries as of December 31, 2004, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of MarkWest Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 24, 2005 expressed an unqualified opinion on management’s assessment of, and an adverse opinion on the effective operation of, internal control over financial reporting.

KPMG LLP

Denver, Colorado

June 17, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 the results of their operations and their cash flows for each of the two years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the 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 the Public Company Accounting Oversight Board (United States), 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 described in Note 19 to the consolidated and combined financial statements, the Partnership has restated its consolidated and combined financial statements as of and for each of the two years in the period ended December 31, 2003.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
March 15, 2004, except for Notes 16 and 19,
as to which the date is May 24, 2005

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

	December 31,
	2004			2003
				(as restated, see note 19)
ASSETS
Current assets:

Cash and cash equivalents	$	24,263		$	8,753
Receivables, net of allowances of $211 and $80, respectively	41,890			11,102
Receivables from affiliate	5,846			2,417
Inventories	449			1,086
Other assets	511			223
Total current assets	72,959			23,581

Property, plant and equipment	335,430			224,534
Less: Accumulated depreciation	(54,795		)	(40,320		)
Total property, plant and equipment, net	280,635			184,214

Other assets:
Intangibles and other assets, net of accumulated amortization of $3,640 in 2004	162,001			84
Deferred financing costs, net of accumulated amortization of $5,496 and $1,275, respectively	13,650			3,747
Deferred offering costs	—			995
Investment in and advances to equity investee	177			250
Total other assets	175,828			5,076
Total assets	$	529,422		$	212,871

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	35,695		$	14,064
Payables to affiliate	7,003			1,524
Accrued liabilities	19,329			5,163
Fair value of derivative instruments	385			373
Total current liabilities	62,412			21,124

Long-term debt	225,000			126,200
Fair value of derivative instruments	—			125
Other liabilities	868			478
Commitments and contingencies (Note 13)

Capital:
General partner	5,160			1,135
Limited partners:
Common unitholders (7,642 and 2,814 units issued and outstanding at December 31, 2004 and 2003, respectively)	227,483			50,992
Subordinated unitholders (3,000 units issued and outstanding at December 31, 2004 and 2003, respectively)	8,813			13,315
Accumulated other comprehensive loss	(314		)	(498		)
Total capital	241,142			64,944
Total liabilities and capital	$	529,422		$	212,871

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

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

	Year Ended December 31,
	2004			2003			2002
				(as restated, see note 19)			(as restated, see note 19)
Revenues:
Sales to unaffiliated parties	$	242,288		$	67,580		$	44,153
Sales to affiliates	59,026			49,850			26,093
Total revenues	301,314			117,430			70,246

Operating expenses:
Purchased product costs	211,534			70,832			38,906
Facility expenses	29,911			20,463			15,101
Selling, general and administrative expenses	16,133			8,598			5,411
Depreciation	15,556			7,548			4,980
Amortization of intangible assets	3,640			—			—
Accretion of asset retirement obligation	13			—			—
Impairments	130			1,148			—
Total operating expenses	276,917			108,589			64,398

Income from operations	24,397			8,841			5,848

Other income (expense):
Interest income	87			14			5
Interest expense	(9,236		)	(3,087		)	(1,128		)
Amortization of deferred financing costs	(5,236		)	(984		)	(291		)
Miscellaneous income (expense)	(50		)	(25		)	52

Income before income taxes	9,962			4,759			4,486

Benefit for income taxes:
Current due from parent	—			—			(1,535		)
Deferred	—			—			(15,640		)
Benefit for income taxes	—			—			(17,175		)
Net income	$	9,962		$	4,759		$	21,661

Interest in net income (loss):
General partner	$	(723	)	$	(654	)	$	(39	)
Limited partners	$	10,685		$	5,413		$	21,700

Net income per limited partner unit:
Basic	$	1.31		$	0.95		$	4.86
Diluted	$	1.31		$	0.94		$	4.83

Weighted average units outstanding:
Basic	8,151			5,722			4,469
Diluted	8,177			5,773			4,493

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

MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)

	Year Ended December 31,
	2004		2003		2002
			(as restated, see note 19)		(as restated, see note 19)
Net income	$	9,962	$	4,759	$	21,661

Other comprehensive income (loss) – unrealized gains (losses) on commodity derivative instruments accounted for as hedges	184		213		(1,679		)

Comprehensive income	$	10,146	$	4,972	$	19,982

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

MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN CAPITAL
(in thousands)

				PARTNERS’ CAPITAL											Accumulated
	Net Parent			Limited Partners											Other
	Investment			Common				Subordinated				General			Comprehensive
	$			Units	Amount			Units	Amount			Partner			Income (Loss)			Total
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 exercise of underwriter over-allotment option), net of offering and other costs	—			2,415	43,625			—	—			—			—			43,625
Participation Plan compensation expense allocated from MarkWest Hydrocarbon, as restated	—			—	—			—	—			128			—			128
Distributions to unitholders	—			—	(1,715		)	—	(2,130		)	(78		)	—			(3,923		)
Net income applicable to the period from May 24 through December 31, 2002, as restated	—			—	1,948			—	2,420			(39		)	—			4,329
Other comprehensive loss	—			—	—			—	—			—			(1,679		)	(1,679		)
Balance at December 31, 2002, as restated	—			2,415	43,858			3,000	17,357			359			(711		)	60,863
Issuance of units in private placement, net of offering costs	—			375	9,747			—	—			217			—			9,964
Contributions by MarkWest Energy GP, LLC	—			—	—			—	—			695			—			695
Participation Plan compensation expense allocated from MarkWest Hydrocarbon, as restated	—			—	—			—	—			912			—			912
Common units issued for vested restricted units, including contribution by MarkWest Energy GP, LLC	—			24	952			—	—			20			—			972
Distributions to partners	—			—	(6,060		)	—	(6,960		)	(414		)	—			(13,434		)
Net income, as restated	—			—	2,495			—	2,918			(654		)	—			4,759
Other comprehensive income	—			—	—			—	—			—			213			213
Balance at December 31, 2003, as restated	$	—		2,814	$	50,992		3,000	$	13,315		$	1,135		$	(498	)	$	64,944

			PARTNERS’ CAPITAL											Accumulated
	Net Parent		Limited Partners											Other
	Investment		Common				Subordinated				General			Comprehensive
	$		Units	Amount			Units	Amount			Partner			Income (Loss)			Total
Balance at December 31, 2003, as restated	$	—	2,814	$	50,992		3,000	$	13,315		$	1,135		$	(498	)	$	64,944
Issuance of units in secondary offerings, net of offering costs	—		3,497	138,859			—	—			2,828			—			141,687
Issuance of units in private placement, net of offering costs	—		1,304	44,063			—	—			899			—			44,962
Common units issued for vested restricted units, including contribution by MarkWest Energy GP, LLC	—		27	1,154			—	—			25			—			1,179
Contributions by MarkWest Energy GP, LLC	—		—	—			—	—			567			—			567
Participation Plan compensation expense allocated from MarkWest Hydrocarbon	—		—	—			—	—			2,277			—			2,277
Distributions to partners	—		—	(14,192		)	—	(8,580		)	(1,848		)	—			(24,620		)
Net income	—		—	6,607			—	4,078			(723		)	—			9,962
Other comprehensive income	—		—	—			—	—			—			184			184
Balance at December 31, 2004	$	—	7,642	$	227,483		3,000	$	8,813		$	5,160		$	(314	)	$	241,142

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

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

	Year Ended December 31,
	2004			2003			2002
				(as restated, see note 19)			(as restated, see note 19)
Cash flows from operating activities:
Net income	$	9,962		$	4,759		$	21,661
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	15,556			7,548			4,980
Amortization of intangible assets	3,640			—			—
Amortization of deferred financing costs	5,236			984			291
Accretion of asset retirement obligation	13			—			—
Impairments	130			1,148			—
Restricted unit compensation expense	1,065			1,357			73
Participation Plan compensation expense	2,277			912			128
Equity in losses of investee	73			81			—
Unrealized loss on derivative instruments	71			—			—
Gain on sale of property, plant and equipment	(29		)	—			—
Deferred income taxes	—			—			(15,640		)
Other	27			21			(366		)
Changes in operating assets and liabilities, net of working capital assumed:
Increase in receivables	(33,377		)	(736		)	(43		)
(Increase) decrease in inventories	(203		)	(956		)	2,333
(Increase) decrease in other assets	(288		)	113			4,933
Increase in accounts payable and accrued liabilities	38,122			5,998			12,062
Increase in long-term replacement natural gas payable	—			—			3,090
Net cash provided by operating activities	42,275			21,229			33,502

Cash flows from investing activities:
East Texas System acquisition	(240,726		)	—			—
Hobbs Lateral acquisition	(2,275		)	—			—
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	(30,467		)	(2,944		)	(2,145		)
Payments on financing lease receivable	133			—			—
Proceeds from sale of property, plant and equipment	159			46			89
Net cash used in investing activities	(273,176		)	(112,893		)	(2,056		)

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

	Year Ended December 31,
	2004			2003			2002
				(as restated)			(as restated)
Cash flows from financing activities:
Proceeds from long-term debt	220,100			391,700			23,400
Repayment of long-term debt	(346,300		)	(286,900		)	(2,000		)
Proceeds from private placement of senior notes	225,000			—			—
Payments for debt issuance costs	(15,399		)	(3,995		)	(1,111		)
Proceeds from secondary public offerings, net	142,076			—			—
Proceeds from private placement, net	44,962			9,964			—
Proceeds from initial public offering, net	—			—			43,625
Payments for deferred offering costs	—			(389		)	—
Capital contributions from MarkWest Energy GP, LLC	592			695			—
Distributions to unitholders	(24,620		)	(13,434		)	(3,923		)
Distribution to MarkWest Hydrocarbon	—			—			(63,476		)
Net distributions to parent	—			—			(24,218		)
Debt due from parent	—			—			(967		)
Net cash provided by (used in) financing activities	246,411			97,641			(28,670		)

Net increase in cash	15,510			5,977			2,776
Cash and cash equivalents at beginning of year	8,753			2,776			—
Cash and cash equivalents at end of year	$	24,263		$	8,753		$	2,776

Supplemental disclosures of cash flow information:

Cash paid during the year for interest, net of amounts capitalized	$	6,532		$	2,068		$	499

Supplemental schedule of non-cash investing and financing activities:

Construction projects in progress obligation	$	4,037		$	—		$	—

Property, plant and equipment asset retirement obligation	$	377		$	450		$	—

Deferred offering costs payable	$	—		$	606		$	—

The accompanying notes are an integral part of these consolidated 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). The Partnership is engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of natural gas liquids and the gathering and transportation of crude oil. The Partnership is a 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 six acquisitions completed during 2003 and 2004, the Partnership has expanded its natural gas gathering, processing and transmission geographic coverage to the southwest United States. In addition, one of the Partnership’s acquisitions has allowed it to enter into the Michigan crude oil transportation business. The Partnership’s principal executive office is located in Englewood, Colorado.

On May 24, 2002, 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 the Partnership’s initial public offering (the IPO) and the Operating Company’s $60.0 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.

In the IPO, the Partnership 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 $60.0 million credit facility with its 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 distribution to MarkWest Hydrocarbon	63,476

Net proceeds retained as working capital	$	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. 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. The consolidated financial statements of the Partnership subsequent to May 24, 2002 include charges from MarkWest Hydrocarbon for direct costs and allocation of indirect corporate overhead as more fully described in Note 7.

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. Some of the most significant areas in which management uses estimates and assumptions are in the valuation of identified intangible assets, in determining the fair value of derivative instruments, in determining impairments of long lived assets, in establishing estimated useful lives for long-lived assets and in the determination of liabilities, if any, for legal contingencies.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation.

Cash and Cash Equivalents

The Partnership considers investments in highly liquid financial instruments purchased with an original maturity of 90 days or less to be cash equivalents. Such investments include money market accounts.

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 of contractually dedicated reserves behind the Partnership’s facilities, whichever is shorter; buildings—40 years; furniture, leasehold improvements and other—3 to 10 years.

Capitalization of Interest

The Partnership capitalizes interest on major projects during construction. For the year ended December 31, 2004, the Partnership capitalized $0.8 million of interest. The Partnership did not capitalize interest for the years ended December 31, 2003 and 2002 as there were no major construction projects during those years.

Valuation of Intangibles

Intangible assets acquired in a business combination are recorded under the purchase method of accounting at their estimated fair values at the date of acquisition, in accordance with SFAS No. 141, Business Combinations. The fair values of acquired identifiable intangible assets are determined by management using relevant information and assumptions. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate, which requires significant management judgment with respect to revenue and expense growth rates, and the selection and use of an appropriate discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset in accordance with SFAS No. 142, Goodwill and Other Intangible Assets.

Impairment of Long-Lived Assets

In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership evaluates its long-lived assets, including intangibles, 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, the amount of impairment recognized is determined by estimating the fair value of the assets and recording a provision for the amount by which the carrying value exceeds fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.

When determining whether impairment of one of the Partnership’s long-lived assets has occurred, the Partnership must estimate the undiscounted cash flows attributable to its assets or asset groups. Such an 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 additional reserves developed by future drilling activity is dependent in part on natural gas prices. Projections of reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset.

Deferred Financing Costs

Deferred financing costs are being amortized over the estimated lives of the related obligations, which approximates the effective interest method. The amortization of deferred financing costs also include the acceleration of amortization due to the refinancing of debt. Total accelerated amortization included in deferred financing costs for the year ended December 31, 2004 was $1.5 million.

Accrued Liabilities

Accrued liabilities consist of the following:

	December 31,
	2004		2003
	(in thousands)

Product purchases	$	7,938	$	866
Interest payable	2,876		396
Construction in-progress accruals	2,602		—
Production taxes payable	1,078		215
Deferred income	2,625		355
Other accruals	2,210		3,331
Total accrued liabilities	$	19,329	$	5,163

Contingencies

The Partnership is involved in various legal actions, the outcomes of which are not within the Partnership’s complete control and may not be known for prolonged periods of time. In some actions, the claimants seek damages, as well as other relief, which, if granted, would require significant expenditures. The Partnership records a liability in the consolidated financial statements for these actions when a loss is known or considered probable and the amount can be reasonably estimated. The Partnership reviews these estimates each accounting period as additional information is known and adjusts the loss accrual when appropriate. If the loss is not probable or cannot be reasonably estimated, a liability is not recorded in the consolidated financial statements.

Derivative Instruments

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized 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. Any change in the fair value resulting from ineffectiveness, is recognized immediately in earnings. For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in earnings. The Partnership formally documents, designates and assesses the effectiveness of transactions receiving hedge accounting treatment. Results of NGL and natural gas derivative transactions are reflected in revenue,

and results of interest rate hedging transactions are reflected in interest expense. Hedge ineffectiveness on NGL and natural gas derivatives is reported in revenue.

Fair Value of Financial Instruments

Cash and Cash Equivalents, Receivables, Accounts Payable and Other Current Liabilities. The carrying amount approximates fair value because of the short-term maturity of these instruments.

Fair Value of Derivative Instruments. Fixed for-floating natural gas and NGL price swaps are recorded at fair value in the consolidated balance sheet.

Debt. The carrying value of the Partnership’s credit facility approximates fair value since the facility bears interest at current market interest rates. The fair value of the senior notes was approximately $225.0 million at December 31, 2004 based on quoted market prices.

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 Partnership records a receivable or payable for such imbalances based upon the contractual terms of the purchase agreements. The Partnership had an imbalance payable of $0.1 million and $0.7 million and an imbalance receivable of $1.4 million and $1.9 million at December 31, 2004 and 2003, respectively. Revenues for the transportation of crude are based upon regulated tariff rates and the related transportation volumes and are recognized when delivery of crude is made to the purchaser or other common carrier pipeline. Revenue for NGL product sales are recognized at the time the product is delivered and title is transferred.

Incentive Compensation Plans

As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, the Partnership has elected to continue to measure compensation costs for unit-based employee compensation plans as prescribed by APB 25, Accounting for Stock Issued to Employees, as permitted under SFAS No. 123, Accounting for Stock Based Compensation, and SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure. The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. In accordance with APB 25, the Partnership applies variable accounting for the plan because a phantom unit is an award to an employee entitling them to increases in the market value of the Partnership’s units subsequent to the date of grant without issuing units to the employees, similar to a stock appreciation right. As a result, the Partnership is required to mark to market the awards at the end of each reporting period. Compensation expense is measured for the phantom unit grants using the market price of MarkWest Energy Partners’ common units on the date the units are granted. The fair value of the units awarded is amortized into earnings over the period of service, adjusted quarterly for the change in the fair value of the unvested units granted. The phantom units vest over a stated period. For certain employees vesting is accelerated if certain performance measures are met. The accelerated vesting criteria provisions are based on annualized distribution goals. If the Partnership’s distributions are at or above the goal for a certain number of consecutive quarters, vesting of the employee’s phantom units is accelerated. However, the vesting of any phantom units may not occur until at least one year following the date of grant. The general partner of the Partnership may also elect to accelerate the vesting of outstanding awards, which results in an immediate charge to operations for the unamortized portion of the award.

MarkWest Hydrocarbon also has entered into arrangements with certain employees and directors of MarkWest Hydrocarbon. These arrangements are referred to as the Participation Plan. Under the Participation Plan, MarkWest Hydrocarbon sells subordinated partnership units of the Partnership and interests in the Partnership’s general partner to employees and directors of MarkWest Hydrocarbon under a purchase and sale agreement. In accordance with the provisions of APB 25, Accounting for Stock Issued to Employees, the Participation Plan is accounted for as a

variable plan. Since the employee and director are 100% vested on the date they purchase the subordinated units or general partner interests, compensation expense for the subordinated units is measured as the difference in the market value of the subordinated Partnership units and the amount paid by those individuals. Compensation related to the general partner interest is calculated as the difference in the formula value and the amount paid by those individuals. The formula value is the amount MarkWest Hydrocarbon would have to pay the directors and employees to repurchase the general partner interests and is based on the current market value of the Partnership’s common units and the current quarterly distribution paid. Increases or decreases in the market value of the subordinated units and the formula value of the general partner interests between the date they are acquired and the end of each reporting period result in a change in the measure of compensation, which is reflected currently in operations.

Under Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses And Related Disclosure In Financial Statements of Subsidiaries, Divisions Or Lesser Business Components of Another Entity compensation expense related to services provided by MarkWest Hydrocarbon’s employees and directors recognized under the Participation Plan should be allocated to the Partnership. The allocation is based on the percent of time that each employee devotes to the Partnership. Compensation attributable to interests that were sold to individuals who serve on both the Partnership’s board of directors and on the board of directors of MarkWest Hydrocarbon is allocated equally. The Partnership recorded compensation expense under the Participation Plan of $2.3 million, $0.9 million and $0.1 million for the year ended December 31, 2004, 2003 and 2002, respectively. Under the Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P. (“Partnership Agreement”), the general partner is deemed to have made a capital contribution equal to the compensation expense recorded under this plan, with the compensation expense allocated 100% to the general partner.

These charges are included in selling, general and administrative expenses. Assuming the compensation cost for the Long-Term Incentive Plan and the Participation Plan had been determined based on the fair-value methodology of SFAS No. 123, the net income and earnings per share would have been the same as reported on the financial statements for the year ended December 31, 2004, 2003, and 2002, respectively.

Income Taxes

The Partnership is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal income tax. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes related to the Partnership.

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 differently than in its 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.

Comprehensive Income

Comprehensive income includes net income and other comprehensive income (loss), which includes, unrealized gains and losses on commodity or interest rate derivative financial instruments accounted for as hedges.

Earnings per unit

Basic earnings per unit was computed by dividing net income allocated to the limited partners by the weighted average number of units outstanding for the years ended December 31, 2004, 2003 and 2002. The computation of diluted earnings per unit further assumes the dilutive effect of phantom units outstanding.

The following are the number of units used to compute the basic and diluted earnings per limited partner unit for the year ended December 31, 2004, 2003 and 2002 (in thousands):

	2004	2003	2002

Basic earnings per unit:
Weighted average limited partner units outstanding	8,151	5,722	4,469
Diluted earnings per unit:
Weighed average limited partner units outstanding	8,151	5,722	4,469
Dilutive effect of restricted units outstanding	26	51	24
Diluted units	8,177	5,773	4,493

Segment Reporting

The Partnership’s business segments consist of five principal geographic areas of operations: East Texas, Oklahoma, Other Southwest, Appalachia, and Michigan.

Recent Accounting Pronouncement

In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise, or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement. The revised Statement requires that an entity account for those transactions using the fair-value-based method, and eliminates the intrinsic value method of accounting in APB 25, Accounting for Stock Issued to Employees, which was permitted under SFAS No. 123, as originally issued. The revised Statement requires entities to disclose information about the nature of the share-based payment transactions and the effects of those transactions on the financial statements. SFAS 123(R) is effective for public companies for the first fiscal year beginning after December 31, 2005. All public companies must use either the modified prospective or the modified retrospective transition method. We have not yet evaluated the impact of the adoption of this pronouncement, which must be adopted in the first quarter of calendar year 2006. On March 29, 2005, the SEC staff issued SAB No. 107, Share-Based Payment, to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. The Partnership will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123(R).

In March 2005, the FASB issued FIN No. 47, Accounting for Conditional Asset Retirement Obligations, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. FIN 47 permits, but does not require, restatement of interim financial information. The provisions of FIN 47 are effective for reporting periods ending after December 15, 2005. The Partnership is currently evaluating the impact of adopting FIN 47 on its consolidated financial statements.

3. Acquisitions

East Texas System Acquisition

On July 30, 2004, the Partnership completed the East Texas System acquisition of American Central Eastern Texas’ Carthage gathering system and gas processing assets located in East Texas for approximately $240.7 million. The Partnership’s consolidated financial statements include the results of operations of the Carthage gathering system from July 30, 2004. The assets acquired consist of processing plants, gathering systems, a processing facility currently under construction and an NGL pipeline to be completed in 2005.

In conjunction with the closing of the acquisition, the Partnership completed a private offering of 1,304,438 common units, at $34.50 per unit, representing approximately $45.0 million in proceeds after transaction costs of approximately $0.9 million and including a contribution from the general partner of $0.9 million to maintain its ownership interest. In addition, The Partnership amended and restated the credit facility, increasing the maximum lending limit from $140.0 million to $315.0 million. The credit facility included a $265.0 million revolving facility and a $50.0 million term loan facility. The Partnership used the proceeds from the private offering and borrowings of $195.7 million under the credit facility to finance the East Texas System acquisition.

The total adjusted purchase price was $240.7 million, and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	240,269
Direct acquisition costs	457
Total	$	240,726

Allocation of acquisition costs:
Customer contracts	$	165,379
Property, plant and equipment	76,012
Inventory	65
Imbalance payable	(337		)
Property taxes payable	(393		)
Total	$	240,726

Hobbs Lateral Acquisition

On April 1, 2004, the Partnership acquired the Hobbs Lateral pipeline for approximately $2.3 million. The Hobbs Lateral consisted of a four-mile pipeline, with a capacity of 160 million cubic feet of natural gas per day, connecting the Northern Natural Gas interstate pipeline to Southwestern Public Service’s Cunningham and Maddox power generating stations in Hobbs, New Mexico. The Hobbs Lateral is a New Mexico intrastate pipeline regulated by the Federal Energy Regulatory Commission.

Michigan Crude Pipeline

On December 18, 2003, the Partnership completed the acquisition (the “Michigan Crude Pipeline acquisition”) of Shell Pipeline Company, LP’s and Equilon Enterprises, LLC’s Michigan Crude Gathering Pipeline, for approximately $21.3 million. The results of operations of the system have been included in the Partnership’s consolidated financial statements since December 18, 2003. The $21.3 million purchase price was financed through borrowings under the Partnership’s line of credit.

The system is a common carrier Michigan intrastate pipeline and gathers light crude oil from wells. The system extends from production facilities near Manistee, Michigan to a storage facility near Lewiston, Michigan. The trunk line consisted 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. The oil is transported for a fee to the

Lewiston station where it is batch injected into the Enbridge Lakehead Pipeline, which then transports the crude oil to refineries in Sarnia, Ontario, Canada.

The purchase price was comprised of $21.3 million paid in cash plus direct acquisition costs and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	21,155
Direct acquisition costs	128
Total	$	21,283

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

Western Oklahoma Acquisition

On December 1, 2003, the Partnership completed the acquisition of American Central Western Oklahoma Gas Company, L.L.C. for approximately $38.0 million. Results of operations of the acquired assets have been included in the Partnership’s consolidated financial statements since that date.

The assets acquired include the Foss Lake gathering system located in the western Oklahoma counties of Roger Mills and Custer. The acquired gathering system was comprised of approximately 167 miles of pipeline, connected to approximately 270 wells, and 11,000 horsepower of compression facilities. The assets also included the Arapaho gas processing plant.

The purchase price of approximately $38.0 million was financed through borrowings under the credit facility.

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

Acquisition costs:
Cash consideration	$		37,850
Direct acquisition costs	101
Total	$	37,951

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

Lubbock Pipeline Acquisition

Effective September 2, 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 the credit facility. The results of operations of the Lubbock Pipeline have been included in the Partnership’s consolidated financial statements since that date.

Pinnacle Acquisition

On March 28, 2003, the Partnership 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”). The assets acquired were comprised of three lateral natural gas pipelines and twenty gathering systems. Pinnacle’s results of operations have been included in the Partnership’s consolidated

financial statements since that date. The purchase price was financed through borrowing under the Partnership’s line of credit.

The purchase price was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$		39,471
Direct acquisition costs	450
Current liabilities assumed	8,945
Total	$		48,866

Allocation of acquisition costs:
Current assets	$	10,643
Fixed assets	38,223
Total	$	48,866

Pro Forma Results of Operations (unaudited)

The following table reflects the pro forma consolidated results of operations for the periods presented, as though the Pinnacle acquisition, the Western Oklahoma acquisition, the Michigan Crude Pipeline acquisition and the East Texas System acquisition each had occurred as of the beginning of the periods presented. The unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results. The unaudited pro forma results of operations for the Hobbs Lateral acquisition and the Lubbock Pipeline acquisition have not been presented, as these acquisitions were not significant.

	Year Ended December 31,
	2004		2003
			(as restated, see note 19)
	(in thousands, except per unit amounts)
Revenue	$	321,992	$	209,699
Net income (loss)	$	11,745	$	(4,233	)
Net income (loss) per limited partner	$	12,432	$	(3,380	)

Net income (loss) per limited partner unit:
Basic	$	1.17	$	(0.32	)
Diluted	$	1.17	$	(0.32	)
Weighted average units outstanding:
Basic	10,629		10,589
Diluted	10,655		10,640

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, the Partnership reviewed current laws and regulations governing obligations for asset retirements as well as the leases. Based on that review, the Partnership identified certain land leases in East Texas that contain provisions requiring the Partnership to return the land to its original condition upon the termination of the lease. Based on the review of the leases, the Partnership recorded an asset retirement obligation of $0.4 million during the year ended December 31, 2004, using an estimated average term of the leases of 25 years. Accretion expense for the year ended December 31, 2004 was less than $0.1 million.

In accordance with SFAS No. 143, the Partnership has identified certain assets that have an indeterminate life, and thus a future retirement obligation is not determinable. These assets include certain pipelines and processing plants. A liability for these asset retirement obligations will be recorded when a fair value is determinable.

The asset retirement obligation associated with the Partnership’s remaining facilities was insignificant and not recognized in the financial statements.

In October 2003, the board of directors of the general partner approved a plan to shut down the existing Cobb processing facility, and construct a replacement facility. Construction of the new facility was completed in the first quarter of 2005. During the fourth quarter of 2003, the Partnership estimated the amount of the asset retirement obligation associated with the shut down of the old Cobb facility to be $0.5 million, and, accordingly, it recorded a related accrued liability. At December 31, 2004, the asset retirement obligation was $0.5 million.

At January 1 and December 31, 2004 and 2003, there were no assets legally restricted for purposes of settling asset retirement obligations.

The following is a reconciliation of the changes in the asset retirement obligation from January 1, 2003, to December 31, 2004 (in thousands):

Asset retirement obligation as of January 1, 2003	$	—
Change in estimated asset retirement obligation	450
Asset retirement obligation as of December 31, 2003	450
Liability accrued in connection with East Texas acquisition	377
Accretion expense	13
Asset retirement obligation as of December 31, 2004	$	840

5. Property, Plant and Equipment

Property, plant and equipment consists of:

		December 31,
		2004			2003
		(in thousands)

Gas gathering facilities		$	160,763		$	73,424
Gas processing plants		56,239			55,888
Fractionation and storage facilities		22,112			22,160
Natural gas pipelines		38,167			38,790
Crude oil pipelines		18,499			18,352
NGL transportation facilities		4,381			4,415
Land, building and other equipment		6,510			9,664
Construction in-progress		28,759			1,841
		335,430			224,534
Less:	Accumulated depreciation	(54,795		)	(40,320		)
	Total property, plant and equipment, net	$	280,635		$	184,214

During 2004, the Partnership recorded an impairment charge of approximately $0.1 million. The charge related to plant processing equipment taken out of service.

Cobb Processing Plant

During 2003, the Partnership entered into an agreement with MarkWest Hydrocarbon for the construction of a new Cobb processing plant. Initially, the Partnership expected the construction costs of the new plant and the costs to decommission and dismantle the old plant to be approximately $2.1 million. In the third quarter of 2004, this estimate was revised to $3.6 million to construct the new plant and $0.5 million to decommission and dismantle the old plant. Construction was completed in the second quarter of 2005 at a cost of $3.6 million. Upon the completion of the new plant, the Partnership ceased operating the existing Cobb processing plant.

As of December 31, 2003, and in accordance with SFAS No. 144, the Partnership determined that the carrying value of the old processing plant of $1.4 million exceeded its estimated fair value of $0.3 million. Consequently, the Partnership has reflected an impairment of $1.1 million in the statement of operations for the year ended December 31, 2003.

On December 31, 2004, the general partner and the Partnership amended the Partnership Agreement to provide for the contribution of $1.7 million by the general partner. In exchange for the contribution, the amendment specifies that the first $1.7 million of depreciation deductions attributable to the new plant will be allocated to the general partner. For the years ended December 31, 2004 and 2003, costs of $0.6 million and $0.7 million, respectively, have been funded by MarkWest Energy GP, L.L.C., which amounts have been reflected as an increase in partners’ capital.

6. Intangible Assets Subject to Amortization

On July 30, 2004, the Partnership completed the acquisition of American Central Eastern Texas’ Carthage gathering system and gas processing assets located in East Texas for approximately $240.7 million. Of the total purchase price, $165.4 million was allocated to amortizable identifiable intangible assets (i.e., customer contracts) based on the net present value of the projected cash flows from these contracts. The key variables in determining the valuation of the customer contracts were the assumption of renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, and pricing volatility. The Partnership is amortizing the carrying value of these customer contracts on a straight-line basis over their average estimated economic life of 20 years. The estimated economic life was determined by assessing the life of the assets to which the contracts relate, likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

Other intangible assets include primarily customer contracts acquired in 2003 for $274,000 that are being amortized through June of 2005.

The Partnership’s intangible assets at December 31, 2004, are composed of customer contracts which are being amortized over the following estimated useful lives (in thousands):

	Gross		Accumulated Amortization		Net
20 years	$	165,379	$	3,446	$	161,933
1 year	288		220		68
Total	$	165,667	$	3,666	$	162,001

Amortization expense related to the intangible assets was $3.6 million for the year ended December 31, 2004.

Estimated future amortization expense related to the intangible assets at December 31, 2004 is as follows (in thousands):

Year ending December 31:
2005	$	8,337
2006	8,269
2007	8,269
2008	8,269
2009	8,269
Thereafter	120,588
Total	$	162,001

7. 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.

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

• A gas processing agreement pursuant to which MarkWest Hydrocarbon delivers to us all natural gas it receives from third party producers for processing at the 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 most of its NGLs to us for transportation through the pipeline to the Partnership’s Siloam fractionator. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for transportation.

• A fractionation agreement pursuant to which MarkWest Hydrocarbon delivers all of its NGLs to us for unloading, fractionation, loading and storage at the Partnership’s Siloam facility. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for fractionation, 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 the Partnership delivers and sells, all of the NGL products the Partnership produces pursuant to the Partnership’s gas processing agreement with a third party. Under the terms of this agreement, MarkWest Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale to third parties of such NGL products. This contract also applies to any other NGL products the Partnership acquires. The Partnership retains a percentage of the proceeds attributable to the sale of the NGL products it produces pursuant to its agreement with a third party, and remit the balance of the proceeds from such NGL products sales to this third party.

Under the Services Agreement with MarkWest Hydrocarbon, MarkWest Hydrocarbon continues to provide centralized corporate functions such as accounting, treasury, engineering, information technology, insurance and other corporate services. The Partnership reimburses MarkWest Hydrocarbon monthly for the selling, general and administrative expenses MarkWest Hydrocarbon allocates to us. For the years ended December 31, 2004, 2003 and 2002, MarkWest Hydrocarbon allocated approximately $8.7 million, $5.3 million and $4.2 million, respectively, of selling, general and administrative expenses to us.

The Partnership also reimburses MarkWest Hydrocarbon for the salaries and employee benefits, such as 401(k) and health insurance, of plant operating personnel as well as other direct operating expenses. For the years ended December 31, 2004, 2003 and 2002, these costs totaled $9.1 million, $6.2 million and $2.6 million, respectively, and are included in facility expenses. The Partnership has no employees.

In Michigan, the Partnership assumed the Midstream Business’s existing third party contracts. As a result, the Partnership gathers and processes gas directly for those third parties. The Partnership receives 100% of all fee and percent-of-proceeds consideration for the first 10,000 Mcf/d that is gathered in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and processing income earned on Michigan pipeline throughput in excess of 10,000 Mcf/d, calculated quarterly. For years ended December 31, 2004, 2003 and 2002, MarkWest Hydrocarbon’s net profit interest was $0.5 million, $0.9 million and $0.4 million, respectively, which amounts are included in facility expenses.

8. Long-Term Debt

Credit Facility

In October 2004, the Operating Company entered into the third amended and restated credit agreement (“Partnership Credit Facility”), which provides for a maximum lending limit of $200.0 million for a term of five years. The credit facility includes a revolving facility of $200.0 million with the potential to increase the maximum lending limit to $300.0 million. The credit facility is guaranteed by the Partnership and all of the Partnership’s subsidiaries and is collateralized by substantially all of the Partnership’s assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate based on one of two indices that include either (i) LIBOR plus an applicable margin, which was fixed at a rate of 2.75% for the first two quarters following the closing of the credit facility or (ii) Base Rate (as defined for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus ½ of 1% or (b) the rate of interest in effect for such day as publicly announced from time to time by the administrative agent of the debt as its “prime rate”) plus an applicable margin, which margin is fixed at a rate of 2.00% for the first two quarters following the closing of the credit facility. After that period, the applicable margin adjusts quarterly based on the ratio of funded debt to EBITDA (as defined in the credit agreement). For the years ended December 31, 2004 and 2003, the weighted average interest rate on the credit facility was 4.48% and 4.69%, respectively.

Under the provisions of the Partnership Credit Facility, the Partnership is subject to a number of restrictions on its business, including restrictions on its ability to grant liens on assets; make or own certain investments; enter into any swap contracts other than in the ordinary course of business; merge, consolidate or sell assets; incur indebtedness (other than subordinated indebtedness); make acquisitions; engage in other businesses; enter into capital or operating leases; engage in transactions with affiliates; make distributions on equity interests; declare or make, directly or indirectly any restricted payments.

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

• a ratio of not less than 3.00 to 1.00 of consolidated EBITDA to consolidated interest expense for the prior four fiscal quarters;

• a ratio of not more than 5.00 to 1.00 of total consolidated debt to consolidated EBITDA for the prior four fiscal quarters;

• a ratio of not more than 3.5 to 1.00 of Consolidated senior debt to Consolidated EBITDA for the prior four fiscal quarters; and

• a minimum net worth of $200.0 million plus 50% of proceeds from partnership interests issued subsequent to October 25, 2004.

These covenants are used to calculate the available borrowing capacity on a quarterly basis. The calculation takes into consideration the cash flow contribution of any future acquisitions at the time of closing. 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 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 on October 23, 2009. At that time, the Partnership Credit Facility terminates and all outstanding amounts thereunder are due and payable.

There is no debt outstanding under the Partnership Credit Facility at December 31, 2004 and, based on the covenants above, the Partnership had available borrowing capacity of approximately $63.3 million. The available borrowing capacity at December 31, 2004 was calculated, using the most restrictive debt covenant, as the amount that, when added to existing debt, would provide a maximum leverage ratio of 5.0 to 1.0.

As the Partnership was unable to deliver its 2004 audited consolidated financial statements within 90 days of December 31, 2004, the Partnership was not in compliance with its debt covenants. The lending institutions of the credit facility have waived the 90 days delivery requirement until June 30, 2005.

Senior Notes

In October 2004, the Partnership and its subsidiary, MarkWest Energy Finance Corporation, issued $225.0 million of senior notes due November 1, 2014 pursuant to Rule 144A and Regulation S under the Securities Act of 1933. Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indenture. Interest on the notes accrues at the rate of 6.875% per year and is payable semi-annually in arrears on May 1 and November 1, commencing on May 1, 2005. The Partnership may redeem some or all of the notes at any time on or after November 1, 2009 at certain redemption prices together with accrued and unpaid interest to the date of redemption, and the Partnership may redeem all of the notes at any time prior to November 1, 2009 at a make-whole redemption price. In addition, prior to November 1, 2007, the Partnership may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a stated redemption price. If the Partnership sells certain assets and does not reinvest the proceeds or repay senior indebtedness, or if the Partnership experiences specific kinds of changes in control, it must offer to repurchase notes at a specified price. MarkWest Energy Partners, LP is a holding entity and owns no operating assets and has no significant operations independent of its subsidiaries. Each of the Partnership’s existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and severally and fully and unconditionally. The notes are senior unsecured obligations equal in right of payment with all of the Partnership’s existing and future senior debt. These notes are senior in right of payment to all of the Partnership’s future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership’s obligations in respect of its Partnership Credit Facility. The proceeds from these notes were used to pay down the Partnership’s outstanding debt under its credit facility.

The indenture governing the senior notes limits the activity of the Partnership and its restricted subsidiaries. The provisions of such indenture places limits, on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in

transactions with the Partnership’s affiliates; sell assets, including equity interest in the Partnership’s subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.

The Partnership agreed to file an exchange offer registration statement, or under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2004 senior notes. On February 22, 2005, the Partnership filed the exchange offer registration statement relating to the 2004 senior notes. The Partnership is offering to exchange up to $225.0 million aggregate principal amount of new 6.875% senior notes due 2014 that have been registered under the Securities Act for an equal principal amount of the 2004 senior notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (March 31, 2005) and as a consequence is incurring an interest rate penalty of 0.5% until such time as the exchange offer is completed.

The indenture governing our outstanding senior notes contains restrictions on our ability to make cash distributions. Under the indenture, we are restricted from making Restricted Payments if at the time of making the Restricted Payment, a default or an event of default has occurred and is continuing. The Partnership’s failure to file this Annual Report on Form 10-K for year ended December 31, 2004 and its Quarterly Report on Form 10-Q for the first quarter of 2005 within the time periods specified in the Securities and Exchange Commission’s rules and regulations constituted a default under the indenture, and the failure to file the Form 10-K within thirty days after the April 8, 2005 notice from the indenture trustee constituted an event of default under the indenture. On May 16, 2005, the Partnership paid a cash distribution to unitholders for the first quarter of 2005. This cash distribution, made while the event of default for failure to file its Form 10-K had occurred and was continuing, constituted a default under the indenture, and this default matured into an event of default thirty days after such Restricted Payment was made, or June 15, 2005. Both of these events of default are cured upon the filing of this Form 10-K and the Quarterly Report on Form 10-Q for the first quarter of 2005 prior to any declaration of acceleration of the senior notes by the trustee as a result of such events of default.

Long-term debt consisted of:

	December 31,
	2004		2003
	(in thousands)

6.875% Senior Notes due November 1, 2014	$	225,000	$	—
Revolving credit facility due November 2006	—		126,200
	225,000		126,200
Less current portion	—		—
	$	225,000	$	126,200

9. Significant Customers and Concentration of Credit Risk

For the years ended December 31, 2004, 2003 and 2002, sales to MarkWest Hydrocarbon accounted for 20%, 42% and 37% of total revenues, respectively. As of December 31, 2004 and 2003, the Partnership had $5.8 million and $2.4 million, respectively, of accounts receivables from MarkWest Hydrocarbon. One other customer accounted for 20% of revenue for each of the years ended December 31, 2004 and 2003.

Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade accounts receivable. The Partnership’s 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 the Partnership’s credit exposure. Outside of MarkWest Hydrocarbon, the Partnership’s 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 the Partnership’s credit exposure. As of December 31, 2004 and 2003, the

unaffiliated gross accounts receivable balance was $42.1 million and $11.2 million, respectively, before allowance for doubtful accounts of $0.2 million and $0.1 million, respectively. At December 31, 2004, one customer accounted for 26% of accounts receivable from third parties.

10. Derivative Financial Instruments

Commodity Price

The Partnership’s primary risk management objective is to reduce volatility in its cash flows as a result of changes in commodity prices. A committee, which includes members of senior management of the general partner of the Partnership, oversees all of the Partnership’s hedging activity.

The Partnership may utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps and options available in the over-the-counter (“OTC”) market. The Partnership may also enter into futures contracts traded on the New York Mercantile Exchange (“NYMEX”). Swaps and futures contracts allow us to protect the Partnership’s margins because corresponding losses or gains on the financial instruments are generally offset by gains or losses in the physical market.

The Partnership enters into OTC swaps with financial institutions and other energy company counterparties. The Partnership conducts a standard credit review on counterparties and has agreements containing collateral requirements where deemed necessary. The Partnership uses standardized swap agreements that allow for offset of positive and negative exposures. The Partnership is subject to margin deposit requirements under OTC agreements (with non-bank counterparties) and NYMEX positions.

The Partnership has hedged its natural gas price risk in Texas (part of the Pinnacle acquisition) by entering into fixed-for-floating price swaps. As of December 31, 2004, the Partnership has hedged the Partnership’s Texas natural gas price risk with swaps that settle monthly through December 31, 2005 as follows:

MMBtu	182,500
$/MMBtu	$	4.26

At December 31, 2004 and 2003, the Partnership recorded a liability of $0.4 million and $0.5 million, respectively, for the fair value of these swaps. The gains and losses included in accumulated other comprehensive loss in the accompanying consolidated balance sheets are reclassified into earnings as the hedged transaction takes place. The accumulated other comprehensive loss balance of $0.3 million represents unrecognized net losses on derivative instruments accounted for as hedges as of December 31, 2004 and is expected to be reclassified into earnings during the next twelve months. During the year ended December 31, 2004 and 2003, the Partnership reclassified $0.7 million and $0.7 million, respectively, of accumulated other comprehensive loss into earnings as a result of hedging transactions that settled during the period. This amount includes the accumulated other comprehensive loss balance of $0.2 million and $0.7 million representing unrecognized net losses on derivative instruments as of December 31, 2003 and December 31, 2002, respectively.

For the year ended December 31, 2004, a loss of $0.3 million included in the accumulated other comprehensive loss were reclassified into earnings as a result of the discontinuance of an interest rate hedge. For each of the years ended December 31, 2003 and 2002, no gains or losses included in the accumulated other comprehensive loss were reclassified into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period.

The Partnership recognized a loss of $0.1 million during each of 2004 and 2003 and a gain of $0.1 million during 2002 relating to the ineffective portion of hedges or non-qualifying hedges. All of these amounts are reflected as adjustments to revenue in the accompanying consolidated statements of income.

Interest Rate

Although the Partnership had no debt outstanding with a floating interest rate at December 31, 2004, the Partnership would be exposed to changes in interest rates in the future if it drew on its Credit Facility. The Partnership may make use of interest rate swap agreements in the future should it borrow from its Credit Facility, to adjust the ratio of fixed and floating rates in its debt portfolio.

11. Income Taxes

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

	2002
Current taxes due from parent:
Federal	$	(1,252	)
State	(283		)
Total current due from parent	(1,535		)
Deferred:
Federal	1,406
State	190
Change in tax status	(17,236		)
Total deferred	(15,640		)
Total income tax benefit	$	(17,175	)

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 is summarized as follows (in thousands):

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

12. Long-Term Incentive Compensation Plans

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

The Partnership’s general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of the 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 the general partner’s board of directors administers the plan.

The 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. The 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 are 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 vest over a stated period. Prior to September 2004, the vesting period was 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. As of September 1, 2004, the vesting period for subsequent grants was changed to three years, with 33% of the grant vesting at the end of each of the first, second and third years. In the future, the Compensation Committee may 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 also determines the period over which restricted units granted to employees and directors will vest. The restricted units will vest upon a change of control of the Partnership, the general partner of the Partnership or MarkWest Hydrocarbon.

If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s unvested restricted units are 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 the general partner in the open market, common units already owned by the general partner, common units acquired by the general partner directly from us or any other person or any combination of the foregoing. The general partner will be entitled to reimbursement from us for the cost incurred in acquiring common units. If the Partnership issues new common units upon vesting of the restricted units, the total number of common units outstanding will increase.

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

	2004			2003
	(in thousands, except unit data)

Balance, beginning of period	34,496			50,230
Granted	27,900			11,756
Vested	(27,453		)	(23,758		)
Forfeited	(5,443		)	(3,732		)
Balance, end of period	29,500			34,496

Fair value, end of year	$	1,434		$	1,383

Compensation expense for the year	$	1,065		$	1,398

During the year ended December 31, 2004, 27,453 restricted unit grants vested. Of the total number of restricted units vested, 155 restricted units, at the Partnership’s option, were redeemed for cash and 27,298 common units were issued for vested restricted units. The Partnership recorded compensation expense of $1.1 million for the year ended December 31, 2004, of which $0.5 million related the accelerated vesting of restricted units.

In October 2003, the board of directors of the general partner approved the accelerated vesting of restricted unit grants based upon the achievement of cash distribution goals. As a result of achieving those distribution goals, 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 fair market value of the common units issued for the vested restricted units at the date of the accelerated vesting less the amount of compensation cost previously recognized.

Unit Options. The Long-Term Incentive Plan currently permits the granting of options covering common units. The Compensation Committee may 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. Unit options granted are exercisable over a period determined by the Compensation Committee. In addition, the unit

options are exercisable upon a change in control of us, the general partner, Markwest Hydrocarbon or upon the achievement of specified financial objectives.

Upon exercise of a unit option, the 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 the general partner, or any combination of the foregoing. The general partner will be entitled to reimbursement by us for the difference between the cost incurred by the general partner in acquiring these common units and the proceeds received by the general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If the Partnership issues new common units upon exercise of the unit options, the general partner will pay us the proceeds it received from the optionee upon exercise of the unit option.

As of December 31, 2004, the Partnership had not granted common unit options to employees or directors of the general partner, or employees of its affiliates or members of senior management.

MarkWest Hydrocarbon Participation Plan

MarkWest Hydrocarbon also has a Participation Plan for certain employees and directors of MarkWest Hydrocarbon. Under the Participation Plan, MarkWest Hydrocarbon sells subordinated partnership units of the Partnership and interest in the Partnership’s general partner to certain employees and directors of MarkWest Hydrocarbon under a purchase and sale agreement. The interest in the Partnership’s general partner are sold with certain put and call provisions that allow the individual to require MarkWest Hydrocarbon to buy back or requires the individual to sell back their interest in the general partner to MarkWest Hydrocarbon. Specifically, the employees and directors can exercise their put if (1) MarkWest Hydrocarbon or the Partnership’s general partner undergoes a change of control; (2) additional membership interests are issued and if the issuance of additional membership interests, on a pro forma basis, decreases the distributions to all the then existing members; (3) any amendment, alteration or repeal of the provisions of the general partner agreement is undertaken which materially and adversely affects the then existing rights, duties, obligations or restrictions of the employees and directors; or (4) the employee or director (i) becomes totally disabled while a director, officer or employee of the general partner, of MarkWest Hydrocarbon or of any of their affiliates, or (ii) dies, or (iii) retires as a director, officer or employee of the general partner, of MarkWest Hydrocarbon or of any of their affiliates after reaching the age of 60 years. The employee or his estate has 120 days after the put event to exercise the put under (4) and 30 days after notice to exercise under (1) through (3). MarkWest Hydrocarbon can exercise their call option if the employee or director ceases to be a director or employee of MarkWest Hydrocarbon or any of its affiliates or if there is a change of control. MarkWest Hydrocarbon has 12 months following the termination date to exercise its call option. As the formula used to determine the sale and buy-back price is not based on fair value, coupled with the attributes of the put and call provisions, these transactions are considered compensatory arrangements, similar to a stock appreciation right. The subordinated partnership units of the Partnership are also sold to the employees and directors at a formula that is not based on fair value. The subordinated units are sold without any restrictions on transfer. However, the Partnership has established an implied repurchase obligation through its pattern of buying back the subordinated units each time a employee or director has left MarkWest Hydrocarbon. The employees’ and director’s subordinated units convert into common units on June 30, 2005. Since the employees and directors are 100% vested on the date they purchase the subordinated units or general partner interests, compensation expense for the subordinated units is measured as the difference in the market value of the subordinated partnership units and the amount paid by those individuals. Compensation expense related to the general partner interest is calculated as the difference in the formula value and the amount paid by those individuals. The formula value is the amount MarkWest Hydrocarbon would have to pay the employees and directors to repurchase the general partner interests and is based on the current market value of the Partnership’s common units and the current quarterly distributions paid. The increases or decreases in the market value of the subordinated units and the formula value of the general partner interests between the date they are acquired and the end of each reporting period result in a change in the measure of compensation, which is reflected currently in operations. Total subordinated units sold to the employees and directors in 2004, 2003 and 2002 were 1,500, 12,500 and 24,864, respectively. MarkWest Hydrocarbon reacquired 2,867, 867 and 4,626 subordinated units in 2004, 2003 and 2002, respectively. Total interests in the Partnership’s general partner sold to the directors and employees in 2004, 2003 and 2002, were 0.7%, 3.6% and 8.6%, respectively. MarkWest Hydrocarbon reacquired 0.7%, 0.3% and 1.6% of the general partner interest in 2004, 2003 and 2002, respectively.

Under Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses And Related Disclosure In Financial Statements of Subsidiaries, Divisions Or Lesser Business Components of Another Entity compensation expense related to services provided by MarkWest Hydrocarbon’s directors and employees recognized under APB 25 should be allocated to the Partnership. The allocation is based on the percent of time that each employee devotes to the Partnership. Compensation attributable to interests that were sold to individuals who serve on both the Partnership’s board of directors and on the board of directors of MarkWest Hydrocarbon is allocated equally. The Partnership recorded compensation expense under the Participation Plan of $2.3 million, $0.9 million and $0.1 million for the year ended December 31, 2004, 2003 and 2002, respectively. The charge is a non-cash item that did not affect management’s determination of the Partnership’s distributable cash flow for any period, and did not affect net income attributed to the limited partners. Under the Partnership Agreement, the general partner is deemed to have made a capital contribution equal to the compensation expense recorded under this plan, with the compensation expense allocated 100% to the general partner.

13. Commitments and Contingencies

Legal

The Partnership and several of its affiliates were recently served with several complaints for recovery of property and personal injury damages sustained as a result of a leak occurring November 8, 2004 in a NGL pipeline owned by a third party, and leased and operated by the Partnership’s subsidiary, MarkWest Energy Appalachia, LLC. The 4-inch pipeline transported NGLs from the Maytown gas processing plant to the Siloam fractionator. A subsequent ignition and fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The exact cause of the leak and resulting fire is unknown and is being investigated by the Partnership and the OPS. The Partnership has submitted claims for and is pursuing Business Interruption Insurance to cover the increased transportation costs incurred and the lost income.

While investigation into the incident continues, at this time the Partnership believes that it has adequate insurance coverage for property damage and personal injury liability resulting from the incident. The deductible for the insurance is $0.3 million, which the Partnership recorded during the year ended December 31, 2004 as a charge to income.

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

Lease Obligations

The Partnership has various non-cancelable operating lease agreements for equipment expiring at various times through fiscal 2015. Annual rent expense under these operating leases was $3.3 million, $1.1 million and $0.6 million for the years ended December 31, 2004, 2003, and 2002, respectively. The minimum future lease payments under these operating leases as of December 31, 2004, are as follows (in thousands):

2005	$	3,096
2006	2,235
2007	958
2008	371
2009	277
2010 and thereafter	446
Total	$	7,383

The Partnership also has commitments to purchase equipment of $6.1 million at December 31, 2004.

14. Partners’ Capital

As of December 31, 2004, partners’ capital consists of 7,641,947 common limited partner units, representing a 70% partnership interest, 3,000,000 subordinated limited partner units, representing a 28% partnership interest, and a 2% general partner interest. MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 25% interest in the Partnership consisting of 2,469,496 subordinated limited partner units and a 2% general partner interest.

The Partnership has the ability to issue an unlimited number of units to fund immediately accretive acquisitions. Under the provisions of the Partnership Agreement an immediately accretive acquisition is one that in the general partner’s good faith determination would have, if acquired by the Partnership as of the date that is one year prior to the first day of the quarter in which such acquisition is consummated, resulted in an increase to the amount of operating surplus generated by the Partnership on a per-unit basis (for all outstanding units) with respect to each of the four most recently completed quarters (on a pro forma basis) as compared to the actual amount of operating surplus generated by the Partnership on a per-unit basis (for all outstanding units), excluding operating surplus attributable to the acquisition with respect to each of such four most recently completed quarters. During 2003 and 2004, the Partnership consummated six acquisitions aggregating approximately $354.4 million that were considered to be immediately accretive, certain of which were consequently partially funded by equity offerings. For acquisitions that are not immediately accretive, the Partnership has the ability to issue up to 1,207,500 common units without unitholder approval.

The Partnership Agreement contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts. Included in the Partnership Agreement is a provision that calls for compensation expense under the Participation Plan allocated to the Partnership by MarkWest Hydrocarbon to be allocated 100% to the general partner (See Note 12).

Distributions of Available Cash

The Partnership distributes 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 the Partnership’s business; (ii) comply with applicable law, any 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.

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 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. The earliest possible date by which some of the subordinated units may be converted into common units is June 30, 2005. A portion of the subordinated units are convertable into common units at an earlier date on a one-for-one basis based upon the achievement of certain financial goals (defined in the Partnership Agreement). As a result of achieving those goals in May 2005, 600,000 subordinated units will convert into common units on June 30, 2005. An additional 600,000 subordinated units will also convert into common units on September 30, 2005. When the subordination period ends, any 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 , the quarterly distributions of available cash will be made in the following manner:

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

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

• Third, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder 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

The Partnership 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 the general partner until the Partnership distributes for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter.

• 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, as described below, have been achieved. The 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:

• The Partnership has distributed available cash to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

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

then, the Partnership will distribute any additional available cash for that quarter among the unitholders and the general partner in the manner described in the following paragraph.

The general partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter in which distributions from available cash exceed specified target levels shown below:

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

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. The Partnership is presently distributing at a rate in excess of $0.75 per unit.

The quarterly cash distributions applicable to 2002 through 2004 were as follows:

Quarter Ended	Record Date	Payment Date	Amount Per Unit

December 31, 2004	February 2, 2005	February 11, 2005	$	0.78
September 30, 2004	November 3, 2004	November 12, 2004	$	0.76
June 30, 2004	July 30, 2004	August 13, 2004	$	0.74
March 31, 2004	April 30, 2004	May 14, 2004	$	0.69

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

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

Secondary Offering – January 12, 2004

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 were retained by them. In connection with the over-allotment provisions of the underwriting agreement, the Partnership issued an additional 72,500 common units for gross proceeds of $2.9 million. Aggregate gross proceeds of $46.8 million were reduced by underwriters’ fees of $2.5 million and professional fees and other offering costs of $1.3 million, resulting in net proceeds of $43.0 million. The net proceeds of $43.0 million and the $0.9 million contributed by the general partner to maintain its 2% interest resulted in total net proceeds associated with the offering of $43.9 million.

Secondary Offering – September 21, 2004

On September 21, 2004, the Partnership priced its offering of 2,157,395 common units at $43.41 per unit. Of the 2,157,395 common units, 2,000,000 were sold by the Partnership for gross proceeds of $86.8 million. The remaining 157,395 were sold by certain selling unitholders, proceeds of which have been retained by them. In connection with the over-allotment provisions of the underwriting agreement, the Partnership issued an additional 323,609 common units for gross proceeds of $14.1 million. Aggregate gross proceeds of $100.9 million were reduced by underwriters’ fees of $4.8 million and professional fees and other offering costs of $0.4 million, resulting in net proceeds of $95.7 million. The net proceeds of $95.7 million and the $2.1 million contributed by the general partner to maintain its 2% interest resulted in total net proceeds associated with the offering of $97.8 million.

Private Placement – June 27 and July 10, 2003

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, for proceeds of approximately $7.9 million. The second installment of 74,969 units was completed on July 10, 2003, for proceeds of approximately $1.9 million. Transaction costs for both installments were less than $0.1 million. The Partnership’s general partner made its contribution to maintain its 2% interest in July 2003 after the second installment was completed.

Private Placement – July 30, 2004

The Partnership sold 1,304,438 common units in a private placement to certain accredited investors for $34.50 per common unit that resulted in gross proceeds of $45.0 million. The aggregate gross proceeds of $45.0 million were reduced by offering costs of $0.9 million resulting in net proceeds of $44.1 million. The net proceeds of $44.1 million and the $0.9 million contributed by the general partner to maintain its 2% interest resulted in total net proceeds associated with the private placement of $45.0 million.

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 benefit plan. Costs related to this plan allocated to the Partnership were $0.1 million, $0.2 million and $0.1 million for the years ended December 31, 2004, 2003 and 2002, 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 the Partnership manages its business, including the allocation of capital and evaluation of business segment performance, the Partnership reports its operations in the following five geographical segments: (1) East Texas, through MarkWest Energy East Texas Gas Company, L.P. and MarkWest Pipeline Company, L.P. (gathering and processing assets) (2) Oklahoma, through MarkWest Western Oklahoma Gas Company, L.L.C. (Foss Lake gathering system and Arapaho processing plant) (3) Other Southwest, through MarkWest Power Tex L.P. (Powertex pipeline), MarkWest Pinnacle L.P. (Pinnacle gathering assets), MarkWest PNG Utility L.P. (Lake Whitney lateral), MarkWest Texas PNG Utility L.P. (Rio Nogales lateral), MarkWest Blackhawk L.P. (Borger lateral) and MarkWest New Mexico L.P. (Hobbs lateral) (4) Appalachia, through MarkWest Energy Appalachia, L.L.C. (Kenova, Boldman, Maytown, Cobb and Kermit processing plants, NGL pipelines, fractionation facility and storage facilities) (5) 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).

The accounting policies the Partnership applies in the preparation of business segment information is 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 before general and administrative expenses. As a result of the Partnership’s recent acquisitions, segment information for the years ended December 31, 2003 and 2002 has been restated to conform to the current period presentation.

Revenues from MarkWest Hydrocarbon are reflected as revenue from Affiliates.

	East Texas		Oklahoma		Other Southwest		Appalachia		Michigan			Total
Year Ended December 31, 2004:
Revenues:
Unaffiliated parties	$	21,932	$	133,636	$	69,464	$	1,632	$	15,624		$	242,288
Affiliates	—		—		—		59,026		—			59,026
Total Revenues	21,932		133,636		69,464		60,658		15,624			301,314
Purchased product costs	3,669		118,325		55,519		30,031		3,990			211,534
Facility expenses	3,229		3,659		3,694		13,444		5,885			29,911
Depreciation	1,489		2,059		3,099		4,329		4,580			15,556
Amortization	3,446		—		194		—		—			3,640
Accretion	13		—		—		—		—			13
Impairment	—		—		—		130		—			130
Operating income before selling, general and administrative expenses	$	10,086	$	9,593	$	6,958	$	12,724	$	1,169		$	40,530
Capital expenditures	$	19,343	$	2,917	$	3,899	$	2,856	$	1,452		$	30,467
Total segment assets	298,451		64,433		59,071		51,088		56,379			529,422

Year Ended December 31, 2003 (as restated):
Revenues:
Unaffiliated parties	$	—	$	7,855	$	46,669	$	1,278	$	11,778		$	67,580
Affiliates	—		—		—		49,850		—			49,850
Total Revenues	—		7,855		46,669		51,128		11,778			117,430
Purchased product costs	—		7,010		37,827		22,387		3,608			70,832
Facility expenses	—		298		2,914		12,316		4,935			20,463
Depreciation	—		158		2,126		2,870		2,394			7,548
Impairment	—		—		—		1,148		—			1,148
Operating income before selling, general and administrative expenses	$	—	$	389	$	3,802	$	12,407	$	841		$	17,439
Capital expenditures	$	—	$	—	$	1,085	$	1,799	$	60		$	2,944
Total segment assets	—		43,991		61,690		49,168		58,022			212,871

Year Ended December 31, 2002 (as restated):
Revenues:
Unaffiliated parties	$	—	$	—	$	—	$	35,161	$	8,992		$	44,153
Affiliates	—		—		—		26,093		—			26,093
Total Revenues	—		—		—		61,254		8,992			70,246
Purchased product costs	—		—		—		36,214		2,692			38,906
Facility expenses	—		—		—		9,701		5,400			15,101
Depreciation	—		—		—		2,647		2,333			4,980
Operating income before selling, general and administrative expenses	$	—	$	—	$	—	$	12,692	$	(1,433	)	$	11,259
Capital expenditures	$	—	$	—	$	—	$	2,110	$	35		$	2,145
Total segment assets	—		—		—		50,131		37,578			87,709

The following is a reconciliation of operating income before selling, general and administrative expenses to net income:

	Year Ended December 31,
	2004			2003			2002
				(as restated)			(as restated)
Total operating income before selling, general and administrative expenses	$	40,530		$	17,439		$	11,259
Selling, general and administrative expenses	16,133			8,598			5,411

Income from Operations	24,397			8,841			5,848

Interest income	87			14			5
Interest expense	(9,236		)	(3,087		)	(1,128		)
Amortization of deferred financing costs	(5,236		)	(984		)	(291		)
Miscellaneous income (expense)	(50		)	(25		)	52
Benefit for income taxes	—			—			17,175

Net income	$	9,962		$	4,759		$	21,661

17. Quarterly Results of Operations (Unaudited)

The following summarizes the Partnership’s quarterly results of operations, as restated:

	Three Months Ended
	March 31		June 30		September 30		December 31
	(in thousands, except per unit amounts)
2004
Revenue	$	63,825	$	65,659	$	77,842	$	93,988
Income from operations	$	3,605	$	4,502	$	7,686	$	8,604
Net income	$	2,161	$	3,262	$	715	$	3,824	(1)
Limited partner’s share of net income	$	2,162	$	3,027	$	802	$	4,694
Net income (loss) per limited partner unit:
Basic	$	0.32	$	0.43	$	0.10	$	0.46
Diluted	$	0.32	$	0.43	$	0.10	$	0.46

	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	$	38,689
Income from operations	$	2,327	$	2,241	$	3,495	$	778
Net income (loss)	$	1,586	$	1,271	$	2,665	$	(763	)(2)
Limited partner’s share of net income (loss)	$	1,593	$	1,478	$	2,681	$	(339	)
Net income (loss) per limited partner unit:
Basic	$	0.29	$	0.27	$	0.46	$	(0.07	)
Diluted	$	0.29	$	0.27	$	0.46	$	(0.07	)

(1) Included in the net income for the fourth quarter ended December 31, 2004 is an impairment charge of $0.1 million related to plant processing equipment taken out of service. See Note 5.

(2) Included in the net loss for the fourth quarter ended December 31, 2003, is an impairment charge of $1.1 million associated with the Cobb Processing Plant. See Note 4.

18. Valuation and Qualifying Accounts

	Balance at beginning of period		Charged to costs and expenses		Deductions		Balance at end of period
	(in thousands)

Year ended December 31, 2004:
Allowance for doubtful accounts	$	80	$	211	$	80	$	211
Year ended December 31, 2003:
Allowance for doubtful accounts	$	—	$	80	$	—	$	80
Year ended December 31, 2002:
Allowance for doubtful accounts	$	—	$	—	$	—	$	—

19. Restatement of Consolidated Financial Statement

The Partnership has determined that, in certain cases, it did not comply with generally accepted accounting principles in the Partnership’s 2002 and 2003 consolidated financial statements and, accordingly, it has restated its 2002 and 2003 annual financial statements. The Partnership has also filed Form 10-Q/As for the first three quarters of 2004 to restate its quarterly financial information for 2003 and 2004.

The restatements primarily result from an allocation of compensation expense from MarkWest Hydrocarbon attributed to its sale of a portion of its subordinated Partnership units and interests in the Partnership’s general partner to certain directors and employees from 2002 through 2004. MarkWest Hydrocarbon had historically recorded the sale of the subordinated Partnership units and interests in the Partnership’s general partner to certain of MarkWest Hydrocarbon’s employees and directors as a sale of an asset. These arrangements are referred to as the Participation Plan. However, MarkWest Hydrocarbon determined that these transactions should be accounted for as compensatory arrangements, pursuant to the guidance in APB 25, Accounting for Stock Issued to Employees and EITF No. 95-16, Accounting for Stock Compensation Arrangements with Employer Loan Features under APB Opinion No. 25. This guidance requires MarkWest Hydrocarbon to record compensation expense based on the market value of the subordinated Partnership units and the formula value of the general partner interests held by the employees and directors at the end of each reporting period. In the process of determining the ultimate accounting treatment for these transactions, a conclusion was reached by the Partnership that a portion of compensation expense related to services provided by MarkWest Hydrocarbon’s employees and directors recognized under APB 25 should be allocated to the Partnership pursuant to Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses And Related Disclosure In Financial Statements of Subsidiaries, Divisions Or Lesser Business Components of Another Entity, based on the amount of time each employee devotes to the Partnership. Compensation attributable to interests that were sold to individuals who serve on both the Partnership’s board of directors and on the board of directors of MarkWest Hydrocarbon is allocated equally. The restatement increased selling, general and administrative expenses by $0.9 million and $0.1 million for the years ended December 31, 2003 and 2002, respectively. The charge is a non-cash item that did not affect management’s determination of the Partnership’s distributable cash flow for any period, and did not affect net income attributed to the limited partners. Under the Partnership Agreement, the general partner is deemed to have made a capital contribution equal to the compensation expense recorded under the Participation Plan and the compensation expense is allocated 100% to the general partner. Although there is no impact on the total consolidated balance sheet, certain components of Partner’s capital were affected.

The Partnership has also restated revenue for 2003 by $0.1 million to record natural gas inventory at cost. Previously, the inventory was incorrectly identified as a pipeline imbalance and was recorded at fair value. The Partnership has reclassified intangible and other assets to a separate line item on the consolidated income statement. All amounts in the accompanying financial statements have been adjusted for this restatement. The restatement had no impact on total cash flows from operating activities, investing activities or financing activities.

Balance Sheet Amounts:

	December 31, 2003
	As Previously Reported		Adjustment			As Restated
Receivables	$	11,942	$	(840	)	$	11,102
Inventories	353		733			1,086
Total current assets	23,688		(107		)	23,581

Intangible and other assets, net	—		84			84
Deferred financing costs, net	3,831		(84		)	3,747
Total assets	$	212,978	$	(107	)	$	212,871

Capital:
Partners’ capital	65,549		(107		)	65,442
Total liabilities and capital	$	212,978	$	(107	)	$	212,871

Income Statement Amounts:

	Year Ended December 31, 2003
	As Previously Reported		Adjustments			As Restated
Revenues:
Sales to unaffiliated parties	$	67,687	$	(107	)	$	67,580
Total revenues	117,537		(107		)	117,430

Operating expenses:
Selling, general and administrative expenses	7,686		912			8,598
Total operating expenses	107,677		912			108,589

Income from operations	9,860		(1,019		)	8,841

Net income	$	5,778	$	(1,019	)	$	4,759

Interest in net income:
General partner	$	260	$	(914	)	$	(654	)
Limited partners	$	5,518	$	(105	)	$	5,413

Net income (loss) per limited partner unit:
Basic	$	0.96	$	(0.01	)	$	0.95
Diluted	$	0.96	$	(0.02	)	$	0.94

	Year Ended December 31, 2002
	As Previously Reported		Adjustment			As Restated

Operating expenses:
Selling, general and administrative expenses	$	5,283	$	128		$	5,411
Total operating expenses	64,270		128			64,398

Income from operations	5,976		(128		)	5,848

Income before income taxes	4,614		(128		)	4,486

Net income	$	21,789	$	(128	)	$	21,661

Interest in net income:
General partner	$	89	$	(128	)	$	(39	)
Limited partners	$	21,700	$	—		$	21,700

Net income per limited partner unit:
Basic	$	4.86	$	0.00		$	4.86
Diluted	$	4.83	$	0.00		$	4.83

Cash Flow Amounts:

	Year Ended December 31, 2003
	As Previously Reported			Adjustment			As Restated
Cash flows from operating activities:
Net income	$	5,778		$	(1,019	)	$	4,759
Participation Plan compensation expense	$	—		$	912		$	912
Increase in receivables	$	(1,576	)	$	840		$	(736	)
Increase in inventories	$	(223	)	$	(733	)	$	(956	)

	Year Ended December 31, 2002
	As Previously Reported		Adjustment			As Restated
Cash flows from operating activities:
Net income	$	21,789	$	(128	)	$	21,661
Participation Plan compensation expense	$	—	$	128		$	128

Statement of Capital Amounts:

	Common Units			Subordinated Units			General Partner			Accumulated Other Comprehensive Income (Loss)			Total

Balance, December 31, 2003, as previously reported	$	51,043		$	13,369		$	1,137		$	(498	)	$	65,051
Restatement adjustment	—			—			912			—			912
Balance, December 31, 2003, as restated	$	51,043		$	13,369		$	2,049		$	(498	)	$	65,963

Net income for the year ended December 31, 2003, as previously reported	$	2,546		$	2,972		$	260		$	—		$	5,778
Restatement adjustments	(51		)	(54		)	(914		)	—			(1,019		)
Net income, as restated	$	2,495		$	2,918		$	(654	)	$	—		$	4,759

20. Subsequent Event

On March 31, 2005, the Partnership completed the acquisition of a 50% non-operating membership interest in Starfish Pipeline Company, LLC from an affiliate of Enterprise Products Partners L.P. for $41.7 million. Starfish is a joint venture with Enbridge Offshore Pipeline LLC, which the Partnership accounts for utilizing the equity method. Starfish owns the FERC regulated Stingray natural gas pipeline and the unregulated Triton natural gas gathering system and West Cameron dehydration facility, all located in the Gulf of Mexico and southwestern Louisiana.

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

On February 23, 2004, the Partnership dismissed PricewaterhouseCoopers LLP as its independent accountants effective upon the filing of the Partnership’s Form 10-K for fiscal year ended December 31, 2003. Our Form 10-K was filed on March 15, 2004. The Audit Committee of the Board of Directors participated in, recommended and approved the decision to change independent accountants.

The reports of PricewaterhouseCoopers LLP on the consolidated financial statements for the years ended December 31, 2003 and 2002 contain no adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principle.

In connection with its audits for the fiscal years ended December 31, 2003 and 2002 and through March 15, 2004, there have been no disagreements with PricewaterhouseCoopers LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of PricewaterhouseCoopers LLP would have caused them to make reference thereto in their reports on financial statements for such years.

During the two fiscal years ended December 31, 2003 and through March 15, 2004, there have been no “Reportable Events” (as defined in Regulation S-K, Item 304(a)(1)(v)); however, as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2003, PricewaterhouseCoopers LLC identified to the Partnership’s management and Audit Committee in connection with the audit for fiscal 2003 certain deficiencies in the Partnership’s internal controls that, when considered collectively, may be considered a material weakness.

On April 12, 2004, the Audit Committee of the Board of Directors, engaged KPMG LLP as our independent accountants for the fiscal year ending December 31, 2004. The general partner of the Partnership has not consulted with KPMG LLP during the fiscal years ended December 31, 2003 and 2002 or during any subsequent interim period prior to its appointment as auditor regarding the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Partnership’s consolidated financial statements, or any matter that was either the subject of a disagreement (as defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions) or reportable event (within the meaning of Item 304(a)(1)(v) of Regulation S-K).

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ITEM 9A. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our Chief Financial Officer (“CFO”), and our Chief Accounting Officer (“CAO”), of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) of the Securities and Exchange Act of 1934, as amended, or the “Exchange Act”). Disclosure controls and procedures are controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Based on this evaluation, our CEO, CFO, and CAO concluded that, as of December 31, 2004, as a result of the material weaknesses in our internal control over financial reporting discussed below, our disclosure controls and procedures were not effective. Due to the material weaknesses discussed below, in preparing our financial statements as of and for the year ended December 31, 2004, we performed additional analysis and other procedures to ensure that such financial statements fairly present in all material respects our financial condition, results of operations and cash flows in accordance with generally accepted accounting principles.

(b) Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We assessed the effectiveness of our internal control over financial reporting as of December 31, 2004. In making this assessment, we used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). During this process, management identified material weaknesses in our internal controls.

A material weakness, as defined under standards established by the Public Company Accounting Oversight Board’s (“PCAOB”) Auditing Standard No. 2, is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements would not be prevented or detected on a timely basis by management or employees in the normal course of performing their assigned functions.

The Partnership acquired MarkWest Energy East Texas Gas Company, L.P. and MarkWest Pipeline Company, L.P. (the “East Texas System”) during 2004, and due to the timing of the acquisitions, we excluded in accordance with SEC guidance from our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004, the East Texas System’s internal control over financial reporting associated with total assets of $261.4 million and total revenues of $21.9 million included in our consolidated financial statements.

Based on our assessment, management has concluded that, as of December 31, 2004, we did not maintain effective internal control over financial reporting due to the following material weaknesses:

Ineffective Control Environment - Our control environment did not sufficiently promote effective internal control over financial reporting throughout our management structure, and this material weakness was a

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contributing factor in the development of other material weaknesses described below. Principal contributing factors included the lack of adequate personnel with sufficient expertise to perform accounting functions necessary to ensure preparation of financial statements in accordance with generally accepted accounting principles, and a lack of adequate policies and procedures to enable the timely preparation of reliable financial statements, as described more fully below. These deficiencies were reported to us by our auditors in connection with their audit of our financial statements for the year ended December 31, 2003, however, they were not remediated by December 31, 2004.

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

• We did not have a sufficient number of personnel with adequate technical expertise to effectively carry out the Company’s policies and procedures related to the review of technical accounting matters.

• We did not maintain policies and procedures over the selection and application of appropriate accounting policies, or the assessment of the appropriate accounting treatment for non-routine transactions.

• We did not maintain policies and procedures that provide for timely and effective management review of information supporting our financial statements prior to their issuance.

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

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

• We did not employ personnel with sufficient expertise to perform accounting functions necessary to ensure preparation of financial information in accordance with generally accepted accounting principles.

• We did not maintain policies and procedures to ensure that account analyses and reconciliations of supporting account details to the general ledger were accurately prepared and reviewed timely, and that any reconciling items were investigated and resolved on a timely basis.

• We did not maintain policies and procedures to ensure that journal entries were accurately prepared and properly reviewed prior to being recorded in the general ledger.

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

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weaknesses also resulted in misstatements of revenues; purchased product costs; facility expenses; selling, general and administrative expenses; depreciation; amortization of intangible assets; accretion of asset retirement obligations; and interest expense. As a result, we restated our financial statements for the first three quarters of 2004. These misstatements, which were considered material in the aggregate, were corrected prior to issuance of our audited financial statements for the year 2004.

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

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears on page 110.

(c) Changes in Internal Controls over Financial Reporting.

During the quarter ended December 31, 2004, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

(d) Remediation of Internal Control Weaknesses

We have dedicated substantial resources to the assessment of our internal control over financial reporting processes and procedures. As a result of that assessment and under the direction of the Audit Committee and the Board of Directors, senior management directed that we dedicate additional resources to implement internal controls to reasonably assure accurate and timely financial reporting in the future.

Subsequent to December 31, 2004, we have initiated the following measures to strengthen our internal control processes:

Ineffective control environment:

• We are in the process of recruiting a Chief Accounting Officer with technical accounting skills relevant to our public company financial reporting needs.

• We are developing plans to formally implement an internal audit function in conjunction with our compliance function designed to assist in the future development and review of sound internal policies and procedures.

• We are conducting an assessment and review of our accounting general ledger systems to determine what changes could be made to improve our overall control environment.

Insufficient technical accounting expertise, inadequate policies and procedures and management review in the preparation of our financial statements:

• We are in the process of recruiting a Chief Accounting Officer with public company reporting technical expertise, and we intend to add at least one additional staff person with specific technical accounting and SEC reporting expertise to supplement our existing internal technical accounting resources.

• We have reaffirmed our corporate policy to capitalize interest on major construction projects. The financial reporting team in our corporate office has assumed the responsibility for calculating and

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recording capitalized interest relating to major construction projects.

• We plan to establish a relationship with an accounting consulting and advisory firm to provide additional technical accounting support and have begun the selection process.

Inadequate personnel, processes and controls at our Southwest Business Unit:

• We have formalized the monthly account reconciliation process for all balance sheet accounts. We have also implemented a formal review of these reconciliations by our Business Unit accounting management.

• We have instituted a quarterly corporate review of all account reconciliations by the corporate accounting staff and management.

• We plan to have our Southwest Business Unit accountants receive specific training on our accounting systems.

• We formalized a consistent procedure across all subsidiaries relating to revenue, purchased product costs and their associated balance sheet accounts to completely reverse the prior period accruals, and analyze and document the current period accruals.

• We initiated the process of consistently comparing each month’s accrual to the actual results in an effort to further refine the estimation process.

• We have systematized the data gathering function for the accounts payable invoices received after period end. This accrual is now reviewed monthly by corporate accounting staff.

• Our executive operations management is now requiring field personnel to expedite the invoice approval process.

Inadequately designed controls and procedures over property, plant and equipment:

• We have implemented additional procedures to provide for an additional review that verifies costs associated with activities relating to our facilities are properly accounted for as capital expenditures or maintenance expense. A weekly review meeting is now held by our Business Unit management to review the specifics of every open construction project. The fixed asset accountant and all operational managers are present.

Our Audit Committee has been and expects to remain actively involved in the remediation planning and implementation. The Partnership is fully committed to remediating the material weaknesses described above, and we believe that we are taking the steps that will properly address these issues during 2005. However, the remediation of the design of the deficient controls and the associated testing efforts are not complete, and further remediation may be required.

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Report of Independent Registered Public Accounting Firm

The Partners of MarkWest Energy Partners L.P.:

We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting (Item 9A(b)), that MarkWest Energy Partners, L.P. (the Partnership) did not maintain effective internal control over financial reporting as of December 31, 2004, because of the effect of the material weaknesses identified in management’s assessment, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). MarkWest Energy Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management’s assessment:

Ineffective Control Environment - The Partnership’s control environment did not sufficiently promote effective internal control over financial reporting throughout their management structure, and this material weakness was a contributing factor in the development of other material weaknesses described below. Principal contributing factors included the lack of adequate personnel with sufficient expertise to perform accounting functions necessary to ensure preparation of financial statements in accordance with generally accepted accounting principles, and a lack of adequate policies and procedures to enable the timely preparation of reliable financial statements, as described more fully above. These deficiencies were reported to the Partnership by their auditors in connection with the audit of the Partnership’s financial statements for the year ended December 31, 2003; however, they were not remediated by December 31, 2004.

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complex accounting matters. In addition, the Partnership did not maintain policies and procedures to ensure adequate management review of information supporting their financial statements. Specifically, the Partnership identified deficiencies in the following areas relating to the preparation of their financial statements:

• They did not have a sufficient number of personnel with adequate technical expertise to effectively carry out the Partnership’s policies and procedures related to the review of technical accounting matters.

• They did not maintain policies and procedures over the selection and application of appropriate accounting policies, or the assessment of the appropriate accounting treatment for non-routine transactions.

• They did not maintain policies and procedures that provide for timely and effective management review of information supporting its financial statements prior to their issuance.

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

Inadequate personnel, processes and controls at the Partnership’s Southwest Business Unit - The Partnership did not have adequate personnel, policies, and procedures at their Southwest Business Unit to enable timely preparation of reliable financial information for that business unit. Specifically, they identified the following internal control deficiencies at their Southwest Business Unit:

• They did not employ personnel with sufficient expertise to perform accounting functions necessary to ensure preparation of financial information in accordance with generally accepted accounting principles.

• They did not maintain policies and procedures to ensure that account analyses and reconciliations of supporting account details to the general ledger were accurately prepared and reviewed timely, and that any reconciling items were investigated and resolved on a timely basis.

• They did not maintain policies and procedures to ensure that journal entries were accurately prepared and properly reviewed prior to being recorded in the general ledger.

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

These material weaknesses in internal control over financial reporting resulted in misstatements of cash; receivables; other current assets; property, plant and equipment; accumulated deprecation; intangible assets; accounts payable; accrued liabilities; other liabilities; and partners’ capital. These material weaknesses also resulted in misstatements of revenues; purchased product costs; facility expenses; selling, general and administrative expenses; depreciation; amortization of intangible assets; accretion of asset retirement obligations; and interest expense. As a result, they restated their financial statements for the first three quarters of 2004.

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

In our opinion, management’s assessment that MarkWest Energy Partners, L.P. did not maintain effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, MarkWest Energy Partners, L.P. has not maintained

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effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

The Partnership acquired MarkWest Energy East Texas Gas Company, L.P. and MarkWest Pipeline Company, L.P. (the “East Texas System”) during 2004, and management excluded from its assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2004, the East Texas System’s internal control over financial reporting associated with total assets of $58.7 million and total revenues of $21.9 million included in the consolidated financial statements of MarkWest Energy Partners L.P. and subsidiaries as of and for the year ended December 31, 2004. Our audit of internal control over financial reporting of also excluded an evaluation of the internal control over financial reporting of the East Texas System.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of MarkWest Energy Partners, L.P., and its subsidiaries as of December 31, 2004, and the related consolidated statements of operations, comprehensive income, changes in capital and cash flows for the year ended December 31, 2004. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2004 consolidated financial statements, and this report does not affect our report dated June 17, 2005, which expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Denver, Colorado

June 17, 2005

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ITEM 9B. OTHER INFORMATION

None.

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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, although such duty is limited under our limited Partnership Agreement. 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.

Three 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 Keith E. Bailey, Charles K. Dempster and William P. Nicoletti.

Three members of the board of directors serve on the Audit Committee that reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls. 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 under the headings “Non-Competition, Non-Solicitation and Confidentiality Agreement and Severance Plan” and “Long-Term Incentive Plan”, which is included herein by reference. The members of the Compensation and Audit Committees for fiscal 2004 were Charles K. Dempster, William A. Kellstrom and William P. Nicoletti. For fiscal 2005, Keith E. Bailey replaced Mr. Kellstrom on both the Audit and Compensation Committees.

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.

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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	64	Chairman of the Board of Directors
Frank M. Semple	53	President, Chief Executive Officer and Director
Keith E. Bailey	62	Director
Charles K. Dempster	62	Director
Donald C. Heppermann	61	Director
William A. Kellstrom	63	Director
William P. Nicoletti	59	Director
C. Corwin Bromley	47	Vice President, General Counsel and Secretary
James G. Ivey	53	Senior Vice President and Chief Financial Officer
John C. Mollenkopf	43	Senior Vice President, Southwest Business Unit
Randy S. Nickerson	43	Senior Vice President, Corporate Development
Andrew L. Schroeder	46	Vice President, Finance and Treasurer
Ted S. Smith	54	Vice President and 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 in various capacities, lastly as Chief Operating Officer, with WilTel Communications, formerly Williams Communications Group, Inc. (“WCG”) from 1997 to 2003. 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. On April 22, 2002, WCG and one of its subsidiaries (“Debtors”) filed a petition for relief under the Bankruptcy Code with the United States Bankruptcy Court for the Southern District of New York. On September 30, 2002, the Bankruptcy Court entered an order confirming the Debtors’ plan of reorganization that became effective October 15, 2002.

Keith E. Bailey has served as a member of the board of directors of our general partner since January 2005. Mr. Bailey was formerly the Chairman, President and Chief Executive Officer of The Williams Companies, Inc. (“Williams”). Commencing in 1973, Mr. Bailey served in various capacities with Williams and its subsidiaries including President and Chairman of Williams Pipe Line, Chairman of Wiltel Communications, President of Williams Natural Gas, and Executive Vice President and Chief Financial Officer of Williams. Also, Mr. Bailey served on the Williams board of directors from 1988 until his retirement in 2002, including eight years as Chairman. Current positions on the boards of directors of public companies include Apco Argentina, Aegis and Peoples Energy. Mr. Bailey holds a bachelor’s degree in mechanical engineering from the Missouri School of Mines and Metallurgy.

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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. He held various management and executive positions with Enron Corporation and its predecessors 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 natural gas midstream and exploration subsidiaries of Nicor Inc. in Chicago. In 1993, he was appointed President of Aquila Energy Corporation, a wholly owned midstream, pipeline and energy-trading subsidiary of Utilicorp, Inc. Mr. Dempster retired in 2000 as Chairman and Chief Executive Officer 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.

Donald C. Heppermann has served on our general partner’s board of directors since its inception in May 2002 and serves as Chairman of the Finance Committee. Mr. Heppermann previously 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. 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 employed by Pinnacle West Capital Corporation, the holding company for Arizona Public Service Company, where he was Vice President of Finance. From 1965 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 MBA 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 Corporation, 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 formed in 1991. Previously he was a Managing Director and head of Energy Investment Banking for PaineWebber Incorporated and E.F Hutton & Company Inc. Mr. Nicoletti is a non-executive Chairman of the Board of Star Gas LLC, the general partner of Star Gas Partners, L.P. He is also a director of SPI Petroleum LLC and Russell-Stanley Holdings, Inc. Mr. Nicoletti is a graduate of Seton Hall University and received an MBA degree from Columbia University Graduate School of Business.

C. Corwin Bromley has served as Vice President, General Counsel and Secretary of our general partner and MarkWest Hydrocarbon since September 2004. Prior to that, Mr. Bromley served as Assistant General Counsel at RAG American Coal Holding, Inc. from 1999 through 2004, and as General-Managing Attorney at Cyprus Amax Minerals Company from 1989 to 1999. Prior to that, Mr. Bromley spent four years in private practice with the law firm Popham, Haik, Schnobrich and Kaufman. Preceding his legal career, Mr. Bromley was employed by CBI, Inc. as a structural/design engineer involved in several LNG and energy projects. Mr. Bromley received his J.D. from the University of Denver and his bachelor’s degree in civil engineering from the University of Wyoming.

James G. Ivey has served as Chief Financial Officer of both MarkWest Hydrocarbon and our general partner since June 2004. Prior to joining MarkWest, Mr. Ivey served as Treasurer of The Williams Companies from

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1999 to April 30, 2004 and as acting Chief Financial Officer from mid 2002 to mid 2003. Prior to joining Williams, Mr. Ivey held similar positions with Tenneco Gas and NORAM Energy. Prior to that, he held various engineering positions with Conoco and Fluor Corporation. He currently serves on the boards of directors for MACH Gen LLC, National Energy & Gas Transmission, Inc. and the Tulsa Boys Home. Mr. Ivey is a graduate of Texas A & M University with a B.S. in Building Construction, the University of Houston with a MBA, the Army Command and General Staff college and the Duke University Advanced Management Program. Mr. Ivey retired in early 2004 from the Army Reserve with the rank of colonel.

John C. Mollenkopf was appointed Senior Vice President, Southwest Business Unit, of our general partner and previously 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 March 2003. 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, Inc. in Tulsa, Oklahoma, having served most recently as Vice President and General Manager of the video services business for WilTel Communications, formerly WCG from 1997 to 2003. 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. On April 22, 2002, the Debtors filed a petition for relief under the Bankruptcy Code with the United States Bankruptcy Court for the Southern District of New York. On September 30, 2002, the Bankruptcy Court entered an order confirming the Debtors’ plan of reorganization that became effective October 15, 2002.

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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 and Mr. Bailey are financially sophisticated and qualify 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 Conduct and Ethics

We have adopted a Code of Conduct and Ethics which complies with SEC standards, applicable to the persons serving as our directors, officers (including without limitation, our CEO, CFO, CAO and Principal Financial Officer) 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. The Code of Conduct and Ethics is also posted on our website, www.markwest.com.

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 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.

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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, 2004, except for the following:

	No. of Late Reported Transactions	No. of Late Form 3 Filings	No. of Late Form 4 Filings
Mr. Fox	1	0	1
Mr. Semple	1	0	1
Mr. Ivey	2	1	1
Mr. Mollenkopf	2	0	2
Mr. Nickerson	1	0	1
Mr. Smith	2	0	2
Mr. Schroeder	1	0	1
Mr. Dempster	3	0	3
Mr. Heppermann	1	0	1
Mr. Nicoletti	2	0	2
Mr. Kellstrom	2	0	2

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 2004, 2003 and 2002 by each person who served as Chief Executive Officer of our general partner in 2004 and the four other highest paid officers, whose salary and bonus exceeded $100,000 for services rendered during 2004.

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.

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Summary Compensation Table

	Annual Compensation					Long-Term Compensation
Name and Principal Positions	Fiscal Year	Salary ($) (1)		Bonus ($) (2)		Restricted Unit Awards ($) (3)		LTIP Payouts ($) (4)		Other Compensation ($) (5)

Frank M. Semple	2004	$	280,385	$	47,250	$	108,750	$	20,500	$	52,838
President and Chief Executive Officer	2003	36,346		6,413		279,000		4,800		623
	2002	—		—		—		—		—

James G. Ivey (6)	2004	$	126,154	$	5,979	$	251,500	$	8,640	$	37,408
Chief Financial Officer	2003	—		—		—		—		—
	2002	—		—		—		—		—

Randy S. Nickerson	2004	$	181,155	$	30,625	$	108,750	$	5,363	$	13,686
Senior Vice President, Corporate Development	2003	164,743		23,515		26,875		10,675		13,193
	2002	154,943		2,601		110,000		6,150		12,395

John C. Mollenkopf	2004	$	180,865	$	30,625	$	65,250	$	6,703	$	13,426
Senior Vice President, Business Development	2003	144,354		20,684		59,475		11,985		12,331
	2002	129,322		2,171		110,000		6,150		10,346

David L. Young (7)	2004	$	161,538	$	25,521	$	77,000	$	4,380	$	—
Senior Vice President, Northeast Business Unit	2003	—		—		—		—		—
	2002	—		—		—		—		—

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

(2) Represents actual bonus paid in each respective fiscal year for services rendered on behalf of both the Partnership and MarkWest Hydrocarbon. Bonuses are paid 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. Semple, Ivey, Nickerson, Mollenkopf and Young had restricted phantom units of 7,073, 6,769, 2,980, 1,980, and 1,406, respectively at May 12, 2005. The restricted units vest over a period of three years, with 33% of the grant vesting at the end of each of the three years. The vesting may be accelerated upon achievement of certain goals.

(4) Represents distributions received for phantom units.

(5) Represents actual MarkWest Hydrocarbon contributions under MarkWest Hydrocarbon’s 401(k) Savings and Profit Sharing Plan. Included in Mr. Semple’s and Mr. Ivey’s other compensation are relocation payments of $34,453 and $37,408, respectively.

(6) Mr. Ivey became the Chief Financial Officer on May 25, 2004. Mr. Ivey is currently being paid an annual salary of $205,000.

(7) Mr. Young became the Senior Vice President of the Northeast Business Unit on February 2, 2004. Mr. Young is currently being paid an annual salary of $175,000.

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 MarkWest Hydrocarbon 1997 Severance Plan (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.

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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 may 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

On January 20, 2005, the Board of Directors of the general partner approved director compensation for 2005. Each independent director will receive an annual retainer of $18,000 and 500 restricted units per year. In addition, each independent director will receive compensation of $2,000 for either in-person or telephonic attendance at meetings of the board of directors or committees of the board of directors. Members of committees will receive $1,000 for each meeting, and the Chairs of the Audit Committee, Compensation Committee and Conflicts Committee will receive an additional $4,000, $2,000 and $2,000, respectively.

Previously, each independent director received an annual retainer of $12,000 and 500 restricted units per year. In addition, each independent director received 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 received compensation of $1,000 for each committee meeting. Additionally, members of the Audit and Conflict committees received an annual retainer of $3,000.

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Each independent director will continue to be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will also continue to be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. As previously disclosed, officers or employees of our general partner who also serve as directors will not receive additional compensation.

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 were reimbursed pursuant to the terms and conditions of the Services Agreement.

Compensation Philosophy

The executive compensation program is based on the following four objectives: (i) to link the interests of management with those of unitholders by encouraging ownership in the Partnership; (ii) to attract and retain superior executives by providing them with the opportunity to earn total compensation packages that are competitive with the industry; (iii) to reward individual results by recognizing performance through salary, annual cash incentives and long-term restricted unit based incentives; and (iv) to manage compensation based on the level of skill, knowledge, effort and responsibility needed to perform the job successfully.

The components of the compensation program for its executive officers include (i) base salary, (ii) performance-based cash bonuses, and (iii) incentive compensation in the form of restricted units.

Base Salary. The Committee annually reviews base salaries of executive officers, including the Named Executive Officers listed in the Summary Compensation Table. Industry compensation surveys are used to establish base salaries that are within the range of those persons holding comparably responsible positions at other similar-sized energy companies/partnerships, both regionally and nationally. The current compensation structure falls generally within the midpoint salary range of compensation structures adopted by the other companies in the salary surveys reviewed. Executive’s salary may be increased based on (i) the individual’s increased contribution over the preceding year; (ii) the individual’s increased responsibilities over the preceding year; and (iii) any increase in median competitive pay levels.

Annual Cash Bonuses. The Committee recommends the payment of bonuses from time-to-time to the employees, including its executive officers, to provide an incentive to these persons to be productive over the course of each fiscal year. These bonuses are awarded only if the Partnership achieves or exceeds certain performance goals. The performance goals include both financial and non-financial measures. The Committee establishes the manner in which the performance goals are calculated and may exclude the impact of certain specified events from the calculation. The size of the cash bonus to each executive officer is based on the individual executive’s performance during the preceding year as well as that level of combination of cash compensation and restricted units that would be required from a competitive point of view to retain the services of a valued executive officer.

Long-term Incentive Plan. The Committee believes that a key component to the compensation of its executive officers should be through the issuance of restricted units. Restricted units utilized for this purpose have been designed to provide an incentive to these employees by allowing them to directly participate in any increase in

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the long-term value of the Partnership. This incentive is intended to reward, motivate and retain the services of executive employees. The Partnership has historically rewarded its executive employees through the grant of restrictive units.

Our general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of our general partner. The long-term incentive plan consists of two components, restricted units and unit options. The plan currently permits the grant of awards covering an aggregate of 500,000 common units, 200,000 which may be awarded in the form of restricted units. At December 31, 2004, the Partnership had granted 29,500 restricted units that are subject to vesting periods established from time to time by the Committee.

The Compensation Committee employs no particular set of mechanical criteria in awarding restricted units. Rather, it evaluates a series of factors including: (i) the overall performance of the Partnership for the fiscal year in question; (ii) the performance of the individual in question; (iii) the anticipated contribution by the individual on an overall basis; (iv) the historical level of compensation of the individual; (v) the level of compensation of similarly situated executives in the Partnership’s industry; and (vi) that level of combination of cash compensation and restricted units that would be required from a competitive point of view to retain the services of a valued executive officer.

CEO Compensation

Effective November 2003, Mr. Semple became the Chief Executive Officer with an annual base salary of $270,000. Mr. Semple’s annual base salary is within the range of compensation structures of those persons holding comparable positions at similar sized partnerships/companies. In setting this amount, the Committee took into account the scope of Mr. Semple’s responsibility and the Board’s confidence in Mr. Semple’s skills and ability to implement the Partnership’s strategy and business model as evidenced by past performance. Mr. Semple took no part in discussions relating to his own compensation.

Compensation Committee of MarkWest Energy GP, L L.C.

Mr. Charles K. Dempster, Chairman

Mr. William A. Kellstrom

Mr. William P. Nicoletti

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PERFORMANCE GRAPH

Source: FactSet.

(a) Peer group companies include Crosstex Energy, L.P., Atlas Pipeline Partners, L.P and Buckeye Partners. 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.

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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, 2004, 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 Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference.

Equity Compensation Plan Information (1)

Plan category	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))
	(a)	(b)		(c)
Equity compensation plans approved by security holders	—	$	—	—
Equity compensation plans not approved by security holders	29,500	—		419,289

Total	29,500	$	—	419,289

(1) The amount in column (a) of this table reflects only restricted units granted but not vested as of December 31, 2004. 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.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units as of May 12, 2005, 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(1)	Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Units Beneficially Owned
MarkWest Energy GP, L.L.C.	—	—		—	—		—
MarkWest Hydrocarbon, Inc.(2)	—	—		2,469,496	82.3	%	23.2	%
John M. Fox(3)	32,000		*	2,489,122	83.0	%	23.7	%
Kayne Anderson Capital Advisors, L.P.	882,000	11.5	%	—	—		8.3	%
Tortoise Capital Advisors LLC(4)	847,710	11.1	%	—	—		8.0	%
Tortoise Energy Infrastructure Corporation	805,810	10.5	%	—	—		7.6	%
Tortoise MWEP, L.P.	—	—		500,000	16.7	%	4.7	%
Frank M. Semple	5,750		*	5,000		*		*
James G. Ivey	2,500		*	—	—			*
Randy S. Nickerson	6,875		*	4,626		*		*
John C. Mollenkopf	2,650		*	4,626		*		*
David L. Young	1,000		*	—	—			*
Keith E. Bailey	2,000		*	—	—			*
Donald C. Heppermann	7,500		*	4,000		*		*
William A. Kellstrom	3,750		*	—	—			*
William P. Nicoletti	3,250		*	—	—			*
Charles K. Dempster	1,250		*	—	—			*
All directors and executive officers as a group (11 persons)	68,525		*	2,507,374	83.6	%	24.2	%
Other (5)	1,500		*	3,000		*		*

* Less than 1%

(1) Beneficial ownership for the purposes of the foregoing table is defined by Rule 13 d-3 under the Securities Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof (“Voting Power”) or to dispose or direct the disposition thereof (“Investment Power”) or has the right to acquire either of those powers within sixty (60) days.

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

(3) Includes 4,626 subordinated units owned directly by Mr. Fox, 2,469,496 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, 2004, Mr. Fox beneficially owned approximately 43% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’s Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003 and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the subordinated units owned by MarkWest Hydrocarbon.

(4) Tortoise Capital Advisors LLC (“TCA”) acts as an investment advisor to Tortoise Energy Infrastructure Corporation (“TYG”), a closed-end investment company. TCA, by virtue of an Investment Advisory Agreement with TYG, has all investment and voting power over securities owned of record by TYG. However, despite its delegation of investment and voting power to TCA, TYG may be deemed to be the beneficial owner under Rule 13d-3 of the Securities and Exchange Act of 1940, of the securities it owns of record because it has the right to acquire investment and voting power through termination of the Investment Advisory Agreement. Thus, TCA and TYG have reported that they share voting power and dispositive power over the securities owned of record by TYG. TCA also acts as an investment advisor to certain managed accounts. Under contractual agreements with individual account holders, TCA, with respect to the securities held in the managed accounts, shares investment and voting power with certain account holders, and has no voting power but shares investment power with certain other account holders. TCA may be deemed the beneficial owner of the securities covered by this statement under Rule 13d-3 of the Act. None of the securities are owned of record by TCA, and TCA disclaims any beneficial interest in such shares.

(5) Held by three key officers of MarkWest Hydrocarbon and our general partner for common and subordinated units, respectively.

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The following table sets forth the beneficial ownership of our general partner as of May 12, 2005, held by MarkWest Hydrocarbon, the directors of our general partner, each named executive officer and by all directors and officers of our general partner as a group.

Name of Beneficial Owner	Percentage of Limited Liability Company Interests Owned
MarkWest Hydrocarbon, Inc.	89.7	%
John M. Fox (1)	91.3
Frank M. Semple	2.0
James G. Ivey	0.5
Randy S. Nickerson	1.6
John C. Mollenkopf	1.6
David L. Young	0.0
Keith E. Bailey	0.0
Donald C. Heppermann	1.0
William A. Kellstrom	0.0
William P. Nicoletti	0.0
Charles K. Dempster	0.0
All directors and executive officers as a group (8 persons)	98.0
Other (2)	2.0

(1) Includes a 1.6% ownership interest held directly by Mr. Fox and an 89.7% ownership interest held by MarkWest Hydrocarbon. As of December 31, 2004, Mr. Fox beneficially owned approximately 43% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’s Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003, and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the ownership interests owned by MarkWest Hydrocarbon.

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

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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 May 12, 2005, affiliates of MarkWest Hydrocarbon, in the aggregate, owned a 25% interest in the Partnership, consisting of 2,495,374 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.

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; and

• a Natural Gas Liquids Purchase Agreement;

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 the 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;

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• 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 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 a Third Party” 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 “MarkWest” name and mark.

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.

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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 third party producers; 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 third party producer’s in 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

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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, if 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 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.

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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;

• at our sole risk be 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. 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.

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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 a third party producer 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 number 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 Directors 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’ propane division is a significant customer of MarkWest Hydrocarbon and accounted for approximately 11% of its revenues for the year ended December 31, 2004. The propane division of Star Gas Partners, L.P. was purchased by another entity in December 2004 and, therefore, Star Gas Partners, L.P. will not be a related party for the year ending December 31, 2005.

Keith E. Bailey, who also serves as a member of our general partner’s board of directors, is a member of the board of directors of Aegis, an insurance company. Aegis provides insurance to MarkWest Hydrocarbon, Inc.

Related Transactions

In February 2004, MarkWest Hydrocarbon entered into a Separation and Release Agreement with Arthur J. Denney, Senior Vice President, pursuant to which MarkWest Hydrocarbon agreed to pay Mr. Denney his base salary through February 28, 2006, or approximately $0.4 million.

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In February 2004, MarkWest Hydrocarbon entered into a Separation and Release Agreement with Donald C. Hepperman, Chief Financial Officer, pursuant to which MarkWest Hydrocarbon agreed to pay Mr. Hepperman his base salary through August 31, 2004.

In March 2004, MarkWest Hydrocarbon entered into a Consulting Agreement with Donald C. Hepperman to advise MarkWest Hydrocarbon’s board of directors, chief executive officer, treasurer and controller on matters relating to banking, financing, mergers and acquisitions and general corporate strategy. Pursuant to the agreement, MarkWest Hydrocarbon agreed to pay Mr. Heppermann $9,000 a month for his consulting services for up to a period of two years (or $0.2 million), unless given notice by MarkWest Hydrocarbon.

In March 2004, MarkWest Hydrocarbon entered into a Separation and Release Agreement with John M. Fox, Chief Executive Officer, pursuant to which MarkWest Hydrocarbon agreed to pay Mr. Fox his base salary through December 31, 2004 or approximately $0.4 million.

On April 5, 2004, MarkWest Hydrocarbon entered into an agreement with a third party to buy Mr. Semple’s house as a part of his relocation to Denver, Colorado. Under the agreement, MarkWest Hydrocarbon agreed to pay the value of Mr. Semple’s equity in the house and associated operating costs of $298,244 to the third party until the house was subsequently sold to a buyer. Upon the sale, the third party agreed to refund the equity paid by MarkWest Hydrocarbon to the extent that the proceeds covered the established value minus certain costs incurred to sell the home. As of December 31, 2004, the house had not been sold.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND EXPENSES

For the year ended December 31, 2004 and 2003, KPMG LLP and PricewaterhouseCoopers LLP’s accounting fees and services (in thousands) were as follows:

	2004		2003
Audit fees	$	1,723	$	404
Audit-related fees(1)	92		998
Tax fees(2)	—		860
All other fees(3)	—		1

Total accounting fees and services	$	1,815	$	2,263

(1) Audit related fees include fees for reviews of registration statements and issuances of consents, reviews of private placement offering documents, benefit plan audits, issuance of letter to underwriters, due diligence pertaining to potential business acquisitions and a review of risk management policies and procedures.

(2) Tax fees include fees for tax return preparation and technical tax advice.

(3) All other fees consist of a subscription to an on-line accounting research tool.

Pre-Approval of Audit and Permitted Non-Audit Services. The Audit Committee is responsible for appointing, setting compensation and overseeing the work of the independent public accountants. The Audit Committee established a policy that requires the Partnership to have the Audit Committee pre-approve all audit and permitted non-audit services from the independent public accountants. The Partnership’s management submits request to the Audit Committee for pre-approval of any such allowable services. The Audit Committee considers whether the provision of non-audit services by the independent public accountants is compatible with maintaining the accountants’ independence. The Audit Committee considers each engagement of the independent public accountants on a case-by-case basis. The Audit Committee pre-approved the performance of the services described above.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(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.

2.5 (9)		Asset Purchase and Sale Agreement and addendum, thereto, dated as of July 1, 2004 by and between American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.

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.

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3.6 (13)		Amendment No. 1 to Amended and Restated Limited Partnership Agreement MarkWest Energy Partners, L.P.

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.

4.3 (9)		Unit Purchase Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund as Purchasers.

4.4(11)		Registration Rights Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund.

4.5(11)		Underwriting Agreement dated as of September 15, 2004 by and among the Partnership, the underwriters named therein and the other parties thereto related to the Common Units Offering.

4.6(11)		Purchase Agreement dated October 19, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein.

4.7(11)		Registration Rights Agreement dated October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein.

4.8(11)		Indenture dated as of October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee.

4.9(11)		Form of 6.875% Series A Senior Notes due 2014 with attached notation of Guarantees (incorporated by Reference to Exhibits A and D of Exhibit 4.8 hereto)

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, Royal Bank 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.

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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 Partners, L.P. 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 (8)		Services Agreement dated January 1, 2004 between MarkWest Energy GP, L.L.C. and MarkWest Hydrocarbon, Inc.

10.14(9)		Second Amended and Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.

10.15(9)		First Amendment to the Second Amended and Restated Credit Agreement dated as of August 20, 2004, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent.

10.16(12)		Third Amended and Restated Credit Agreement dated as of October 25, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, N.A., as Syndication Agent, Fortis Capital Corp., as Documentation Agent, U.S. Bank National

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		Association, as Documentation Agent, Societe Generale, as Documentation Agent, and Wachovia Bank, National Association, as Documentation Agent, RBC Capital Markets and J.P. Morgan Securities Inc., as Lead Arrangers and Joint Bookrunners, to the $200,000,000 Senior Credit Facility.

10.17(15)^D		MarkWest Hydrocarbon, Inc. 1997 Severance Plan

10.18(16)^D		Executive Employment Agreement effective November 1, 2003 between Markwest Hydrocarbon, Inc. and Frank Semple.

21.1 (14)		List of subsidiaries

23.1*		Consent of KPMG LP

23.2*		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

31.3*		Chief Financial Officer 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 Chief Financial 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.

(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 10-K filed March 15, 2004.
(9)		Incorporated by reference to the Current Report on form 8-K/A filed September 13, 2004.
(10)		Incorporated by reference to the Current Report on Form 8-K filed September 20, 2004.
(11)		Incorporated by reference to the Current Report on Form 8-K filed October 25, 2004.
(12)		Incorporated by reference to the Current Report on Form 8-K filed October 29, 2004.
(13)		Incorporated by reference to the Current Report on Form 8-K filed January 6, 2005.
(14)		Incorporated by reference to the Registration Statement (No. 333-122945) on Form S-4 filed February 22, 2005.
(15)		Incorporated by reference to the Current Report of MarkWest Hydrocarbon, Inc. on Form 10-Q filed November 13, 1997
(16)		Incorporation by reference to the Current Report of MarkWest Hydrocarbon, Inc. on Form 10-K filed March 30, 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.
D		Identifies each management contract or compensatory plan or arrangement.

(b) The following exhibits are filed as part of this report: See Item 15(a)(2) above.

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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: June 23, 2005	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: June 23, 2005	By:	/S/Frank M. Semple
		Frank M. Semple
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: June 23, 2005	By:	/S/James G. Ivey
		James G. Ivey
		Chief Financial Officer
		(Principal Financial Officer)

Date: June 23, 2005	By:	/S/Ted S. Smith
		Ted S. Smith
		Chief Accounting Officer
		(Principal Accounting Officer)

Date: June 23, 2005	By:	/S/John m. Fox
		John M. Fox
		Chairman of the Board and Director

Date: June 23, 2005	By:	/S/Keith E. Bailey
		Keith E. Bailey
		Director

Date: June 23, 2005	By:	/S/Charles K. Dempster
		Charles K. Dempster
		Director

Date: June 23, 2005	By:	/S/William A. Kellstrom
		William A. Kellstrom
		Director

Date: June 23, 2005	By:	/S/Donald C. Heppermann
		Donald C Heppermann
		Director

Date: June 23, 2005	By:	/S/William P. Nicoletti
		William P. Nicoletti
		Director

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